Item 3. LEGAL PROCEEDINGS
On August 30, 2000 CJC Leasing, Inc. ("CJC"), a wholly owned subsidiary of the Company previously involved in the coal mining business, received a "Notice of Taxes Due" from the State of Kentucky regarding the results of a coal severance tax audit covering the years 1989 through 1993. The audit proposed a tax assessment of $8.3 million plus penalties and interest. CJC protested this assessment and set forth a number of defenses including that CJC was not a taxpayer engaged in severing and/or mining coal at anytime during the assessment period. Further, it is CJC's informed belief that such taxes were properly paid by the third parties that had in fact mined the coal. Management intends to vigorously defend CJC and currently expects that resolution of this matter will not have a significant adverse impact on the Company's financial position or results of operations.
In the normal course of business, the Company becomes involved in litigation incident to its operations. In management's opinion, the ultimate resolution of all litigation matters and disputes will not have a material adverse impact on the Company's financial position or results of operations.
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Item 4.
Item 4. SUBMISSION OF MATTER TO A VOTE OF SECURITY HOLDERS.
None.
EXECUTIVE OFFICERS OF THE REGISTRANT
The persons who are currently serving as executive officers of the Company, their ages and the positions they hold with the Company are as follows:
Each officer has served in his present position for at least five years. No family relationship exists between any of the officers. Mr. Hurst is a partner in the law firm of Chaffin & Hurst.
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PART II
Item 5.
Item 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDER MATTERS
The Company's common stock is traded on the American Stock Exchange. The following table sets forth the high and low sales prices of the common stock as published in The Wall Street Journal for issues listed on the American Stock Exchange for each calendar quarter since January 1, 2000.
At December 31, 2001 there were 362 holders of record of the Company's common stock and the closing stock price was $7.80 per share.
The terms of the Company's bank loan agreement requires the Company to maintain consolidated net worth in excess of $31,357,000. Should the Company's net worth fall below this threshold, the Company may be restricted from payment of additional cash dividends on the Company's common stock.
On December 17, 2001 and on each of December 15, 2000 and 1999, the Company paid an annual cash dividend of $.13, $.13 and $.10 per common share, respectively, to all holders of its common stock of record on December 1st of each year. Such dividends aggregated $548,000, $548,000 and $422,000, respectively for each year.
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Item 6.
Item 6. SELECTED FINANCIAL DATA
FIVE YEAR REVIEW OF SELECTED FINANCIAL DATA
- ----------
(1) The 2001 marketing loss primarily resulted from $8 million in charges related to crude oil and natural gas inventory liquidations and price declines and a $1.9 million bad debt provision that resulted from Enron North America Corp's bankruptcy.
(2) The 1998 oil and gas loss primarily resulted from additional 3D seismic expense and a write-down of oil and gas properties due to reduced prices for crude oil and natural gas.
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Item 7.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
- Marketing
Marketing operating earnings were adversely affected by a number of significant factors during 2001, the first of which was declining crude oil and natural gas prices. Crude oil prices began the year in the $26 range, but fell to the $19 range by year's end. Within its crude oil operation, the Company has been generally required to carry in excess of one million barrels of inventory. Such requirements stem from the Company's position as a shipper on third party pipelines. With declining prices, the Company recognized approximately $7.2 million in charges related to crude oil inventory liquidations and valuation write-downs during 2001. During the year, however, the Company endeavored to reduce crude oil inventory quantities, and as of December 31, 2001, exposure to price declines was substantially reduced. Year-end 2001 crude oil inventory volumes stood at 361,000 barrels with an average cost of $19.27 per barrel. The natural gas business also experienced price declines during 2001. The Company is required by the New England area local distribution companies to store certain quantities of natural gas during the summer for winter usage. Due to natural gas prices that fell from the $5 per mmbtu range in the summer months as inventories were being built to under $3 in the fourth quarter winter months, the Company sustained an $805,000 valuation loss on natural gas inventories. At December 31, 2001, the Company held 306,000 mmbtu's of natural gas in storage at its market value of $2.64 per unit.
Another significant adverse factor in 2001 was the bankruptcy of Enron Corp. In December 2001, the Company was a creditor of Enron for physical sales of natural gas, and as a result sustained a $1.9 million bad debt provision. As of year-end 2001, the Company is carrying a net account receivable from Enron North America Corp. totaling $489,000, which equates to 25% of the original face value of the receivable. The credit problems of Enron further hampered operations because of its overall impact on the industry. Beginning in October 2001, the Company's operations were severely restricted as the use of Enron's online trading service was avoided and open line credit terms granted to counterparties were constrained. Similarly, counterparties restricted the amount of trade credit available to the Company. With the decrease in volumes, natural gas operating margins were not sufficient to absorb associated back office costs. While this situation primarily affected the natural gas business, it also had a spillover adverse impact on the crude oil operation.
The interrelationship between falling natural gas prices and record mild weather in the New England region also hampered the Company. In the retail natural gas sales business, the Company enters into certain "full requirements contracts" with heat sensitive end users. Under these contracts, the Company bears the risk associated with the difference between expected volumes versus actual usage. During the spring of 2001, the Company entered into a number of contracts to sell fourth quarter natural gas at prices in the $6 per unit range. In turn, the Company purchased such expected future sales volumes in the $5 per unit price range. Recognizing its exposure to volume fluctuations, the Company attempted to reduce some of its risk by purchasing certain straddle options. Unfortunately, these options were purchased from Enron and were not honored due to the bankruptcy. With the abnormal weather conditions, actual usage volumes were reduced, forcing the Company to sell off excess supply into a falling market. The resulting loss was $1,609,000. As the "full requirements" contracts expire in 2002, the Company will not renew most of this business. Such non-renewal will also substantially reduce the Company's requirement to hold natural gas inventories. Other than reducing market risk, the loss of this business will not impact the Company's overall marketing operation.
