ITEM 1. BUSINESS
A. GENERAL
Howell Corporation and its subsidiaries ("Company") are engaged in the exploration, production, acquisition and development of oil and gas properties. These operations are conducted in the United States. A description of the Company's principal business segment and the market in which it operates 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.
RECENT EVENTS
On January 4, 1999, the Company sold its right to participate in the future earnings of Specified Fuels & Chemicals, Inc. ("SFC") for $2.0 million. SFC acquired the Company's research and reference fuel business in July 1997.
On January 29, 1999, the Company sold its interest in the LaBarge field for $15.8 million.
On March 16, 1999, the Company received a refund of $5.7 million for Federal taxes paid in prior years.
On March 19, 1999, the Company signed an agreement to sell its interest in the Pitchfork and Grass Creek Wyoming fields for $12.4 million.
The cumulative proceeds from these events, totaling $35.9 million, have been or will be used to reduce bank debt. By utilizing this $35.9 million and part of the $5.9 million cash and cash equivalents available at December 31, 1998, the Company will be able to pay off Tranche B and reduce Tranche A to approximately $84 million. See Item 2.
ITEM 2. PROPERTIES
A. SUPPLEMENTARY OIL AND GAS PRODUCING INFORMATION
RECENT EVENTS
The proposed sale of the Pitchfork and Grass Creek, Wyoming fields and the completed sale of LaBarge, Wyoming fields for a total of $28.2 million represent 7.0 million barrels of oil equivalent ("MMBOE") out of the 43.1 MMBOE of the Company's proved oil and gas reserves at December 31, 1998 and approximately 2.2 MBOE per day of the Company's 11.9 MBOE 1998 daily production. These transactions also represent 460 gross and 135 net oil wells, 21 gross and 9 net gas wells, 10,409 gross and 2,508 net developed acres, and 320 gross and 320 net undeveloped acres.
The oil and gas producing activities of the Company are summarized below. Substantially all of the Company's producing properties are subject to certain restrictions under the Company's credit facility. See Note 6 of Notes to Consolidated Financial Statements.
OIL AND GAS WELLS
As of December 31, 1998, the Company owned interests in productive oil and gas wells (including producing wells and wells capable of production) as follows:
- ----------------- (1) One or more completions in the same well are counted as one well.
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, except for the reserves purchased from Amoco, at December 31, 1998, 1997, and 1996, were reviewed by independent petroleum consultants, H. J. Gruy and Associates, Inc. The December 31, 1998 and 1997 reserves, associated with the properties acquired from Amoco, were reviewed by independent petroleum consultants, Ryder Scott & Associates. The estimates for 1995 were reviewed 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.
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
Total proved reserves at year-end 1998 were 43,072 MBOE compared to 56,109 MBOE at year-end 1997. The change was related almost entirely to downward revisions associated with lower oil and gas prices. The price sensitivity of the Company's reserve base is illustrated by the fact that if year-end 1998 reserves were calculated using year-end 1997 pricing, total proved reserves would have remained basically unchanged at 1997 reserve levels.
Proved oil reserves at December 31, 1998, include 1.4 million barrels of natural gas liquids ("NGL").
In addition to the oil and gas reserves shown above, the Company, through its participation in the LaBarge Project in southwestern Wyoming, had proved carbon dioxide reserves of 57,140 MMCF and proved helium reserves of 2,570 MMCF at December 31, 1998. The LaBarge Project was sold in January 1999.
OIL AND GAS LEASEHOLDS
The following table sets forth the Company's ownership interest in leaseholds as of December 31, 1998. 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.
(1) Acres spaced or assignable to productive wells.
DRILLING ACTIVITY
The following table shows the Company's gross and net productive and dry exploratory and development wells drilled in the United States:
The table above reflects only the drilling activity in which the Company had a working interest participation. In addition, in 1998, 1997 and 1996, 5, 24 and 22 gross productive wells, respectively, were drilled on the Company's fee mineral interest acreage, which was sold in December 1998.
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:
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:
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:
In 1998, 1997 and 1996, $18,123,000, $57,000 and $8,000 of costs of unproved fee mineral interests, respectively, were transferred to the full-cost pool, representing the costs of fee mineral interests that were drilled and evaluated during the periods. The 1998 amount also represents the sale of the fee mineral interests on December 17, 1998. These transfers of costs are not reflected in the table above. See Note 3 of Notes to the Consolidated Financial Statement.
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 fee mineral interests which were sold in December 1998.
Included in the 1998, 1997 and 1996, amounts above are $1,314,000, $2,005,000, and $2,301,000 of revenues and $121,000, $174,000, and $181,000 of production costs, respectively, from the production of the Company's fee mineral interests which were sold in December 1998.
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 1998 and 1997. 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.
The standardized measure is not intended to represent the market value of reserves and, in view of the uncertainties involved in the reserve estimation process, including the instability of energy markets as evidenced by recent declines in both natural gas and crude oil prices, the reserves may be subject to material future revisions.
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS. The table below presents a reconciliation of the aggregate change in standardized measure of discounted future net cash flows:
The Company's oil and gas exploration and production activities are conducted entirely within the United States by HPC and are concentrated in Wyoming and along the Gulf Coast, both onshore and offshore. At December 31, 1998, the Company's estimated proved reserves were 29.9 MMBO and plant liquids and 78.8 BCF of gas. The Company's major producing properties include Salt Creek, Elk Basin, North Frisco City, Main Pass 64, Grass Creek and LaBarge fields. These six major fields represent 36.0 MMBOE, or 84% of the Company's total proved reserves. 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.
DESCRIPTION OF SIGNIFICANT PROPERTIES
SALT CREEK. The Company owns and operates the Salt Creek Field in the Powder River Basin in Natrona County, Wyoming. The Company's working interest varies from 65% to 100% in this multi-pay field. The field underwent primary development beginning in 1908. In the 1960's a waterflood was installed in the "Light Oil Unit" ("LOU") which is unitized from the surface to the base of the Sundance 3 formation. There are currently 655 producing wells and 588 injection wells located in the LOU on a flood pattern of approximately five acre well spacing. As of December 31, 1998, the field was producing a net of approximately 3,050 barrels per day of sweet crude oil, 275 barrels per day of sour crude and 50 barrels per day of NGLs.
The most prolific producing formation in the LOU is the Wall Creek 2 at a depth of 1,500 feet. It has produced approximately 386 MMBO from an original estimated 950 MMBO in place. In addition, the field has produced another 269 MMBO from multiple horizons varying in depth down to 4,000 feet. The Company believes that the application of horizontal drilling to target unswept intervals within several of the reservoirs may have positive production and reserve potential and plans to implement a pilot program in the future to test the application. In addition, the potential for enhanced oil recovery through CO2 flooding is under consideration for the Wall Creek 1 and Wall Creek 2 formations. Another opportunity exists in the shallow shale formations that exist above the Wall Creek 1. The shale was developed in the 1920s and produced over 2 MMBO in the LOU. The Company believes the oil resided in the extensive vertical fractures and fault systems prevalent in the shale and the reserves were not completely depleted in all areas of the field. The Company is investigating the application of horizontal drilling to connect these fracture systems and faults to a producing wellbore.
ELK BASIN. The Company owns and operates the Elk Basin field, located in the Bighorn Basin in Park County, Wyoming and Carbon County, Montana. The productive horizons range in depth from 1,700 feet to 6,000 feet, with the majority of the production coming from the Embar-Tensleep and the Madison formations. As of December 31, 1998, the field was producing a net of 1,532 barrels per day of oil and 226 barrels per day of NGLs from 215 producing wells.
The Embar-Tensleep reservoir was an inert gas injection pressure maintenance project until injection into the gas cap was discontinued in the 1970's. The company successfully re-established the inert gas injection to increase reservoir pressure in 1998, which is anticipated to have a positive impact on future production rates. In addition, the Company plans to supplement this gas cap injection with horizontal and vertical producing wells located in the oil rim on the edge of the structure, which could improve the sweep efficiency and ultimate recovery. The shallow Frontier formation, at a depth of 1,700 feet, holds a significant number of potential low cost drilling opportunities to extend the production in this field down-structure to the lowest known oil-water contact. Since 1986, 32 Frontier wells have been successfully drilled or recompleted within the Frontier Unit. These wells cost approximately $75,000 each, typically produce at rates of 30 barrels per day of oil and have cumulative recoveries up to 60 thousand barrels each. The Company has identified numerous potential drilling locations within the unit and outside the unit on Company leasehold. The prolific Madison carbonate, at a depth of 5,000', has the potential for horizontal drilling due to its heterogeneous nature. In addition, this waterflooded reservoir has the potential to downspace the 72 producers from the current 40 acres per well to 20 acres per well based on the successful infill drilling program over the last 10 years.
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. In 1989, the Company unitized portions of Main Pass blocks 64 and 65, covering the main pay sand (the "7,300' Sand Unit") and implemented a waterflood project to repressure the 7,300' Sand Unit. Through exploitation, additional acquisitions and field unitization, the Company currently has a working interest which averages approximately 80% in 24 gross wells, including 5 injection wells. Gross cumulative production from the 7,300' Sand Unit over almost 17 years has totaled 11.3 MMBO and 26.6 BCF of natural gas. As of December 31, 1998, daily net production was approximately 706 barrels of oil. In 1998, after an internal comprehensive reservoir study indicated that the waterflood pushed the oil column into the original gas cap, the Company successfully completed a sidetrack operation to confirm and exploit these previously unrecoverable attic oil reserves. As a result of the drilling activity, the Company added net reserves of 1.8 MMBOE and has identified an additional 7 recompletions in the 7,300' Sand Unit.