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Finally for 2001, a series of shifts in inter-month crude oil price spreads occurred, particularly in the second and fourth quarters due to weak refiner demand for domestic crude oil. During 2000 through mid-March 2001, the Company's trading strategy was premised on current month crude oil prices being higher or stronger than succeeding month prices. When this situation reversed in late March 2001 (the current month price being lower than the next month's price) the Company chose to liquidate certain positions, necessitating a $1,375,000 second quarter charge to earnings. The problem was compounded by a high degree of inter-month price volatility, making it difficult to judge the general trend of the market. Crude oil is normally purchased under 30-day evergreen contracts, while the resale of crude oil is consummated daily throughout the month. In a volatile and falling market, the Company was unable to extract its necessary margin of profit. The situation in May 2001 caused the Company to begin systematically cancelling its crude oil acquisition contracts in accordance with the allowed terms. Effective with July 2001 production, the Company had adjusted the pricing on its crude oil purchase contracts to be in line with current trends. Following the events of September 11, 2001, however crude oil price spreads first spiked and then fell once again as the OPEC nations attempted to maintain liquidity in the marketplace. This situation further cut operating margins.
Marketing segment revenues, operating earnings and significant operating statistics were as follows (in thousands except volume information):
(1) Reflects the volume purchased from third parties by the Company and its affiliated crude oil joint venture at the lease level and pipeline pooling points.
Gross revenues from marketing decreased by $2.3 billion or 33% for 2001 primarily as a result of converting certain previously consolidated marketing operations into a joint venture structure. In May 2000, the Company entered into a joint venture with a third party for the purpose of purchasing, distributing, and marketing crude oil in the offshore Gulf of Mexico region. The venture became fully operational in October of 2000 and was accounted for under the equity method of accounting. Thus, certain crude oil purchases and sales previously consolidated on the statement of earnings began being reported on a net earnings basis in marketing segment revenues. Desiring to reduce crude oil inventory levels and improve liquidity, the Company agreed to dissolve the joint venture and withdrew from the offshore region effective November 1, 2001. As consideration for terminating the joint venture agreement, the Company is entitled to a per barrel fee to be paid by its former joint venture co-participant on certain barrels purchased by the co-participant in the offshore Gulf of Mexico region. Such fee remains in effect for a 60-month period, provided the former joint venture participant continues to purchase crude oil in the offshore region. In connection with its withdrawal from the joint venture, the Company accrued $800,000 to provide for severance payments pending the final wind-down of the joint venture relationship.
Comparatives for 2000 and 1999 show that gross revenues for 2000 increased by $3,023,800,000 or 76% as a result of higher crude oil prices during most of the year, coupled with an approximate 37% growth in crude oil volumes. Further, during the fourth quarter of 1999, the Company expanded its presence in the wholesale marketplace for natural gas. Natural gas volumes combined with higher prices
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added $1.3 billion to 2000 revenues. Operating earnings for 2000 improved by 48% because of the crude oil volume increases and a strong operating environment for crude oil margins. Absolute crude oil prices rose during much of 2000 to a high of $34 per barrel in November, but fell off during December to their original levels. The resulting effect on operating earnings from the rise and fall of crude oil prices was negligible for the year. While the natural gas business added significantly to revenues, its impact on operating margins was a loss of $4.1 million, stemming from bad debt write-offs recorded in late 2000. Such write-offs resulted from the commencement of involuntary bankruptcy proceedings by a customer of the Company.
- - Transportation
A depressed marketplace continued to face the transportation segment in 2001, as has been the situation since the second quarter of 2000. Revenues and operating earnings were as follows (in thousands):
(1) Represents the percentage increase (decrease) from the prior year.
Results from transportation are closely tied to trends for the United States economy in general and more specifically, to the domestic petrochemical industry. As a common carrier transporter of bulk liquid chemicals, demand for the Company's services is closely tied to the economic activity of domestic manufacturers of petrochemicals. A weakened U.S. economy, a strong dollar reducing chemical exports, last year's run-up in natural gas feedstock costs, and the aftermath of September 11, 2001 have all served to reduce demand.
Coupled with falling demand, the Company experienced increased operating expenses in 2001; most notably, liability insurance which increased by 71% or $636,000 for 2001 and maintenance and repairs which increased by 8% or $386,000, as the Company has elected to hold off on the purchase of new equipment given the demand picture. Increased insurance costs reflect the cyclical nature of the insurance industry and their present efforts to pass on high premium costs.
To counter these problems, the Company attempted to expand market share and focus on cost control. In 2001, there were a limited number of layoffs, and there were no additions to the transportation fleet. In recent years, the tank truck industry has seen a large volume of consolidation through mergers and acquisitions. Given current conditions for the industry, the Company anticipates further fallout as less financially secure competitors fail or are acquired. This should reduce future competition. When the U.S. economy improves and chemical demand resumes, the Company anticipates being well-positioned to capitalize on new opportunities.
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- Oil and Gas
Oil and gas segment revenues and operating earnings are primarily derived from crude oil and natural gas production volumes and prices. Comparative amounts are as follows (in thousands except average price data):
As reflected in the table above, oil and gas production revenues were consistent between 2001 and 2000 when improved average natural gas prices offset a slight volume decline and lower average crude oil prices. While revenues were consistent in the two most recent years, 2001 operating earnings were reduced by $931,000 or 57 percent. The comparative 2001 earnings reduction was influenced by a number of factors. At year-end 2001, natural gas and crude oil prices for the Company's equity production fell dramatically to $2.34 and $17.55 per unit respectively. This event caused a $1,060,000 fourth quarter 2001 write-down in the carrying value of certain oil and gas properties. Primarily due to the write-down, 2001 depreciation and depletion of $2,456,000 is equivalent to 2000's depreciation and depletion of $2,435,000. See Note 1 to Financial Statements. Without the write-down, 2001 depreciation and depletion would have been substantially reduced from 2000 levels. An additional factor impacting 2001 operating earnings was increased dry hole expense of $821,000 in 2001 versus $481,000 in 2000.
As reflected in the table above, during 1999, the Company experienced significantly reduced average prices for both crude oil and natural gas. This situation caused 1999 revenues to be approximately 44 percent below the other periods presented and produced a 1999 operating loss.
During 2001, the oil and gas operation participated in the drilling of twenty-seven wells. Seventeen of these wells were successfully completed, while three were drilling at year-end, and seven were dry holes. Oil and gas reserves of 618,000 barrels and 7,618,000 mcf's, respectively, as of December 31, 2001 reflect an average decrease of nine percent from 2000. Estimated future net cash flow from oil and gas properties was more significantly reduced, however, from $69,752,000 at year-end 2000, to $16,989,000 at year-end 2001. This reduction resulted from price declines, most notably natural gas which was valued at $8.79 per unit for the year-end 2000 reserve estimate versus $2.34 per unit for the year-end 2001 reserve valuation.
A potentially significant discovery was made in January 2002 from an exploratory well in Schleicher County, Texas. This well was successfully completed and tested more than 140 barrels of oil per day. Production facilities have been installed and the well is being placed on production. Conversely, recent exploration efforts in Fort Bend County, Texas have not met original expectations. Three deep wells were successfully completed but production is below anticipated rates.
The Company's shallow gas prospect in Refugio County, Texas had two wells successfully completed in 2001 with at least one step-out well planned. Six wells were drilled in the Vinton Dome prospect during 2001, five of which were successful. Six Vinton Dome wells are planned for 2002. In the Elm Grove Field in North Louisiana, the Company drilled nine successful wells. Drilling in this area
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is concentrated low risk, in-fill wells designed to exploit undrained areas of older gas reservoirs. The Company will continue to participate in these wells as they are identified.
Outlook
A significant objective for 2001 was to reduce price risk exposure from crude oil inventory levels. As shown in Note 1 to the Financial Statements, crude oil inventory stood at $32,556,000 at year-end 2000 versus $6,806,000 at year-end 2001. With this risk dramatically reduced, a return to profitability from marketing operations is anticipated in 2002. In addition, because of Enron, the emphasis on sound credit quality has been increased throughout the industry. The Company is also taking steps to reduce its exposure to volume risk within its New England retail natural gas operation. With a reduced risk environment, the Company believes it can restore profitability to its marketing operation.
The economic outlook for 2002 looks better for the chemical industry, and hence the Company's transportation operation. Forecasts call for a slow recovery commencing during the second quarter and picking up momentum as the year progresses. The goal for 2002 is to increase revenues by 10 to 15 percent while holding cost increases below three percent. Because over half of this segment's cost structure is fixed in nature, management believes this goal is achievable. Some obstacles being faced are high maintenance costs of an aging fleet, driver recruitment and retention, insurance costs, and low competitive freight rates. If the goal is accomplished, however, transportation segment operating earnings should improve from current levels.
The Company's 2002 strategy for oil and gas exploration is to continue the focus on the prolific areas of the Gulf Coast from South Texas to the Upper Louisiana coast. However, the Company is also opportunity driven and will not limit itself geographically if an attractive project is identified such as the discovery in Schleicher County. The Schleicher project has the potential for nine additional wells, but production will be monitored for three to six months before drilling the next location. Presently under lease is a like structure offsetting this discovery and a second exploratory well is currently scheduled for drilling in the second quarter of 2002. Importantly, the Company has a 50 percent working interest in this prospect. The emphasis in Fort Bend County, Texas will be to evaluate the numerous shallow prospects that have been identified and are ready to drill. Lower drilling cost combined with less mechanical and geological risk make these shallower prospects attractive alternatives to the deeper, more costly Wilcox wells drilled to date. The current plan is to drill four to six wells. If successful, a significant number of additional wells will be drilled over the next two years. Management believes very attractive acquisition opportunities will be present in 2002, and the Company plans to evaluate and act on those projects that offer synergy and upside potential.
Other Income (Expense)
General and administrative expenses increased in 2000 and again in 2001 because of additional personnel costs stemming from increased crude oil and natural gas marketing activities. Other income for 2001 includes a $5,000,000 gain from the cash sale of a Sour Lake, Texas to Baytown, Texas crude oil pipeline. Income for 2001 also includes a $132,000 gain from the sale of eleven truck-tractors and interest income totaling $444,000. Other income totaling $1,233,000 for 2000 reflects interest income received, while other income for 1999 includes a $617,000 gain from the sale of forty-five truck-tractors and $565,000 of interest income.
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LIQUIDITY AND CAPITAL RESOURCES
In 2001, the general U.S. economy was slowing and inter-month crude oil and natural gas price spreads were very volatile with a downward trend. As a result, beginning in the second quarter of 2001, the Company began to seek liquidity. New capital projects were restricted and only $3,591,000 was expended on property additions. The Company also made a concentrated effort to reduce crude oil inventory quantities. Positive cash flow was created when crude oil inventory levels were sold off from $32,556,000 at December 31, 2000 to $6,806,000 at December 31, 2001. See Note 1 to the Financial Statements.
Partly because of its drive to improve liquidity, the Company sold its Sour Lake pipeline, which generated $5,000,000 in cash. In addition, the Company exited its crude oil joint venture arrangement. This decision freed the Company from the requirement to fund its pro-rata share of crude oil inventory maintained within the joint venture structure. As a shipper of crude oil on third party offshore pipeline systems, the joint venture was generally required to carry in excess of 1 million barrels of inventory of which the Company would fund 50 percent. The Company's responsibility to fund joint venture inventory required a base level of cash funding in the $10-12 million range. The Company also used $21,963,000 of cash funds available at the beginning of the year to fund 2001 operations as more fully described below.
While the Company was making efforts to generate available cash, events in the marketplace were placing significant demands on liquidity. A key factor providing liquidity in the crude oil and natural gas business is the practice to settle, in cash, all wholesale level accounts receivable or payable on the 20th for crude oil and 25th for natural gas of the month following inception of the transaction. Historically, the Company's counterparties have been less proficient in the process of seeking prompt payment of amounts due. During 2001, counterparties improved the timeliness of their billing efforts, necessitating more prompt payments by the Company. As reflected on the Consolidated Statement of Cash Flows, during 2001 accounts receivable balances (primarily reflecting billings to counterparties), decreased by $168,311,000, while accounts payable, (primarily reflecting billings from counterparties), decreased by $193,350,000.