NORTH FRISCO CITY. The North Frisco City field, located in Monroe County, Alabama, was discovered in March 1991. Production is predominantly from the Frisco City sand member of the Haynesville formation at a depth of about 12,000 feet. Based on seismic data, ten successful development wells were completed from 1992 though 1994. In 1994, the field was unitized. The Company currently has a 24.1% working interest in nine gross producing wells in the unit. As of December 31, 1998, daily net production from this field was 690 barrels of oil, 173 barrels of natural gas liquids and 765 thousand cubic feet of natural gas. The Company also owns a royalty interest in this field.
GRASS CREEK. The Grass Creek Unit, located in the Bighorn Basin in Hot Springs County, Wyoming, is operated by Marathon Oil Company. Oil was discovered in the Frontier formation in 1914. The Company's working interest within the Grass Creek field differs by horizon, varying from 13% in the Curtis to 37.65% in the Darwin. The company owns a 31% working interest in the primary horizons, the Phosphoria and Tensleep, which are mature waterfloods. Current net production is approximately 965 barrels of oil per day. In February 1996, a 3-D seismic survey was acquired over the field. Based upon that data, the Company has identified numerous potential drilling opportunities. In 1998, the operator successfully completed three deepenings and one drill well in the Phosphoria-Tensleep, confirming these opportunities. Grass Creek field is also a candidate for enhanced oil recovery using CO2. On March 19, 1999, the Company entered into an agreement to sell its interest in Grass Creek and other properties for $12.4 million.
LABARGE PROJECT. The LaBarge Project, operated by Exxon Company USA, is located in southwestern Wyoming. The Company owns a 4.8% working interest in the Fogarty Creek Unit. The Company has an interest in 12 gross wells producing from depths between 14,500 feet to 17,000 feet in the Fogarty Creek Unit. 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 following table 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. On January 29, 1999, the Company sold all of its right, title, and interest in and to the LaBarge Project for $15.75 million.
- -----------------
(1) Because of a lack of market, approximately 80%, 78% and 81% of the volume produced in 1998, 1997 and 1996, respectively, was vented and not sold. Amounts included in the table reflect only volumes sold.
B. OTHER PROPERTIES
In addition to the oil and gas properties described above, the Company and its subsidiaries lease approximately 52,900 square feet for use as corporate and administrative offices in Houston, Texas.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
The Company, through its subsidiaries, is involved from time to time in various claims, lawsuits and administrative proceedings incidental to its business. In the opinion of management, the ultimate liability thereunder, if any, will not have a materially adverse effect on the financial condition or results of operations of the Company. See Note 9 of Notes to Consolidated Financial Statements.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
Howell Corporation common stock is traded on the New York Stock Exchange. Symbol: HWL
Approximate number of equity shareholders as of December 31, 1998: 1,800.
Due to the current market conditions, the Company's Board of Directors will evaluate on a quarterly basis whether or not to pay either common or preferred dividends. No assurance can be given, however, as to the timing and amount of any future dividends which necessarily will depend on the earnings and financial needs of the Company, legal restraints, and other considerations that the Company's Board of Directors deems relevant. The ability of the Company to pay dividends on its common stock is currently subject to certain restrictions contained in its bank loan agreement. See Item 7, "Management's Discussion and Analysis of Financial Condition - Liquidity and Capital Resources."
In addition, the Company has 690,000 shares of convertible preferred stock outstanding. These shares were issued in April 1993. The $3.50 convertible preferred stock is traded on the National Association of Securities Dealers, Inc. Automated Quotation System ("NASDAQ") under the symbol HWLLP. See Note 7 of Notes to Consolidated Financial Statements.
ITEM 6.
ITEM 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.
- ----------------- (1) See Note 3 of Notes to Consolidated Financial Statements regarding the 1997 sale of the technical fuels and chemical processing operations. (2) See Notes 3 and 5 of Notes to Consolidated Financial Statements regarding the 1996 purchase and sale, contribution and conveyance of crude oil gathering and marketing, pipeline, and transportation operations. (3) Includes $102,167 (pre-tax) charge for impairment of oil & gas properties in 1998. Summarized below are the Company's quarterly financial data for 1998 and 1997 continuing operations.
Summarized below are the Company's quarterly financial data for 1998 and 1997 continuing operations.
- ----------- (1) Includes charge for impairment of oil & gas properties (pre-tax) of $66,118 in the first quarter and $36,049 in the fourth quarter.
(2) See Note 3 of Notes to Consolidated Financial Statements regarding the 1997 sale of the technical fuels and chemical fuels processing operations.
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 CONTINUING OPERATIONS
The Company's only principal business segment is oil and gas production. Crude oil marketing and transportation was also a principal segment until its sale on December 3, 1996. Results of continuing operations by segment for the three years ended December 31, 1998, are discussed below. The table below for each segment's revenues does not reflect the elimination of intercompany revenues. See Notes 3 and 8 of Notes to Consolidated Financial Statements.
REVENUES
During 1998 revenues for the oil and gas segment increased 48% when compared to the year ended 1997 due to the Amoco property Acquisition, partially offset by a 35% decrease in average oil prices and a 20% decrease in average natural gas prices. The increase in revenues were partially offset by the Company's continued reduction of its gas marketing activities.
Revenues for 1997 increased primarily due to an increase in the natural gas price of 13% to $2.33 per thousand cubic feet. Minerals leasing activity steadily increased over the last three years. These revenue increases were partially offset by a decrease in gas marketing revenue due to reduced activity.
Revenues from the sales of the La Barge other products are attributable to sales of carbon dioxide, helium and sulfur. Increased production levels of helium and carbon dioxide in 1997 relative to 1996 were partially offset by reduced product sales prices. Sulfur revenues were insignificant.
OPERATING PROFIT
Operating profits for the oil and gas segment decreased $98.9 million primarily due to pre-tax non-cash impairments of $102.2 million. On an after-tax basis, the impairments amounted to $67.4 million or a loss of $12.32 per common share. Excluding the impairments, the segment's operating profits increased 39% when compared to the year ended 1997. The Acquisition also resulted in increased lease operating expense and production and severance tax expense of $13.3 million and $2.8 million, respectively. A reduction of workover expense of $1.1 million helped to offset these increased costs. The Company's general and administrative expenses decreased $1.6 million due to increased administrative credits on some of the properties acquired in late 1997. Also offsetting these costs was a decrease in depreciation, depletion and amortization, excluding the impairments, per equivalent barrel of production from $5.18 in 1997 to $2.68 in 1998 due to the Acquisition.
In 1997, the operating profit of this segment decreased $0.3 million when compared to 1996. The decrease was primarily due to increased workover expenses and LaBarge expenses. Workover costs increased from $1.1 million in 1996 to $1.6 million in 1997 primarily due to platform refurbishment on Main Pass 64.
Howell's average realized oil price, including hedging, for 1998 was $11.37 per barrel. The crude oil price decline that began in the latter part of the fourth quarter 1997 continued into early 1999.
Lower oil and gas prices may continue for the near term. During such period, the Company's cash flow and funds available for reinvestment are reduced. Accordingly, Howell is currently focusing its 1999 capital investments on obligatory projects and pilot programs designed to build an inventory of projects for long-term
shareholder value. In the interim, should lower product prices be sustained, Howell may record a non-cash ceiling test impairment at the end of the first quarter 1999 to the value of its proved oil and gas properties as determined by Securities and Exchange Commission guidelines.
CRUDE OIL MARKETING & TRANSPORTATION
There were no revenues or operating profits during 1998 or 1997 in the crude oil marketing and transportation segment as a result of the sale of the Business. Revenues and operating profits for 1996 were $666.1 million and $9.6 million, respectively. However, the Company did retain a direct and indirect interest in Genesis. As a result of the Company's interest, the Company recognized net earnings in Genesis of $0.6 million during 1998 and $0.9 million during 1997. See Note 5 of Notes to Consolidated Financial Statements.
Effective December 3, 1996, the Company's sale of the assets and liabilities associated with crude oil marketing and transportation segment resulted in a pre-tax gain of $13.8 million recognized in other income/expense.
INTEREST EXPENSE
During 1998, interest expense increased $9.3 million as a result of the increased short-term and long-term debt ("Debt") necessary for the Acquisition. Debt averaged $136.8 million during 1998. As a result of the sale of the fee mineral interests during December 1998, the Company was able to reduce this Debt by $13.0 million. In early 1999, the Company was able to further reduce Debt by $17.8 million as a result of the sale of the LaBarge properties and the buyout by SFC of its remaining excess EBITDA payments.