Along with funding the consolidated $7 million pre-tax operating loss in 2001, the Company's natural gas marketing operation created additional cash flow needs. The New England retail business is typically conducted under term contracts ranging from 5 months to 2 years with a one-year term being common. In the first half of 2001, natural gas prices fell from the $10 per unit level to the $5.50 per unit level. Believing the $5.50 price was advantageous, the typical retail customer elected to enter into a one year fixed price contract with a November 1, 2001 start date. In order to protect itself against a price increase prior to the time of actual delivery, the Company executed a matching fixed price purchase either through the New York Mercantile Exchange or with a counterparty such as Enron. Because prices continued to fall during 2001, the Company was required to fund margin calls until such time as the gas was scheduled to physically flow. The margining process used $5.8 million during 2001. In addition to the cash required for margins, this operation also experienced a call on liquidity when Enron filed bankruptcy. While the net balance owed by Enron was $1,957,000, the balance due consisted of two components. First, $8.3 million was due from Enron in December 2001. Offsetting this amount was $6.4 million originally due to Enron during 2002, from certain of the fixed price purchases described above. Prior to Enron's filing, the Company exercised its offset rights to reduce its net exposure from Enron to $1,957,000. This netting process did, however, leave the Company with the short-term mismatch of cash flow requirements as described herein.
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Banking Relationships
The Company's primary bank loan agreement, with Bank of America, provides for two separate lines of credit with interest at the bank's prime rate minus 1/4 of 1 percent. The agreement also provides for an interest rate option at the lender's quoted Eurodollar rate (LIBOR) plus 2 and 3/4 percent. The working capital loan provides for borrowings up to $7,500,000 based on 80% of eligible accounts receivable and 50% of eligible inventories. Available capacity under the line is calculated monthly and as of December 31, 2001 was established at $7,500,000. The oil and gas production loan provides for flexible borrowings subject to a borrowing base established semi-annually by the bank. The borrowing base was established at $5,000,000 as of December 31, 2001 and was subsequently reduced to $4,000,000 in March 2002. The next scheduled borrowing base redetermination date is September 1, 2002. The working capital loans also provide for the issuance of letters of credit. The amount of each letter of credit obligation is deducted from the borrowing capacity. The line of credit loans are scheduled to expire on October 29, 2003, with the then present balance outstanding converting to a term loan payable in 12 equal quarterly installments. As of December 31, 2001, bank debt outstanding under the Company's two revolving credit facilities totaled $12,475,000, with letters of credit outstanding totaling $25,000.
The Company's Gulfmark subsidiary maintains a separate banking relationship with BNP Paribas in order to support its crude oil purchasing activities. In addition to providing letters of credit, the facility also finances up to $6,000,000 of crude oil inventory and certain accounts receivable associated with crude oil sales. Such financing is provided on a demand note basis with interest at the bank's prime rate plus 1 percent. As of December 31, 2001 the Company had $3.4 million of eligible collateral value under this facility. No amounts were outstanding at year-end.
Through December 2001, the Company's ARM subsidiary maintained a separate banking relationship with Bank of America in order to support its natural gas purchasing activities. In addition to providing letters of credit, the facility financed up to $4,000,000 of general working capital needs. During the third quarter of 2001, Bank of America announced its intentions to exit the commodities finance business. At that time, BNP Paribas indicated its desire to duplicate this facility and the transaction with BNP Paribas was originally anticipated for November 2001. In October 2001, when the problems of Enron became apparent, the availability of new commodity based loan facilities ceased. As scheduled, Bank of America shut off credit support in December 2001, and ARM has operated without credit support from December 2001 and on into March 2002. As of the date herein, ARM has received a term sheet from BNP Paribas to reinstate this facility and formal loan documentation is in process. No amounts were outstanding at year-end.
Management of the Company has long maintained that the biggest credit risk facing the Company is the uncertainty of the banking community's willingness to support commodity credit facilities. The events leading to Enron's bankruptcy support this belief. The Company continues to remain positioned to operate the commodity portions of its business without bank support should such a need develop.
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Contractual Cash Obligations
In addition to its banking relationships and obligations, the Company enters into certain operating leasing arrangements for tractors, trailers, office space and other equipment and facilities. A summary of contractual debt and lease obligations is as follows (in thousands):
Investment Activities
During 2001, the Company invested approximately $2.1 million in oil and gas projects, $635,000 for replacement equipment for its petrochemical trucking fleet and $846,000 was invested in facilities, trucks and equipment for the Company's marketing operations. Oil and gas exploration and development efforts continue, and the Company plans to invest approximately $3.5 million toward such projects in 2002. No additional monies are currently projected to be expended toward marketing or transportation related capital projects.
Insurance
The marketplace for all forms of insurance has entered a period of severe cost increases. In the past, during such cyclical periods, the Company has seen severe cost increases to the point where desired levels of insurance were either unavailable or unaffordable. The Company's primary insurance needs are in the area of automobile and umbrella coverage for its trucking fleet and medical insurance for employees. During 2001, the Company's insurance expense totals $5,016,000. Based on insurance renewals in late 2001 and early 2002, the Company is anticipating at least 50% insurance increase for 2002. The Company has no effective way to pass on such cost increases and this increase will thus need to be absorbed by existing operations.
Competition
In all phases of its operations, the Company encounters strong competition from a number of entities. Many of these competitors possess and employ financial and personnel resources substantially in excess of those which are available to the Company. The Company faces competition principally in pricing and quality of service. In its oil and gas operation, the Company also competes for the acquisition of mineral properties. The Company's marketing division competes with integrated oil companies which in some cases own or control refining and marketing facilities. These major oil companies may offer their products to others on more favorable terms than those available to the Company. From time to time in recent years, there have been supply imbalances for crude oil and natural gas in the marketplace. This in turn has led to significant fluctuations in prices for crude oil and natural gas. As a result, there is a high degree of uncertainty regarding both the future market price for crude oil and natural gas and the available margin spread between wholesale acquisition costs and sales realization.
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ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risk, including adverse changes in interest rates and commodity prices.
Interest Rate Risk
Total long-term debt at December 31, 2001 included $12,475,000 of floating rate debt. As a result, the Company's annual interest costs fluctuate based on interest rate changes. Because the interest rate on the Company's long-term debt is a floating rate, the fair value approximates carrying value as of December 31, 2001. A hypothetical 10 percent adverse change in the floating rate would not have had a material effect on the Company's results of operations for the fiscal year ending December 31, 2001.