Interest expense in 1997 decreased $5.3 million below the 1996 level. The primary reason for this decrease was repayment of the term loan and revolving credit facilities out of funds received from: (i) the December 3, 1996 sale of the Business to Genesis; (ii) the December 31, 1996 sale of 100% of the outstanding common stock of Howell Transportation Services, Inc. to Lodestar Logistics, Inc.; and (iii) the July 31, 1997, sale of substantially all of the assets of the Company's research and reference fuels and custom chemical manufacturing business to SFC. Debt averaged $23.9 million for the first half of 1997. The proceeds of the sale to SFC were used to reduce debt to an average of $11.8 million for the last half of the year before the Acquisition and an average of $21.0 million for the last half of the year including the Acquisition. The average debt during 1996 was $90.5 million. The purchase of the Acqusition, increased debt to $137.0 million at year-end 1997. See Notes 3, 5 and 6 of Notes to Consolidated Financial Statements.
PROVISION FOR INCOME TAXES
The Company's approximate effective tax rate of 35% reflects the statutory federal rate and state income taxes less the effect of statutory depletion deductions in excess of cost basis.
RESULTS FROM DISCONTINUED OPERATIONS
TECHNICAL FUELS AND CHEMICAL PROCESSING
On July 31, 1997, Seller completed the sale of and disposition of substantially all of the assets of its research and reference fuels and custom chemical manufacturing business to SFC.
As a result of the sale, the Company was entitled to receive an additional payment equal to 55% of the amount by which Buyer's "EBITDA" for each twelve month period ending June 30, 1998, 1999, 2000, 2001 and 2002 exceeds the "Minimum EBITDA" (as defined in the agreement). The Minimum EBITDA amounts for those years were $5.0 million, $5.175 million, $5.35 million, $5.525 million and 5.7 million, respectively, SFC was entitled to repurchase Seller's rights to these additional payments at any time after June 30, 1998, generally by paying to Seller an amount equal to the greater (a) the product obtained by multiplying the EBITDA payment amount for the immediately preceding twelve-month period by the number of twelve-month periods remaining, or (b) an amount fixed by the agreement, which was initially set at $5.7 million if the repurchase occurred during the twelve-month period ending on June 30, 1999, and which declines for each twelve-month period thereafter to $1.2 million if the repurchase occurred during the twelve-month period ending June 30, 2002.
During August 1998, the Company received the first excess EBITDA payment of $0.7 million pre-tax. On January 4, 1999, SFC and Seller agreed that the amount fixed by the Agreement was not reasonable in light of the current performance; therefore, Seller agreed to reduce the excess EBITDA payment to $2.0 million which SFC agreed to purchase.
The results of the technical fuels and chemical processing business have been classified as discontinued operations in the accompanying consolidated financial statements. Discontinued operations also includes the allocation of interest expense (based on a ratio of net assets of discontinued operations to total consolidated net assets). Allocated amounts are as follows:
LIQUIDITY AND CAPITAL RESOURCES
RECENT EVENTS
On January 4, 1999, the Company sold its right to participate in the future earnings of SFC for $2.0 million. SFC acquired the Company's research and reference fuel business in July 1997.
On January 29, 1999, the Company sold its interest in the LaBarge field for $15.8 million.
On March 16, 1999, the Company received a refund of $5.7 million for Federal taxes paid in prior years.
On March 19, 1999, the Company signed an agreement to sell its interest in the Pitchfork and Grass Creek, Wyoming fields for $12.4 million.
The cumulative proceeds from these events, totaling $35.9 million, have been or will be used to reduce bank debt. By utilizing this $35.9 million and part of the $5.9 million cash and cash equivalents available at December 31, 1998, the Company will be able to pay off Tranche B and reduce Tranche A to approximately $84 million. See Item 2. "Properties" and Note 6 of Notes to Consolidated Financial Statements.
CREDIT FACILITY
The Company amended and restated the December 17, 1997 Credit Agreement effective on December 1, 1998 ("Credit Facility"). The Credit Facility is comprised of two tranches. Tranche A is a revolving credit facility with a termination date no later than December 15, 2002. The Borrowing Base was redetermined to $110 million prior to the 1998 sale of the Company's fee mineral interest, and to $105 million after the sale. Tranche B is a term loan with an amended borrowing availability of $30 million. The Company is required to pay commitment fees on the unused portion of Tranche A at a rate of 0.375% per annum while Tranche B is outstanding. After Tranche B has been repaid, the commitment fee will be based upon the Borrowing Base Utilization at a rate of 0.25% per annum if 25% or less of the Borrowing Base is used, 0.30% if more than 25% and less than or equal to 75% is used, and 0.375% if more than 75% is used.
Outstanding amounts under the Credit Facility bear interest, at the Company's option, at either the Eurodollar Loan ("Libor") rate per annum, or the Base Rate (prime), plus the Applicable Margin. The Applicable Margin is determined by the Borrowing Base Utilization Percentage. It ranges from as low as Libor plus 1.50% or the Base Rate plus 0.00% if 25% or less of the Borrowing Base is used, to as high as Libor plus 2.50% or the Base Rate plus 0.75% if greater than 90% of the Borrowing Base is used.
The Credit Facility is secured by mortgages on substantially all of the Company's oil and gas properties. The Credit Facility contains certain other affirmative and negative covenants, including limitations on the ability of the Company to incur additional debt, sell assets, merge or consolidate with other persons, pay dividends on its capital in excess of historical levels, and a prohibition on change of control or management. In addition, the Credit Facility requires the Company to maintain a ratio of current assets plus Tranche A borrowing capacity to current liabilities, excluding current maturities of long-term debt, of at least 1.0 to 1.0 and an interest coverage ratio of not less than 1.5 to 1.0 on a rolling four quarter basis through June 30, 1999, and beginning in the third quarter of 1999 and thereafter, of not less than 1.5 to 1.0 at the end of any fiscal quarter.
On December 17, 1998, the Company was able to reduce the outstanding balance of Tranche A by $5 million and Tranche B by $8 million as a result of the sale of its fee mineral interests.
As of December 31, 1998, the outstanding amounts under Tranche A bore interest at 8.0625% per annum on $102 million and under Tranche B bore interest at 10.5625% per annum on $22 million.
OTHER
At December 31, 1998, the Company had negative working capital of $11.4 million, including the $22.0 million Tranche B loan facility referred to above. In 1998, cash provided from operating activities was $19.6 million.
In 1993, the Company issued 690,000 shares of $3.50 convertible preferred stock. The net proceeds from the sale were $32.9 million. Dividends on the convertible preferred stock are to be paid quarterly. Such dividends accrue and are cumulative. The Company has paid all dividends on time. Due to the current market conditions, the Company's Board of Directors will evaluate on a quarterly basis whether or not to pay either common or preferred dividends.
The Company currently anticipates spending approximately $0.1 million during fiscal years 1999 and 2000 at various facilities for capital and operating costs associated with ongoing environmental compliance and may continue to have expenditures in connection with environmental matters beyond fiscal year 1999. The Company spent $0.05 million on such expenditures in 1998. See Note 10 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 and capital expenditure requirements. At December 31, 1998, the Company had cash and cash equivalents of $5.9 million and $3 million available to it under the Credit Facility. A decline in the value of the Company's proved reserves could result in the bank reducing the Borrowing Base, thereby causing mandatory payments under the Credit Facility. While the Company does not expect this to happen in 1999, such payments would adversely affect the Company's ability to carry out its capital expenditure program and could cause the Company to recapitalize its debt through the public or private placement of securities. See "Recent Events".
QUALITATIVE & QUANTITATIVE MATTERS
In order to guarantee the Company a specific minimum sales price for its crude oil, the Company purchased a put option and sold a call option covering approximately 3,300 barrels per day of crude oil production for an 18-month period beginning March 1, 1995. The option strike prices were based on the average price of crude oil on the organized exchange with monthly settlement. The strike prices were $17 per barrel for the put option and $20 per barrel for the call option.
During 1996, the monthly average sales price of crude oil on the organized exchange was between $17 and $20 per barrel for January and February; therefore, no options were exercised during the two months. The monthly average sales price for the remainder of the March 1, 1995 call option period, March 1996 through August 1996, was above the $20 ceiling. This resulted in collar payments of $0.9 million, excluding the premium amortization and were recorded as a reduction of revenue.
Upon the expiration of the 18-month option period, the Company purchased a $16.50 per barrel put option and sold a $21.10 per barrel call option covering 100,000 barrels of oil per month for a six-month period ending February 28, 1997. For September through December 1996, the monthly average sales price exceeded the ceiling price. This resulted in collar payments for the four month period of $1.3 million which were recorded as a reduction of revenue.
In 1997, the monthly average price of crude oil on the organized exchange exceeded the strike price for the call option during January and February, the final two months of the options. The payments required in 1997 under the call option totaled $0.5 million and were recorded as a reduction of revenue.
In 1998, the Company purchased a put option and sold a call option covering 4,800 barrels of oil per day for a nine-month period ended December 31, 1998. The strike prices were $16.00 per barrel for the put option and $19.25 per barrel for the call option. There was no premium associated with these options. During 1998, the Company received $2.8 million as a result of the options. These amounts were recorded as additional revenues. Without the options the average price per barrel of oil for the year ended December 31, 1998, would have been reduced from $11.37 to $10.55.