Commodity Price Risk
The Company's major market risk exposure is in the pricing applicable to its marketing and production of crude oil and natural gas. Realized pricing is primarily driven by the prevailing spot prices applicable to oil and gas. Commodity price risk in the Company's marketing operations represents the potential loss that may result from a change in the market value of an asset or a commitment. From time to time, the Company enters into forward contracts to minimize or hedge the impact of market fluctuations on its purchases of crude oil and natural gas. The Company may also enter into price support contracts with certain customers to secure a floor price on the purchase of certain supply. In each instance, the Company locks in a separate matching price support contract with a third party in order to minimize the risk of these financial instruments. Substantially all forward contracts fall within a 6-month to 1-year term with no contracts extending longer than three years in duration. The Company monitors all commitments and positions and endeavors to maintain a balanced portfolio.
Certain forward contracts are recorded at fair value, depending on management's assessments of numerous accounting standards and positions that comply with generally accepted accounting principles. The revaluation of such contracts is recognized in the Company's results of operations. Current market quotes from actively traded, liquid markets are used to determine the undiscounted fair value of the contracts, which are reflected on the Company's balance sheet as risk management assets and liabilities. Risk management assets and liabilities are classified as short- or long-term depending on contract terms. The net unrealized gains and losses related to the valuation of these contracts are included in the marketing revenues on the accompanying statement of earnings. The estimated future net cash inflow based on year-end market prices is $12,672,000 for 2002, $1,711,000 for 2003 and $140,000 for 2004. The estimated future cash inflow approximates the net fair value recorded in the Company's risk management assets and liabilities.
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The following table illustrates the factors that impacted the change in the net value of the Company's risk management assets and liabilities for the year ended December 31, 2001. (In thousands)
Other changes in fair value of $6,337,000, as shown in the table above, reflects certain forward contracts entered into with Enron North America Corp. prior to their bankruptcy filing. Upon certain events of default leading up to the bankruptcy, the Company exercised its right to offset such funds due Enron North America with approximately $8.2 million due the Company from Enron North America Corp. Thus, the apparent $6,337,000 gain in fair value is offset by ordinary realized losses included in "Marketing Segment Operating Costs and Expenses".
Historically, prices received for oil and gas production have been volatile and unpredictable. Price volatility is expected to continue. Gas price realizations ranged from a monthly low of $1.96 per Mcf to a monthly high of $9.10 per Mcf during 2001. Oil prices ranged from a low of $17.55 per barrel to a high of $31.71 per barrel during the same period. A hypothetical 10 percent adverse change in average natural gas and crude oil prices, assuming no changes in volume levels, would have reduced earnings by approximately $855,000 and $519,000, respectively, for the fiscal year ended December 31, 2001.
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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
Item 8.
Item 8.
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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To The Shareholders of Adams Resources & Energy, Inc.:
We have audited the accompanying consolidated balance sheet of Adams Resources & Energy, Inc. (a Delaware corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of earnings, shareholders' equity and cash flows for each of the three years in the period ended December 31, 2001. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Adams Resources & Energy, Inc. and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Houston, Texas March 21, 2002
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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET (IN THOUSANDS)
The accompanying notes are an integral part of these consolidated financial statements.
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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF EARNINGS (IN THOUSANDS, EXCEPT PER SHARE DATA)
The accompanying notes are an integral part of these consolidated financial statements.
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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY (IN THOUSANDS)
The accompanying notes are an integral part of these consolidated financial statements.
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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CASH FLOWS (IN THOUSANDS)
The accompanying notes are an integral part of these consolidated financial statements.
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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of Adams Resources & Energy, Inc., a Delaware corporation, and its wholly owned subsidiaries (the "Company") after elimination of all significant intercompany accounts and transactions. In addition, these statements include the Company's share of oil and gas joint interests using pro-rata consolidation and its interest in a 50% owned crude oil marketing joint venture using the equity method of accounting. See Note 2 to Consolidated Financial Statements. Certain reclassifications have been made to prior year balances to conform with current year presentation.
Nature of Operations
The Company is engaged in the business of crude oil, natural gas and petroleum products marketing, as well as tank truck transportation of liquid chemicals and oil and gas exploration and production. Its primary area of operation is within a 500 mile radius of Houston, Texas.
Cash and Cash Equivalents
Cash and cash equivalents include any treasury bill, commercial paper, money market fund or federal fund with a maturity of 30 days or less. Included in the cash balance at December 31, 2001 and 2000 is a deposit of $2 million to collateralize the Company's month-to-month crude oil letter of credit facility. See Note 3 to Consolidated Financial Statements.
Inventories
Crude oil and petroleum product inventories are carried at the lower of cost or market. Due to declining prices for crude oil during 2001, the Company recognized a combined $7.2 million in charges related to crude oil inventory liquidations and valuation write-downs during the year. Petroleum products inventory includes gasoline, lubricating oils and other petroleum products purchased for resale and are valued at cost determined on the first-in, first-out basis, while crude oil inventory is valued at average cost. Materials and supplies are included in inventory at specific cost, with a valuation allowance provided if needed. Natural gas inventories are carried at market. Components of inventory are as follows (in thousands):
Property and Equipment
Expenditures for major renewals and betterments are capitalized, and expenditures for maintenance and repairs are expensed as incurred. Interest costs incurred in connection with major capital expenditures are capitalized and amortized over the lives of the related assets. When properties are retired or sold, the related cost and accumulated depreciation, depletion and amortization ("DD&A") is removed from the accounts and any gain or loss is reflected in earnings.
II-19
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Oil and gas exploration and development expenditures are accounted for in accordance with the successful efforts method of accounting. Direct costs of acquiring developed or undeveloped leasehold acreage, including lease bonus, brokerage and other fees, are capitalized. Exploratory drilling costs are initially capitalized until the properties are evaluated and determined to be either productive or nonproductive. If an exploratory well is determined to be nonproductive, the capitalized costs of drilling the well are charged to expense. Costs incurred to drill and complete development wells, including dry holes, are capitalized.
Producing oil and gas leases, equipment and intangible drilling costs are depleted or amortized over the estimated recoverable reserves using the units-of-production method. Other property and equipment is depreciated using the straight-line method over the estimated average useful lives of three to twenty years for marketing, three to fifteen years for transportation and ten to twenty years for all others.
The Company is required to periodically review long-lived assets for impairment whenever there is evidence that the carrying value of such assets may not be recoverable. This consists of comparing the carrying value of the asset with the asset's expected future undiscounted cash flows without interest costs. Estimates of expected future cash flows represent management's best estimate based on reasonable and supportable assumptions. Proved oil and gas properties are reviewed for impairment on a field-by-field basis. Any impairment recognized is permanent and may not be restored. Due to the decline in oil and natural gas prices in the fourth quarter of 2001, certain of the Company's proved oil and gas fields were deemed impaired as of December 31, 2001. Accordingly, a $1,062,000 asset impairment charge was included in DD&A for 2001.
Revenue Recognition
The Company's natural gas and crude oil marketing customers are invoiced based on contractually agreed upon terms on a monthly basis. Revenue is recognized in the month where the physical product is delivered to the customer. Where required, the Company also recognizes mark-to-market gains and losses related to its natural gas and crude oil trading activities. A detailed discussion of the Company's risk management activities are included later in this footnote.
Customers of the Company's petroleum products marketing subsidiary are invoiced and revenue is recognized in the period the product is shipped or received by the customer depending on when title transfers. Transportation customers are invoiced, and the related revenue is recognized as the service is provided. Oil and gas revenue from the Company's interests in producing wells is recognized as oil and gas is produced.
Statement of Cash Flows
Interest paid totaled $128,000, $172,000 and $75,000 during the years ended December 31, 2001, 2000 and 1999, respectively. Income taxes paid during these same periods totaled $322,000,
II-20
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
$2,814,000 and $895,000, respectively. There were no significant non-cash transactions in any of the periods reported.
Earnings Per Share
The Company computes and presents earnings per share in accordance with Statement of Financial Accounting Standards ("SFAS") No. 128, "Earnings Per Share", which requires the presentation of basic earnings per share and diluted earnings per share for potentially dilutive securities. Earnings per share are based on the weighted average number of shares of common stock and common stock equivalents outstanding during the period. Such shares outstanding on both a basic and diluted basis averaged 4,217,596 for 2001, 2000 and 1999.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of 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. Examples of significant estimates used in the accompanying consolidated financial statements include the accounting for depreciation, depletion and amortization, income taxes, contingencies and price risk management activities.
Price Risk Management Activities
The Company's trading and non-trading transactions give rise to market risk, which represents the potential loss that may result from a change in the market value of a particular commitment. The Company closely monitors and manages its exposure to market risk to ensure compliance with the Company's risk management policies. Such policies are regularly assessed to ensure their appropriateness given management's objectives, strategies and current market conditions.
Certain forward contracts are recorded at fair value, depending on management's assessments of numerous accounting standards and positions that comply with generally accepted accounting principles. The revaluation of such contracts is recognized in the Company's results of operations. Current market quotes from actively traded, liquid markets are used to determine the undiscounted fair value of the contracts, which is reflected on the Company's balance sheet as risk management assets and liabilities. Risk management assets and liabilities are classified as short- or long-term depending on contract terms. The net unrealized gains and losses related to the valuation of these contracts are reflected in marketing revenues on the accompanying statement of earnings. The estimated future net cash inflow based on year-end market prices is $12,672,000 for 2002, $1,711,000 for 2003, and $140,000 for 2004. The estimated future cash inflow approximates the net fair value recorded in the Company's risk management assets and liabilities.
On January 1, 2001 the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended by SFAS No. 137 and No. 138. The statement establishes accounting and reporting standards that require
II-21
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value, unless the derivative qualifies as a normal purchase or sale. Changes in fair value are recognized immediately in earnings, unless the derivatives qualify for cash flow hedge accounting, then the effective portion of the change in fair value will be deferred in other comprehensive income until the related hedge item impacts earnings. Based on the Company's assessment of its contracts that qualify as a derivative instrument under SFAS No. 133 and that were not already recorded at fair value on the balance sheet, the Company recorded a net risk management income of $55,000 (net of $29,000 of income taxes), as a cumulative affect of change in accounting principle. Prior to adoption of SFAS No. 133, all qualifying hedge contracts were not recorded on the balance sheet and gains and losses were recorded as the contracts were settled. As a result of these hedging activities, the Company recognized net hedging losses of $5,809,000 and $1,199,000 for the years ended December 31, 2000 and 1999, respectively. As of January 1, 2001 and for the year ended December 31, 2001 the Company had no contracts that qualified for hedge accounting under SFAS 133.
New Accounting Pronouncements
In September 2000, the Emerging Issues Task Force ("EITF") reached a consensus on EITF No. 00-10, "Accounting for Shipping and Handling Fees and Costs." Pursuant to the consensus, amounts paid related to certain transportation must be reported as an expense on the consolidated statement of earnings rather than reporting revenues net of transportation as has been common within the industry. In addition, pertinent amounts in financial statements for prior periods should be reclassified to reflect the same accounting treatment. The Company has, for all years presented, included all shipping and handling fees and costs in operating costs and expenses in the consolidated statement of earnings and as such no reclassification of amounts is required.
In August 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("Statement No. 144"). Statement No. 144 addresses the accounting and reporting for the impairment or disposal of long-lived assets and supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" and APB Opinion No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions." The objective of Statement No. 144 is to establish one accounting model for long-lived assets to be disposed of by sale as well as resolve implementation issues related to Statement No. 121. The Company adopted Statement No. 144 effective January 1, 2002 and with no material impact on its financial condition and results of operations.
(2) MARKETING JOINT VENTURE
Commencing in May 2000, a subsidiary of the Company entered into a joint venture arrangement with a third party for the purpose of purchasing, distributing and marketing crude oil in the offshore Gulf of Mexico region. The venture operated as Williams-Gulfmark Energy Company pursuant to the terms of a joint venture agreement. The Company held a 50 percent non-controlled interest in the net earnings of the venture and accounted for its interest under the equity method of accounting. The Company's net investment in the venture was reported in the consolidated balance sheet and its equity in the venture's pretax earnings was included in marketing segment revenues in the consolidated statement
II-22
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
of earnings. Because the excess cash generated by the venture was paid to the venture participants as of December 31, 2001 and 2000, the Company's net investment was a negative balance of $3,307,000 and $912,000, respectively, and was included in accounts payable. Equity earnings included in marketing segment operating earnings relating to the venture was a net loss of $7,369,000 for 2001 and net earnings of $3,643,000 for 2000. Included in equity earnings for 2000 was $1,480,000 representing market gains recorded as of December 31, 2000 on certain energy contracts. Effective November 1, 2001 the Company and the other venture participant agreed to cease conducting new business. The activities of the joint venture are being wound down and the Company has accrued a 2001 charge totaling $800,000 for related severance payments. These expenses were not included in the Company's reported equity loss in 2001. Summarized condensed financial information for the Company's joint venture investment (on a 100 percent basis) is presented below (in thousands):
Other than ordinary trade credit under standard industry terms, the joint venture had no third party debt or other obligations. Management of cash flow and all cash flow requirements were maintained by the participants.