ACCOUNTING PRONOUNCEMENTS
In June 1997, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive Income", ("SFAS 130"). SFAS 130 is effective for periods beginning after December 15, 1997. SFAS 130 establishes standards for reporting and displaying comprehensive income and its components. The purpose of reporting comprehensive income is to report a measure of all changes in equity of an enterprise that result from recognized transactions and other economic events of the period other than transactions with owners in their capacity as owners. In 1998, the Company adopted SFAS 130 and as of December 31, 1998, there were no adjustments to net income in deriving comprehensive income.
In June 1997, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 131, "Disclosures About Segments of an Enterprise and Related Information," ("SFAS 131"). SFAS 131 establishes standards for the way that public business enterprises report information about operating segments. SFAS 131 is effective for periods beginning after December 15, 1997. The Company has adopted SFAS 131. See Note 8 of Notes to the Consolidated Financial Statements.
In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities," ("SFAS 133"). SFAS 133 establishes accounting and reporting standards for derivative instruments and hedging activities that require an entity to recognize all derivatives as an asset or liability measured at its fair value. Depending on the intended use of the derivative, changes in its fair value will be reported in the period of change as either a component of earnings or a component of other comprehensive income. SFAS 133 is effective for all fiscal quarters of fiscal years beginning after June 15, 1999. Earlier application of SFAS 133 is encouraged, but not prior to the beginning of any fiscal quarter that began after issuance of the Statement. Retroactive application to periods prior to adoption is not allowed. The Company has not quantified the impact of adoption of SFAS 133 on its financial statements.
YEAR 2000 DATE CONVERSION
The Company has a plan in place that addresses the year 2000 ("Y2K") conversion issue. The first step in the plan was to evaluate all computer systems used in its operations. This includes accounting and financial systems, field and production systems, and other field or office devices that may not be Y2K compliant. This was followed by a determination of what remedial action is necessary and initiation of that remedy. The Company's plan to correct its in-house systems involved installation of new software and hardware. The Company installed a new accounting package during the fourth quarter of 1998 which is Y2K compliant. The Company has begun corrective action on major field systems and anticipates completion during the third quarter of 1999.
The next step was to determine the Y2K status of relevant outside suppliers and vendors. While the Company cannot control the Y2K corrective action of third parties, it has begun the process of identifying and contacting its critical suppliers and vendors. Based on their status, the Company will develop contingency plans. These should be completed by the third quarter of 1999.
Based on preliminary estimates, the cost of implementing this plan is approximately $300,000. It is not certain that this estimate is correct or that Year 2000 compliance can be achieved. The Company does not expect a significant disruption in its operations, but actual results could differ greatly from these expectations. Some areas that could cause differences to occur are the availability of personnel trained in this area, the ability to identify and correct all relevant computer code and non-compliant embedded systems and the degree of interdependence with third party suppliers and purchasers. Other areas outside the Company's control such as problems in the utility, banking, or transportation systems could have a material disruptive effect on the Company's ability to produce and deliver oil and gas, receive delivery of materials and supplies, or disburse or receive funds.
One example of a serious Y2K problem would be the shut down of a field which is on automated controls and/or a monitoring system. As disclosed above, the Company has examined such controls and systems in all of its major fields and is taking corrective action, as appropriate. Nevertheless, the Company intends to prepare a Y2K contingency plan which will address potential risks in the field, and possible solutions, including manual intervention or equipment replacement. The Company is unable to anticipate every potential problem and determine a contingency for every possible Y2K risk. Should essential services such as electricity be affected adversely, or if other Y2K related problems limit or restrict production from one of the Company's major fields, it could have a material adverse affect on the Company.
FORWARD-LOOKING STATEMENTS
Statements contained in this Report and other materials filed or to be filed by the Company with the Securities and Exchange Commission (as well as information included in oral or other written statements made or to be made by the Company or its representatives) that are forward-looking in nature are intended to be "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, relating to matters such as anticipated operating and financial performances, business prospects, developments and results of the company. Actual performance, prospects, developments and results may differ materially from any or all anticipated results due to economic conditions and other risks, uncertainties and circumstances partly or totally outside the control of the Company, including rates of inflation, oil and natural gas prices, uncertainty of reserve estimates, and changes in the level and timing of future costs and expenses related to drilling and operating activities.
Words such as "anticipated", "expect", "project", and similar expressions are intended to identify forward-looking statements.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
See discussion under Liquidity and Capital Resources.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The response to this item is submitted as a separate section.
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 1999 Annual Shareholders' Meeting, is incorporated herein by reference. Regarding executive officers, information is set forth below.
The executive officers are elected annually.
Mr. Donald W. Clayton was elected Chairman and Chief Executive Officer in May 1997. From 1993 to 1997, he was co-owner and President of Voyager Energy Corp. Formerly served as President and Director of Burlington Resources, Inc.; and President and Chief Executive Officer of Meridian Oil, Inc. Prior to that, he was a senior executive with Superior Oil Company.
Mr. Richard K. Hebert was elected President and Chief Operating Officer in May 1997. From 1993 to 1997, he was co-owner of Voyager Energy Corp. Formerly served as Executive Vice President and Chief Operating Officer of Meridian Oil, Inc., now Burlington Resources, Inc. Prior to that, he served in various engineering and management positions with Mobil Oil Corporation, Superior Oil Company and Amoco Production Company.
Mr. J. Richard Lisenby was elected Vice President and Chief Financial Officer of the Company in December 1996. Prior to that, Mr. Lisenby served as Treasurer of Columbia Gas Development, a subsidiary of Columbia Gas System.
Mr. Robert T. Moffett was elected Secretary in October 1996 and Vice President and General Counsel of the Company in January 1994. He had served as General Counsel of the Company since September 1992. Prior to that time, Mr. Moffett was a general partner in the firm of Moffett & Brewster.
Mr. John E. Brewster, Jr. was elected Vice President, Corporate Development & Planning in May 1996. Prior to that time he was a consultant for Voyager Energy Corp. He has held senior management positions with Santa Fe Minerals, Inc., Odyssey Energy, Inc., and Trafalgar House Oil & Gas Inc.; and was a general partner in the firm of Moffett & Brewster.
Regarding delinquent filers pursuant to Item 405 of Regulation S-K, the information appearing under the caption "Compliance with Section 16(a) of the Securities Exchange Act of 1934" set forth in the Company's definitive proxy statement, to be filed within 120 days after the close of the fiscal year in connection with the 1999 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 1999 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 1999 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 1999 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) Exhibits - None
(b). Reports on Form 8-K.
A report on Form 8-K was filed December 29, 1998 announcing the sale of mineral estates and royalty interests located in the states of Alabama, Mississippi and Louisiana.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
HOWELL CORPORATION (Registrant)
By /s/ J. RICHARD LISENBY ------------------------------------ J. Richard Lisenby Vice President and Chief Financial Officer Principal Financial and Accounting Officer
Date: March 22, 1999
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/ DONALD W. CLAYTON Officer and Director March 22, 1999 - ----------------------------------- Donald W. Clayton Chairman and Chief Executive Officer
Principal Executive /s/ RICHARD K. HEBERT Officer and Director March 22, 1999 - ----------------------------------- Richard K. Hebert President and Chief Operating Officer
/s/ PAUL N. HOWELL Director March 22, 1999 - ----------------------------------- Paul N. Howell
/s/ JACK T. TROTTER Director March 22, 1999 - ----------------------------------- Jack T. Trotter
/s/ WALTER M. MISCHER, SR. Director March 22, 1999 - ----------------------------------- Walter M. Mischer, Sr.
HOWELL CORPORATION AND SUBSIDIARIES
FORM 10-K
ITEMS 8, 14(a) (1) and (2)
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
The following consolidated financial statements of the registrant and its subsidiaries required to be included in Items 8 and 14(a)(1) are listed below:
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, 1998 and 1997, and the related consolidated statements of operations, changes in shareholders' equity, and cash flows for each of the three years in the period ended December 31, 1998. 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, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998 in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Houston, Texas March 22, 1999
HOWELL CORPORATION AND SUBSIDIARIES Consolidated Balance Sheets
See accompanying Notes to Consolidated Financial Statements.
HOWELL CORPORATION AND SUBSIDIARIES Consolidated Statements of Operations
HOWELL CORPORATION AND SUBSIDIARIES Consolidated Statement of Changes in Shareholders' Equity
HOWELL CORPORATION AND SUBSIDIARIES Consolidated Statements of Cash Flows
HOWELL CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. RECENT EVENTS
On January 4, 1999, Howell Corporation and its subsidiaries (the "Company") sold its right to participate in the future earnings of Specified Fuels & Chemicals ("SFC") for $2.0 million. SFC acquired the Company's research and reference fuel business in July 1997.
On January 29, 1999, the Company sold it interest in the LaBarge field for $15.8 million.
On March 16, 1999, the Company received a refund of $5.7 million for Federal taxes paid in prior years.
On March 19, 1999, the Company signed an agreement to sell its interest in the Pitchfork and Grass Creek, Wyoming fields for $12.4 million.
The cumulative proceeds from these events, totaling $35.9 million, have been or will be used to reduce bank debt. By utilizing this $35.9 million and part of the $5.9 million cash and cash equivalents available at December 31, 1998, the Company will be able to pay off Tranche B and reduce Tranche A to approximately $84 million. See Note 6.