(3) LONG-TERM DEBT
Long-term debt is comprised of the following (in thousands):
The Company's revolving bank loan agreement, with Bank of America, provides for two separate lines of credit with interest at the bank's prime rate minus 1/4 of 1 percent. The agreement also provides for an interest rate option at the lender's quoted Eurodollar rate (LIBOR) plus 2 and 3/4 percent. The first line of credit or working capital loan provides for borrowings up to $7,500,000 based on the total of 80%
II-23
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
of eligible accounts receivable and 50% of eligible inventories. Available borrowing capacity under the working capital line is calculated monthly and as of December 31, 2001 was established at $7,500,000 with the full amount outstanding at December 31, 2001. The second line of credit or oil and gas production loan provides for flexible borrowings, subject to a borrowing base established semi-annually by the bank. The borrowing base was established at $5,000,000 as of December 31, 2001 and was subsequently reduced to $4,000,000 in March 2002. The next scheduled borrowing base redetermination date is September 1, 2002. As of December 31, 2001, $4,975,000 was outstanding under the oil and gas production loan facility. The working capital loans also provide for the issuance of letters of credit. The amount of each letter of credit obligation is deducted from the borrowing capacity. As of December 31, 2001, letters of credit under this facility totaled $25,000. The revolving line of credit loans are scheduled to expire on October 29, 2003, with the then present balance outstanding converting to a term loan payable in 12 equal quarterly installments.
The revolving loan agreement, among other things, places certain restrictions with respect to additional borrowings and the purchase or sale of assets, as well as requiring the Company to comply with certain financial covenants, including maintaining a 1.0 to 1.0 ratio of consolidated current assets to consolidated current liabilities, maintaining a 3.0 to 1.0 ratio of pre-tax net income to interest expense, and consolidated net worth in excess of $31,357,000.
A subsidiary of the Company, Gulfmark Energy, Inc. ("Gulfmark"), maintains a separate banking relationship with BNP Paribas in order to provide letters of credit and to provide financing for up to $6 million of crude oil inventories and certain accounts receivable associated with sales of crude oil. Such financing is provided on a demand note basis with interest at the bank's prime rate plus 1%. The letter of credit and demand note facilities are secured by substantially all of Gulfmark's assets. At year-end 2001 and 2000, Gulfmark had no amounts outstanding under the inventory based line of credit. Gulfmark had approximately $18.1 million and $53 million in letters of credit outstanding as of December 31, 2001 and 2000, respectively, in support of its crude oil purchasing activities. As of December 31, 2001, the Company had $3.4 million of eligible borrowing capacity under the Gulfmark facility.
The Company's Adams Resources Marketing, Ltd. subsidiary ("ARM") maintained a separate banking relationship with Bank of America in order to support its natural gas purchasing business. In addition to providing letters of credit, the facility financed up to $4,000,000 of general working capital needs. During the third quarter of 2001, Bank of America announced its intentions to exit the commodities finance business. At that time, BNP Paribas indicated its desire to duplicate this facility, and the transaction with BNP Paribas was originally anticipated for November 2001. In October 2001, when the problems of Enron became apparent, the availability of new commodity based loan facilities ceased. As scheduled, Bank of America shut off credit support in December 2001, and ARM has operated without credit support from December 2001 and on into March 2002. As of the date herein, ARM has received a term sheet from BNP Paribas to reinstate this facility and formal loan documentation is in process. No borrowings were outstanding under the ARM's Bank of America facility at December 31, 2001. At December 31, 2001, ARM had $13.9 million of letters of credit outstanding under this facility that have subsequently expired under normal terms.
The Company's weighted average effective interest rate for 2001, 2000 and 1999 was 5.7%, 8.5% and 7.5%, respectively. No interest was capitalized during 2001, 2000 or 1999. At December 31, 2001,
II-24
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the scheduled aggregate principal maturities of the Company's long-term debt are: 2002 - 1,000; 2003 - $956,000; 2004 - $3,825,000; 2005 - $3,825,000; and 2006 - $2,869,000.
(4) INCOME TAXES
The following table shows the components of the Company's income tax provision (benefit) (in thousands):
As of December 31, 2001 and 2000, the Company's deferred tax liability totaled $5,407,000 and $3,915,000, respectively, and consisted principally of financial statement carrying amounts in excess of the underlying tax basis of fixed assets and mark-to-market gains on energy contracts not included in taxable income. At December 31, 2001 the fixed asset component of the deferred tax liability totaled $2,506,000 and the mark-to-market gain component totaled $2,901,000. As of December 31, 2001, the Company had a $3,930,000 tax receivable as a result of taxable losses which are being carried back and applied against taxes paid in prior years.
Taxes computed at the corporate federal income tax rate reconcile to the reported income tax provision as follows (in thousands):
The Company's remaining statutory depletion carryforwards were fully utilized in 1999 to reduce taxable earnings.
II-25
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(5) FAIR VALUE OF FINANCIAL INSTRUMENTS AND CONCENTRATION OF CREDIT RISK
Fair Value of Financial Instruments
The carrying amount of cash equivalents are believed to approximate their fair values because of the short maturities of these instruments. Substantially all of the Company's long and short-term debt obligations bear interest at floating rates. As such, carrying amounts approximate fair values. For a discussion of the fair value of commodity financial instruments see "Price Risk Management Activities" in Note 1 to Consolidated Financial Statements.