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company. The Company accounts for its investment in less than 50% owned investees using the equity method of accounting when it has the ability to exercise significant influence over operating and financial policies of the investee. All significant intercompany accounts and transactions have been eliminated.
NATURE OF OPERATIONS
The Company is primarily engaged in the exploration, production, acquisition and development of oil and gas properties. These operations are conducted in the United States. The Company has also been involved in technical fuels and chemical processing and crude oil marketing and transportation, but has divested itself of these businesses. The Company has retained an equity investment in a crude oil marketing and transportation company. See Notes 3, 5, and 8.
PROPERTY, DEPRECIATION, DEPLETION AND AMORTIZATION
The Company follows the full-cost method of accounting for its oil and gas exploration and production activities, which are conducted solely in the United States. Consequently, all costs pertaining to the acquisition, exploration and development of oil and gas reserves are capitalized and amortized using the unit-of-production method as the remaining proved oil and gas reserves are produced. The Company's net investment in oil and gas properties is subject to a quarterly ceiling limitation calculation that is based on the present value of future net revenues from estimated production of proved oil and gas reserves valued at current prices. Costs in excess of the ceiling limitation are currently charged to expense. Gains or losses upon the disposition of a property, normally treated as an adjustment to capitalized costs, are recognized currently in the event of a sale of a significant portion (normally in excess of 25%) of oil and gas reserves.
The costs allocated to the unproven properties and fee mineral interests of the Company are excluded from amortization using the full-cost method of accounting described above. These costs are reviewed periodically for impairment. This impairment will generally be based on geographic or geologic data. At the time of any impairment, the related costs will be added to the costs being amortized under the full-cost method of accounting. Due to the perpetual nature of the Company's ownership of the mineral interests, the drilling of a well, whether successful or unsuccessful, may not represent a complete test of all depths of interest. Therefore, at the time that a well is drilled only a portion of the costs allocated to the acreage drilled may be added to the costs being amortized.
Other property and equipment are carried at cost. Depreciation is provided principally using the straight-line method over the estimated useful lives of the assets.
Maintenance and repairs are charged to expense as incurred, while renewals and betterments are capitalized.
INCOME TAXES
The Company utilizes a balance sheet liability approach in the calculation of the deferred tax balance at each financial statement date by applying the provisions of enacted tax laws to measure the deferred tax consequences of the differences in the tax and 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. Deferred tax assets are recognized if it is more likely than not that the future tax benefit will be realized.
EARNINGS PER COMMON SHARE
Basic earnings per common share amounts are calculated using the average number of common shares outstanding during each period. Diluted earnings per share assumes conversion of dilutive convertible preferred stocks and exercise of all stock options having exercise prices less than the average market price of the common stock using the treasury stock method.
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 $10,184,000, $1,347,000 and $7,793,000 in 1998, 1997 and 1996, respectively. In 1998, 1997 and 1996, cash payments for income taxes totaled $261,000, $6,849,000, and $2,974,000, respectively.
DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company estimates that the carrying amount of its cash and cash equivalents and accounts receivable and payable as reflected in its balance sheet approximates fair value.
STOCK BASED COMPENSATION
The intrinsic value method of accounting is used for stock-based employee compensation whereby no compensation expense is recognized when the exercise price of an employee stock option is equal to or greater than the market price of the Company's common stock on the grant date.
ENVIRONMENTAL LIABILITIEs
The Company provides for the estimated costs of environmental contingencies when liabilities are likely to occur and reasonable estimates can be made. In accordance with full cost accounting rules, the Company provides for future environmental clean-up costs associated with oil and gas activities as a component of its depreciation, depletion and amortization expense. Information regarding environmental liabilities can be found in Note 10. Ongoing environmental compliance costs, including maintenance and monitoring costs, are charged to expense as incurred.
DERIVATIVES
In order to mitigate the effects of future price fluctuations, the Company has used a limited program of hedging its crude oil production. Crude oil futures and options contracts are used as the hedging tools. Changes in the market value of the futures transactions are deferred until the gain or loss is recognized on the hedged transactions.
In 1995, the Company purchased a put option and sold a call option covering 3,300 barrels per day of oil production for an 18-month period beginning March 1, 1995. The option strike prices were based on the average price of crude oil on the organized exchange, with monthly settlement. The strike prices were $17 per barrel for the put option and $20 per barrel for the call option. The premiums for the options were amortized over the option period. Upon expiration of the 18-month option period, the Company purchased a put option and sold a call option covering 100,000 barrels of oil per month for a six-month period ended February 28, 1997. The strike
prices were $16.50 per barrel for the put option and $21.10 per barrel for the call option. There was no premium associated with these options.
During 1996, the monthly average price of crude oil on the organized exchange exceeded the strike price for the call option in ten months. The payments required in 1996 under the call options and the premium amortized in 1996 totaled $2.5 million and were recorded as a reduction of revenue. During 1995, the monthly average price of crude oil on the organized exchange was between $17 and $20 per barrel; therefore, none of the options were exercised during this period. Premiums amortized during 1995 totaled $0.4 million and were recorded as a reduction of revenue.
In 1997, the monthly average price of crude oil on the organized exchange exceeded the strike price for the call option during January and February, the final two months of the options. The payments required in 1997 under the call option totaled $0.5 million and were recorded as a reduction of revenue.
In 1998, the Company purchased a put option and sold a call option covering 4,800 barrels of oil per day for a nine-month period ended December 31, 1998. The strike prices were $16.00 per barrel for the put option and $19.25 per barrel for the call option. There was no premium associated with these options. During 1998, the Company received $2.8 million as a result of the options. These amounts were recorded as additional revenues. Without the options the average price per barrel of oil for the year ended December 31, 1998, would have been reduced from $11.37 to $10.55.
Crude oil future contracts and options were also used as a hedging tool in a limited program of hedging crude oil inventories and fixed purchase price commitments. Other costs and expenses related to the crude oil marketing and transportation businesses were reduced by $0.1 million in 1996 from the effects of futures and options.
REVENUE RECOGNITION
The Company recognizes oil and gas revenue from its interests in producing wells as oil and gas is sold from those wells. Oil and gas sold in production operations is not significantly different from the Company's share of production.
The Company utilizes the sales method to account for gas production volume imbalances. Under this method, income is recorded based on the Company's net revenue interest in production taken for delivery. Management does not believe that the Company had any material gas imbalances at December 31, 1998 or 1997.
CONCENTRATION OF RISK
Substantially all of the Company's accounts receivable result from oil and gas sales and joint interest billings to third parties in the oil and gas industry. This concentration of customers and joint owners may impact the Company's overall credit risk in that these entities may be similarly affected by changes in economic and other conditions.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
RECLASSIFICATIONS
Certain reclassifications have been made to the 1997 and 1996 financial presentation to conform with the 1998 presentation. Other revenues and expenses includes all of the revenues, costs and expenses (operating expenses, depreciation, selling, general and administrative expenses) associated with the crude oil gathering and marketing operations, pipeline operations and transportation services.
NOTE 3. ACQUISITIONS & DISPOSITIONS
On December 17, 1998, the Company sold its fee mineral estates and royalty interests comprised of approximately 875,000 acres located in the states of Alabama, Mississippi, and Louisiana for $13.0 million. The
company will retain a 10% net profits interest after payout. The net daily production attributable to these assets is approximately 350 BOE. Proceeds from the sale were used to retire bank debt. See Note 6.
During November 1998, the Company announced the execution of a letter agreement with SFC which purchased the Company's research and reference fuel business on July 31, 1997. As part of the consideration in that sale, the Company was to receive an additional payment equal to 55% of the amount by which SFC's "EBITDA" for each twelve-month period ending June 30, 1998, 1999, 2000, 2001 and 2002 exceeds the "Minimum EBITDA" (as defined in the Agreement). The Minimum EBITDA amounts for those years were $5.0 million, $5.175 million, $5.35 million, $5.525 million and $5.7 million, respectively. The Company received $0.7 million pre-tax under that provision in 1998. On January 4, 1999, SFC and Howell Hydrocarbons & Chemicals, Inc. ("Seller"), a wholly owned subsidiary of the Company, agreed that the amount fixed by the Agreement was not reasonable in light of the current performance; therefore, Seller agreed to reduce the excess EBITDA payment to $2.0 million which SFC agreed to purchase.
Effective May 22, 1998, Howell Petroleum Corporation ("HPC"), a wholly owned subsidiary of Howell Corporation, entered into a Settlement Agreement and Release with Amoco Production Company ("Amoco") and Snyder Oil Corporation ("SOCO") whereby the parties agreed to settle the pending litigation between them styled: SNYDER OIL CORPORATION, PLAINTIFF V. AMOCO PRODUCTION COMPANY AND HOWELL PETROLEUM CORPORATION, DEFENDANTS in the District Court, Ninth Judicial District, Civil Action No. 29861, Fremont County, Wyoming. Under the terms of the settlement, HPC agreed to relinquish its contractual rights to purchase that portion of the Amoco Wyoming package relating to the Beaver Creek Unit and the associated facilities. In addition, Amoco agreed to sell HPC an approximate 31% working interest in the Higgins Unit located in Sweetwater County, Wyoming, and a 1.95% overriding royalty interest covering over 78,000 acres in the Natural Buttes Field located in Uintah County, Utah. The purchase price for these predominately gas properties was $11 million. HPC's in-house petroleum engineers estimate total proved reserves attributable to these properties were 8.1 BCFE. Net daily production from the properties was approximately 1.8 MMCF of natural gas with a projected reserve-to-production index of 12 years. This settlement completed HPC's acquisition of the properties from Amoco. HPC purchased proved reserves of 39.1 MMBOE for $126.4 million which was an acquisition cost of $3.23 per barrel of oil equivalent. The operating results of the assets acquired from Amoco have been included in the Company's Statement of Operations since May 22, 1998. Pro forma information is not required because of materiality.
On December 18, 1997, the Company purchased certain oil and gas producing properties (the "Package") in Wyoming from Amoco Production Company ("Amoco"), a subsidiary of Amoco Corporation, for approximately $115.4 million, subject to purchase price adjustments. The effective date of the Purchase was December 1, 1997. The Package was accounted for using the purchase method of accounting, and accordingly, the purchase price was allocated to the assets acquired based on estimated fair values at the date of acquisition. The operating results of the assets acquired from Amoco have been included in the Company's Statement of Operations since December 18, 1997. The pro forma information shown below assumes that the Purchase occurred at January 1, 1997. Adjustments have been made to reflect changes in the Company's results from revenues and direct operating expenses of the producing properties acquired from Amoco, additional interest expense to reflect the acquisition, depreciation, depletion and amortization based on fair values assigned to the assets acquired, and general and administrative expenses incurred from hiring additional employees. The pro forma financial data are based on assumptions and the actual recording of the Purchase could differ. The unaudited pro forma financial data are not necessarily indicative of financial results that would have occurred had the Acquisition occurred on January 1, 1997, and should not be viewed as indicative of operations in future periods.
The acquisition was financed through bank debt. See Note 6.
On October 1, 1997, the Company acquired Voyager Energy Corp. ("Voyager"), an oil and gas exploration and production company, for 352,638 shares of common stock of the Company in a tax-free reorganization. The shares issued by the Company in the merger represent in the aggregate approximately 6.5 percent of the Company's common stock outstanding after the transaction. The value of the shares in the tax-free reorganization was $4.6 million. The shares were distributed as a non-cash transaction and, as such, are not reflected in the Consolidated Statement of Cash Flows for the year ended December 31, 1997. The Company assumed approximately $1.3 million in Voyager indebtedness as a result of the merger.
On July 31, 1997, the Seller completed the previously announced sale and disposition of substantially all of the assets of its research and reference fuels and custom chemical manufacturing business to SFC.
The assets purchased by SFC included the fee property in Channelview, Texas, on which Seller's refinery was located, all refining facilities located on the fee property and all related personal property, all inventories of finished products, work in process, raw materials and supplies related to the business, substantially all of the accounts receivable on the closing date, all transferable intellectual property used primarily in the business and all of Seller's rights under various contracts and leases related to the business. In connection with the transaction, (a) SFC received a license to use the name "Howell Hydrocarbons & Chemicals" for a five-year period after closing and assumed certain obligations of Seller and the Company, and (b) the Company agreed not to engage (directly or through affiliates) in any competing business for a five-year period after the closing.
The sale resulted in a pre-tax gain of $0.4 million and the proceeds of the sale were used by the Company to reduce its outstanding indebtedness. The sale completes the divestiture by the Company of all of its non-exploration and production businesses. In connection with the sale, the Company has given and received environmental and other indemnities. Should claims be made against the Company based on these indemnities, the Company could be required to perform its obligations thereunder.
In consideration of the assets sold to SFC, Seller and the Company received a payment of $19.8 million in cash, which included $14.8 million for the property, plant, equipment and related items, and $5.0 million in payment of working capital items. Seller was entitled to receive an additional payment equal to 55% of the amount by which Buyer's "EBITDA" for each twelve month period ending June 30, 1998, 1999, 2000, 2001 and 2002 exceeded the "Minimum EBITDA".
The results of the technical fuels and chemical processing business have been classified as discontinued operations in the accompanying consolidated financial statements. Discontinued operations also includes the allocation of interest expense (based on a ratio of net assets of discontinued operations to total consolidated net assets). Allocated amounts are as follows:
On December 31, 1996, the Company sold 100% of the outstanding common stock of Howell Transportation Services, Inc. ("HTS") to Lodestar Logistics, Inc. ("Lodestar") for $2.6 million, consisting of $1.8 million in cash, a $0.5 million note receivable and a $0.3 million receivable in the form of services to be rendered by HTS for Seller. Lodestar is owned by the former president of HTS, and the Company believes the sale price was equivalent to an arm's-length transaction.
The $0.5 million non-revolving note bears interest at the Prime Rate for a term of no longer than 84 months.
The note receivable and the receivable for future services are non-cash transactions which are not reflected in the statement of cash flows for the year ended December 31, 1996.
NOTE 4. INCOME TAXES
A summary of the provision for income taxes (benefit) from operations included in the consolidated statements of earnings is as follows:
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 carry forward were as follows:
The following table accounts for the difference between the actual tax provision and the amounts obtained by applying the applicable statutory U.S. federal income tax rate to the earnings from continuing operations before income taxes:
As of December 31, 1998, the Company had net operating loss carryforwards for federal income tax purposes of approximately $22 million, which expire in 2013.
NOTE 5. INVESTMENT IN GENESIS
On December 1, 1996, Genesis Crude Oil, L.P., a Delaware limited partnership ("Buyer"), Genesis Energy, L.P., a Delaware limited partnership ("MLP") and Genesis Energy, L.L.C., a Delaware limited liability company ("LLC"), (collectively referred to hereinafter as "Genesis"), entered into a Purchase & Sale and Contribution & Conveyance Agreement ("Agreement") with Howell Corporation and certain of its subsidiaries ("Howell") and Basis Petroleum, Inc. ("Basis"), a subsidiary of Salomon Inc. ("Salomon"). Pursuant to the
Agreement, Howell agreed to sell and convey certain of its assets to Buyer. These assets consisted of the crude oil gathering and marketing operations and pipeline operations of Howell ("Business").
Buyer was formed by MLP and LLC to acquire the Business from Howell and similar assets from Basis. MLP is owned 98% by limited partners and 2% by LLC, which is the general partner. LLC is owned 46% by Howell and 54% by Basis. As a result of this transaction, Howell owns a subordinated limited partner interest in Buyer of 9.01%, a direct general partner interest in Buyer of 0.18% and a general partner interest through MLP of 0.74% of Buyer.
In accordance with the Agreement, Howell received cash of approximately $74.0 million and 991,300 subordinated limited partner units in Buyer in exchange for its sale and conveyance of the Business and recognized a gain in the amount of approximately $13.8 million. The receipt of units is a non-cash transaction which reduced property, plant and equipment and increased investment in Genesis. Since this was non-cash, it is not reflected in the statement of cash flows for the year ended December 31, 1996. Except as specifically provided in the Agreement, Howell retained all liabilities related to the Business arising from the operations, activities and transactions of the Business up through the closing date, including various environmental-related liabilities. Howell made various representations and warranties as to itself and the Business and has agreed to indemnify Buyer for any breaches thereof. Claims for breaches of such representations and warranties must be brought before December 3, 2001. Howell also agreed to perform, and retain the liability for, the cleaning of certain tanks used in the pipeline operations which cleaning was completed in 1997.
On the closing date, Howell entered into various agreements with Buyer, MLP and LLC pursuant to the Agreement, including (a) a non-competition agreement prohibiting Howell from competing with the Business for a period of ten years; (b) an agreement relating to the purchase of crude oil by Howell for use in its technical fuels business and the sale of crude oil by Howell from its oil and gas exploration and production business; (c) an agreement whereby Howell will provide certain transitional services to Buyer; (d) an agreement whereby MLP will sell additional limited partner units to the public and use the proceeds to redeem the subordinated limited partner units in Buyer owned by Howell after certain conditions are met; and (e) an agreement whereby one-half of the subordinated limited partner units owned by Howell are pledged to secure Howell's indemnification of Buyer for environmental liabilities.
Also at closing, Howell entered into an agreement with Salomon which provides (a) an unconditional obligation of Howell to buy its 46% share of additional limited partner interests ("APIs") from Salomon if Howell (as a member of LLC) has approved an acquisition by Buyer and (b) to the extent APIs are outstanding, an obligation by Howell to purchase 46% of such outstanding APIs, but only to the extent of any distribution made to Howell by Buyer on Howell's subordinated limited partner units.
Summarized financial information for the Buyer for the years ended December 31, 1998 and 1997, respectively, was as follows:
At December 31, 1998, the amount of investment in the Buyer includes goodwill in the amount of $4.9 million which is being amortized over a period of 20 years. Accumulated amortization at December 31, 1998, was $0.5 million.
Salomon has reported that on May 1, 1997, it sold the stock of Basis to Valero Energy Corporation ("Valero"). On May 1, 1997, Basis informed the Company that Basis intends to transfer its interest in LLC back to Salomon. Pursuant to the agreement forming LLC, the Company had 30 days from the date of receipt of such
notice to make an offer for Basis' interest in LLC. The Company decided not to make an offer to purchase Basis' interest in LLC.
Basis is party to a number of agreements with Genesis, some of which may have terminated in connection with the transfer to Valero and others which may be terminated by Basis pursuant to their terms. Whether such contracts will be terminated or revised by Basis and/or Genesis in the future and the ultimate effect on Genesis of any such termination or revision cannot be determined at this time, but may or may not have a material effect on Howell.
On July 29, 1997, the Board of Directors of LLC cancelled the $3.45 million note payable by Howell Crude Oil Company ("HCO") to LLC. The note was distributed to HCO as a non-cash transaction and, as such, is not reflected in the Consolidated Statement of Cash Flows for the year ended December 31, 1998.
NOTE 6. DEBT AND AVAILABLE CREDIT FACILITIES
Short-term and long-term debt of the Company as of December 31, 1998 and 1997, were as follows:
The Company had no capital lease obligations.
REVOLVING CREDIT/TERM LOAN AGREEMENT
The Company amended and restated the December 17, 1997 Credit Agreement effective on December 1, 1998 ("Credit Facility"). The Credit Facility is comprised of two tranches. Tranche A is a revolving credit facility with a termination date no later than December 15, 2002. The Borrowing Base was redetermined to $110 million prior to the 1998 sale of the Company's fee mineral interest, and to $105 million after the sale. Tranche B is a term loan with an amended borrowing availability of $30 million. The Company is required to pay commitment fees on the unused portion of Tranche A at a rate of 0.375% per annum while Tranche B is outstanding. After Tranche B has been repaid, the commitment fee will be based upon the Borrowing Base Utilization at a rate of 0.25% per annum if 25% or less of the Borrowing Base is used, 0.30% if more than 25% and less than or equal to 75% is used, and 0.375% if more than 75% is used.
Outstanding amounts under the Credit Facility bear interest, at the Company's option, at either the Eurodollar Loan ("Libor") rate per annum, or the Base Rate (prime), plus the Applicable Margin. The Applicable Margin is determined by the Borrowing Base Utilization Percentage. It ranges from as low as Libor plus 1.50% or the Base Rate plus .00% if 25% or less of the Borrowing Base is used, to as high as Libor plus 2.50% or the Base Rate plus .75% if greater than 90% of the Borrowing Base is used.
The Credit Facility is secured by mortgages on substantially all of the Company's oil and gas properties. The Credit Facility contains certain other affirmative and negative covenants, including limitations on the ability of the Company to incur additional debt, sell assets, merge or consolidate with other persons, pay dividends on its capital in excess of historical levels, and a prohibition on change of control or management. In addition, the Credit Facility requires the Company to maintain a ratio of current assets plus Tranche A borrowing capacity to current liabilities, excluding current maturities of long-term debt, of at least 1.0 to 1.0 and an interest coverage ratio of not less than 1.5 to 1.0 on a rolling four quarter basis through June 30, 1999, and beginning in the third quarter of 1999 and thereafter, of not less than 1.5 to 1.0 at the end of any fiscal quarter.
On December 17, 1998, the Company was able to reduce the outstanding balance of Tranche A by $5 million and Tranche B by $8 million as a result of the sale of its fee mineral interest. See Note 3.
As of December 31, 1998, the Tranche A interest rate was 8.0625% per annum on $102 million and the Tranche B interest rate was 10.5625% per annum on $22 million.
At December 31, 1998, the Company had cash and cash equivalents of $5.9 million and $3 million available to it under the Credit Facility. Should a decline in the value of the Company's proved reserves occur during 1999, the bank could reduce the Borrowing Base, thereby causing mandatory payments under the Credit Facility. While the Company does not expect this to happen in 1999, such payments would adversely affect the Company's ability to carry out its capital expenditure program and could cause the Company to accelerate its plans to recapitalize its debt through the public or private placement of securities. See Note 1 "Recent Events" for proceeds received in 1999 applied to reduce the outstanding borrowing under the Credit Facility.
The fair value of the Company's long-term debt at December 31, 1998 and 1997, was estimated to be the same as its carrying value in the balance sheet since all significant debt obligations bear interest at floating market rates.
NOTE 7. SHAREHOLDERS' EQUITY
PREFERRED STOCK
At December 31, 1998 and 1997, the Company had 3,000,000 shares of preferred stock authorized.
In April 1993, the Company completed a public offering of 690,000 shares of $3.50 convertible preferred stock. The offering was priced at $50 per share to yield 7%. The convertible preferred stock is convertible into common stock of the Company at the option of the holder, at any time, at a conversion rate equal to, approximately, 3.03 common shares for each preferred share, with fractional shares paid in cash. The Company has the option to redeem the convertible preferred stock at a declining premium redemption price beginning in 1996.
Dividends on the convertible preferred stock are to be paid quarterly. Such dividends accrue and are cumulative. Holders of the preferred stock have no voting rights except on matters affecting the rights of preferred shareholders. If at any time the equivalent of six quarterly dividends payable on the preferred stock are accrued and unpaid, the preferred shareholders will be entitled to elect two additional directors to the Company's Board of Directors. The Company is current in the payment of preferred dividends.
COMMON STOCK
At December 31, 1998 and 1997, the Company had 50,000,000 shares of common stock authorized.
EMPLOYEE STOCK OPTIONS
The Company maintains nonqualified stock option plans that provide for granting of options for the purchase of common stock to key employees. These stock options may be granted for periods up to 10 years and are generally subject to vesting up to four years. At December 31, 1998, no shares were available for future option grants.
Stock option activity for the Company during 1998, 1997, and 1996 was as follows:
At December 31, 1998, options were exercisable for 400,340 shares at a weighted average exercise price of $12.37. The range of exercise prices on outstanding options at December 31, 1998, was $8.31 to $18.75. The remaining contractual life of these options was approximately 8.5 years.
The following pro forma summary of the Company's consolidated results of operations have been prepared as if the fair value based method of accounting for stock based compensation had been applied:
The weighted average fair value of options granted during 1998, 1997 and 1996 was $7.94, $5.46 and $8.17, respectively.
Fair value of the options estimated at the date of grant using a Black-Scholes option pricing model with the following weighted average assumptions for 1998, 1997 and 1996.
NOTE 8. SEGMENT INFORMATION
In 1998, the Company adopted Financial Accounting Standards Board Statement No. 131, "Disclosures About Segments of An Enterprise and Related Information."
The principal business of the Company consists of the exploration, development and acquisition of oil and gas properties and the production and sale of crude oil and liquids and natural gas. The Company has determined that its reportable segments are those that are based on the Company's principal and non-principal business activities involved in continuing operations. The Company's reportable segments are Oil and Gas Production and Crude Oil Marketing and Transportation. See Note 5 for discussion of the Crude Oil Marketing and Transportation segment. All of the Company's operations and assets are conducted and located in the United States.
The accounting policies of the segments are the same as those described in the "Summary of Significant Accounting Policies." The Company allocates 100% of its resources to its principal business activity.
Financial information about the Company's continuing operations for each of the years ended December 31, 1998, 1997 and 1996, is summarized as follow:
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 sales of production of carbon dioxide, helium and sulfur from the LaBarge Project.
Inter-segment sales by the oil and gas production segment to the crude oil marketing and transportation segment were $0, $0 and $15,438 in 1998, 1997 and 1996, respectively. These amounts have been eliminated in consolidation.
Marathon Oil Company, a customer of the crude oil marketing and transportation segment, accounted for approximately 18% of consolidated revenues in 1996.
As a result of the sale in 1997 to SFC, referred to in Note 3, segment data for 1996 have been restated to conform to the 1998 presentation.
NOTE 9. LITIGATION
On July 11, 1995, the Company received a demand letter from several working interest owners in the North Frisco City Field and in the North Rome Field indicating the Company had not paid according to the terms of a "call on production." The Company was granted a call on a portion of this production but never exercised the call. Accordingly, the Company has filed petitions for declaratory judgment to that effect in cases styled HOWELL PETROLEUM CORPORATION, ET AL, VS. SHORE OIL COMPANY, ET AL, District Court of Harris County, Texas; No. 95-037480 and HOWELL PETROLEUM CORPORATION, ET AL, VS. TENEXCO, INC., ET AL, District Court of Harris County, Texas; No. 95-037970. The defendants in this action have counterclaimed against the Company. These claims are similar in nature to the Alabama and Mississippi royalty litigation. One of the defendants, John Faulkinberry, has filed a counterclaim against the Company seeking actual damages of $75,000 and punitive damages of $100,000,000. Effective July 14, 1997, the Company settled with John Faulkinberry as well as several other working interest owners. The terms of the settlement are confidential, but the amounts paid in settlement were not material to the Company's financial condition, results of operations or cash flows. The case (as to the remaining interest owners) was tried during the week of December 7, 1998. On January 6, 1999 the trial court granted the request of the Company's subsidiaries for a declaratory judgment. The trial court ruled that neither of the Company's subsidiaries had exercised the call and denied the defendants' counterclaim for monetary damages. The trial court also awarded the subsidiaries attorney fees of $373,333, plus 10% interest on all sums owing to the subsidiaries. Subsequently, this case was settled.
Related to this matter, several royalty owners have filed lawsuits against the Company in Alabama and Mississippi concerning pricing in the North Frisco City Field. The lawsuits allege the Company violated its contracts with the plaintiffs by not paying the plaintiffs ". . . the highest available price for oil." Damages claimed by the plaintiffs include approximately $3.8 million and are based on numerous damage theories including, but not limited to, allegations of breach of contract and fraud. The complaints also seek unspecified punitive damages in the Alabama lawsuits and $7 million in punitive damages in the Mississippi lawsuit. The Company filed answers denying all charges. The Company does not believe that the ultimate resolution of these matters will have a materially adverse effect on the financial position, results of operations or cash flows of the Company. On July 28, 1997, the Company settled the Mississippi lawsuit. On March 30, 1998 a tentative settlement was reached with the Alabama Class representative. On February 24, 1999 the trial court entered a preliminary approval order. The final fairness hearing is scheduled for May 5, 1999. The amounts paid in settlement of both cases were not material to the Company's financial condition, results of operations or cash flows.
There are various other lawsuits and claims against the Company, none of which, in the opinion of management, will have a materially adverse effect on the Company.
NOTE 10. COMMITMENTS AND CONTINGENCIES
The Company is subject to various environmental regulations and laws. Procedures exist within the Company to monitor compliance and assess the potential environmental exposure of the Company. The Company believes that such exposure is not materially adverse to its financial position, results of operations or cash flows.
The Company has indemnified Exxon for certain environmental claims that may be made in the future attributable to the time when Exxon owned the crude oil pipelines that the Company acquired from Exxon. In 1996, the crude oil pipelines were acquired by Buyer under the Agreement, however, the Company retained certain environmental liabilities which management believes will not have a material financial impact on the financial position, results of operations or cash flows of the Company. See Note 5.
The Channelview facility was 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 has been negotiating to obtain a renewed permit. Penalties may potentially be imposed upon the Company as a result of this matter; however, until this matter is resolved, the amount of such penalties, if any, cannot be quantified. While penalties may be material and the actions of regulatory bodies are not subject to accurate prediction, based on information currently available to the Company and on the circumstances present at its Channelview facility (including the existence of the state permit, the Company's compliance with the more stringent state permit, and the ability, if required, to operate the Channelview facility utilizing holding tanks and offsite third party treatment facilities in the absence of a permit), the Company does not believe that this matter will have a materially adverse effect on the financial position, results of operations or cash flows of the Company. In 1997, the Channelview facility was sold to SFC, however, the Company retained certain environmental liabilities for a period of five years which management believes will not have a material financial impact on the financial position, results of operations or cash flows of the Company.
The Company has indemnified Amoco for all third party claims other than those for which Amoco is obligated to indemnify the Company regardless of whether the claims relate to periods of time prior to or after the closing. Amoco has indemnified the Company for non-environmental third party claims relating to the period of time prior to closing that are identified within eighteen months after closing if the claims exceed three percent of the purchase price in the aggregate. Amoco also will indemnify the Company for environmental third party claims relating to the period of time prior to closing that are identified within twelve months after closing if the claims exceed three percent of the purchase price in the aggregate but in no event to exceed 50% of the purchase price.
Under the terms of the purchase agreement, Amoco has a call on certain oil production from the properties acquired in the Acquisition. Beginning March 1, 1998, for a fifteen year period Amoco has a call, if exercised, on 4,000 barrels per day of sweet crude oil production net to the Company's interest from the acquired Salt Creek field at a price per barrel equal to the average of three postings chosen by the Company from an approved group plus $1.50; provided, however, the maximum price paid shall not exceed Platt's Wyoming Sweet Monthly Average and the minimum price paid shall not be less than Platt's Wyoming Sweet Monthly Average minus $1.00. Beginning March 1, 1998, for a seven year period Amoco has a call on 2,000 barrels per day of sour crude oil production net to the Company's interest from the acquired Elk Basin field and all of the sour crude oil production from the acquired Grass Creek and Pitchfork fields at a price per barrel equal to the average of three postings chosen by the Company from an approved group plus $0.25; provided, however, the maximum price paid shall not exceed Platt's Wyoming Sweet Monthly Average minus $2.75 and the minimum price paid shall not be less than Platt's Wyoming Sweet Monthly Average minus $4.75. All crude oil pricing is subject to gravity adjustment.
The Company occupies office and operational facilities and uses equipment under operating lease arrangements. Expense of these arrangements amounted to $425,000 in 1998, $425,000 in 1997 and $2,765,000 in 1996. At December 31, 1998, long-term commitments for lease of facilities and equipment totaled approximately $4,207,000, consisting of $651,000, $672,000, $672,000, $672,000 and $672,000 for the years 1999 through 2003, respectively, and $868,000 thereafter.
NOTE 11. DETERMINATION OF EARNINGS PER INCREMENTAL SHARE
The following tables present the reconciliation of the numerators and denominators in calculating diluted earnings per share ("EPS") from continuing operations in accordance with Statement of Financial Accounting Standards No. 128.
COMPUTATION OF DILUTED EARNINGS PER SHARE
Note: Because diluted EPS from continuing operations increases from $(12.84) to $(12.74) when common stock options are included in the computation and because diluted EPS increases from $(12.74) to $(8.92) when convertible preferred shares are included in the computation, those common stock options and convertible preferred shares are antidilutive and are ignored in the computation of diluted EPS from continuing operations. Therefore, diluted EPS from continuing operations is reported as $(12.84).
COMPUTATION OF DILUTED EARNINGS PER SHARE
Note: Because diluted EPS from continuing operations increases from $0.17 to $0.44 when convertible preferred shares are included in the computation, those convertible preferred shares are antidilutive and are ignored in the computation of diluted EPS from continuing operations. Therefore, diluted EPS from continuing operations is reported as $0.17.
COMPUTATION OF DILUTED EARNINGS PER SHARE
NOTE 12. SUPPLEMENTARY OIL AND GAS PRODUCING INFORMATION (UNAUDITED)
RECENT EVENTS
The proposed sale of the Pitchfork and Grass Creek, Wyoming fields and the actual sale of LaBarge, Wyoming fields for a total of $28.2 million represent 7.0 million barrels of oil equivalent ("MMBOE") out of the 43.1 MMBOE of the Company's proved oil and gas reserves at December 31, 1998 and approximately 2.2 MBOE per day of the Company's 11.9 MBOE 1998 daily production. These transactions also represent 460 gross and 135 net oil wells, 21 gross and 9 net gas wells, 10,409 gross and 2,508 net developed acres, and 320 gross and 320 net undeveloped acres.
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, except for the reserves purchased from Amoco, at December 31, 1998, 1997, and 1996, were reviewed by independent petroleum consultants, H. J. Gruy and Associates, Inc. The December 31, 1998 and 1997 reserves, associated with the Wyoming properties acquired from Amoco, were reviewed by independent petroleum consultants, Ryder Scott & Associates. The estimates for 1995 were reviewed 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.
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
Total proved reserves at year-end 1998 were 43,072 MBOE compared to 56,109 MBOE at year-end 1997. This change was related almost entirely to downward revisions associated with lower oil and gas prices. The price sensitivity of the Company's reserve base is illustrated by the fact that if year-end 1998 reserves were calculated using year-end 1997 pricing, total proved reserves would have remained basically unchanged at 1997 reserve levels.
Proved oil reserves at December 31, 1998, include 1.4 million barrels of natural gas liquids ("NGL").
In addition to the oil and gas reserves shown above, the Company, through its participation in the LaBarge Project in southwestern Wyoming, had proved carbon dioxide reserves of 57,140 MMCF and proved helium reserves of 2,570 MMCF at December 31, 1998. The LaBarge Project was sold in January 1999.
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:
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:
In 1998, 1997 and 1996, $18,123,000, $57,000 and $8,000 of costs of unproved mineral interests, respectively, were transferred to the full-cost pool, representing the costs of mineral properties that were drilled and evaluated during the periods. The 1998 amount also represents the sale of the minerals on December 17, 1998. These transfers of costs are not reflected in the table above. See Note 3 of Notes to the Consolidated Financial Statement.
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 which was sold in December 1998.
Included in the 1998, 1997 and 1996, amounts above are $1,314,000, $2,005,000, and $2,301,000 of revenues and $121,000, $174,000, and $181,000 of production costs, respectively, from the production of the Company's producing fee mineral interests which was sold in December 1998.
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 1998 and 1997. 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.
The standardized measure is not intended to represent the market value of reserves and, in view of the uncertainties involved in the reserve estimation process, including the instability of energy markets as evidenced by recent declines in both natural gas and crude oil prices, the reserves may be subject to material future revisions.
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS. The table below presents a reconciliation of the aggregate change in standardized measure of discounted future net cash flows:
The Company's oil and gas exploration and production activities are conducted entirely within the United States by HPC and are concentrated in Wyoming and along the Gulf Coast, both onshore and offshore. At December 31, 1998, the Company's estimated proved reserves were 29.9 MMBO and plant liquids and 78.8 BCF of gas. The Company's major producing properties include Salt Creek, Elk Basin, North Frisco City, Main Pass 64, Grass Creek and LaBarge fields. These six major fields represent 36.0 MMBOE, or 84% of the Company's total proved reserves. 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.
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.