Concentration of Credit Risk
Credit risk represents the account loss which the Company would absorb if its customers failed to perform pursuant to contractual terms. Management of credit risk involves a number of considerations, such as the financial profile of the customer, the value of collateral held, if any, specific terms and duration of the contractual agreement, and the customer's sensitivity to economic developments. The Company has established various procedures to manage credit exposure, including initial credit approval, credit limits, and rights of offset. Letters of credit and guarantees are also utilized to limit credit risk.
The Company's largest customers consist of large multinational integrated oil companies and utilities. In addition, the Company transacts business with independent oil producers, major chemical concerns, crude oil and natural gas trading companies and a variety of commercial energy users. Accounts receivable associated with crude oil and natural gas marketing activities comprise approximately 95% of the Company's total receivables as of December 31, 2001, and industry practice requires payment for purchases of crude oil to take place on the 20th of the month following a transaction, while natural gas transactions are settled on the 25th of the following month. The Company's credit policy and the relatively short duration of receivables mitigates the uncertainty typically associated with longer term receivables management. Accordingly, the amount of the allowance for doubtful accounts required is minimal. No customer represented 10 percent of total accounts receivable or greater as of December 31, 2001. The Company had accounts receivable from one customer that comprised 11% of total receivables at December 31, 2000 and from one customer that comprised 31% of total receivables at December 31, 1999.
Primarily as a result of the bankruptcy of Enron Corp. in 2001, the Company incurred $2.1 million of bad debt expense. In 2000, the Company incurred bad debts totaling $4.1 million following the bankruptcy proceedings by a natural gas customer. An allowance for doubtful accounts is provided where appropriate and accounts receivable presented herein are net of allowances for doubtful accounts of $2,193,000 and $559,000 at December 31, 2001 and 2000, respectively.
(6) EMPLOYEE BENEFITS
The Company maintains a 401(k) savings plan for the benefit of its employees. Company contributions to the plan were $433,000 in 2001, $374,000 in 2000, and $314,000 in 1999. There are no pension or retirement plans maintained by the Company.
II-26
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(7) TRANSACTIONS WITH RELATED PARTIES
Sakco, Ltd. ("Sakco"), Kenada Oil & Gas, Ltd. ("Kenada") and Kasco, Ltd. ("Kasco"), family limited partnerships of which Mr. K. S. Adams, Jr., Chairman and President, is a limited partner, Sakdril, Inc. ("Sakdril"), a wholly owned subsidiary of KSA Industries Inc., which is a major stockholder of the Company, and certain officers and members of the Board of Directors of the Company including Mr. Adams have participated as working interest owners in certain oil and gas wells administered by the Company. Sakco, Kenada, Kasco, Sakdril and the officers and directors participated in each of the wells under terms no better than those afforded other non-affiliated working interest owners. As of December 31, 2001, the Company was owed $251,000 from these related parties and the Company owed $233,000 to these related parties. As of December 31, 2000, the Company was owed $76,000 from these related parties, and the Company owed $339,000 to these related parties.
David B. Hurst, Secretary of the Company, is a partner in the law firm of Chaffin & Hurst. The Company has been represented by Chaffin & Hurst since 1974 and plans to use the services of that firm in the future. Chaffin & Hurst currently leases office space from the Company. Transactions with Chaffin & Hurst are on the same terms as those prevailing at the time for comparable transactions with unrelated entities.
The Company also enters into certain transactions in the normal course of business with other affiliated entities. These transactions with affiliated companies are on the same terms as those prevailing at the time for comparable transactions with unrelated entities.
(8) COMMITMENTS AND CONTINGENCIES
The Company has operating lease arrangements for tractors, trailers, office space, and other equipment and facilities. Rental expense for the years ended December 31, 2001, 2000, and 1999 was $7,035,000, $6,981,000 and $7,573,000, respectively. At December 31, 2001, commitments under long-term noncancelable operating leases for the next five years and thereafter are payable as follows: 2002 - $4,677,000; 2003 - $3,965,000; 2004 - $2,674,000; 2005 - $1,133,000; 2006 - $420,000; 2007 and thereafter - $456,000.
On August 30, 2000 CJC Leasing, Inc. ("CJC"), a wholly owned subsidiary of the Company previously involved in the coal mining business, received a "Notice of Taxes Due" from the State of Kentucky regarding the results of a coal severance tax audit covering the years 1989 through 1993. The audit proposed a tax assessment of $8.3 million plus penalties and interest. CJC protested this assessment and set forth a number of defenses including that CJC was not a taxpayer engaged in severing and/or mining coal at anytime during the assessment period. Further, it is CJC's informed belief that such taxes were properly paid by the third parties that had in fact mined the coal. Management intends to vigorously defend CJC and currently expects that resolution of this matter will not have a significant adverse impact on the Company's financial position or results of operations.
In the normal course of business, the Company and its subsidiaries become involved in litigation incident to operations. In management's opinion, the ultimate resolution of all litigation matters and disputes will not have a material adverse impact on the Company's financial position or results of its operations.
II-27
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(9) SEGMENT REPORTING
The Company is engaged in the business of crude oil, natural gas and petroleum products marketing as well as tank truck transportation of liquid chemicals, and oil and gas exploration and production. Information concerning the Company's various business activities is summarized as follows (in thousands):
- ----------
(1) Includes $8 million in charges related to crude oil and natural gas inventory liquidations and valuation write-downs and a $1.9 million bad debt loss due to the bankruptcy of Enron North America Corp.
II-28
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Intersegment sales are insignificant. Other identifiable assets are primarily corporate cash, accounts receivable, and properties not identified with any specific segment of the Company's business. All sales by the Company occurred in the United States. During 2000 and 1999, the Company had sales to one customer that totaled $1,036 million and $565 million, respectively. No other customers accounted for greater than 10% of sales in any of the three years presented herein.
Earnings from operations by segment represent revenues less operating costs and expenses and depreciation, depletion and amortization and are reconciled to operating earnings and earnings from operations before income taxes, as follows (in thousands):
II-29
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
SUPPLEMENTARY FINANCIAL DATA
Quarterly Financial Data (Unaudited) -
Selected quarterly financial data and earnings per share of the Company are presented below for the years ended December 31, 2001 and 2000 (in thousands, except per share data):
- -----------------
(1) Reflects basic and diluted earnings per share for indicated periods.
(2) Includes $3.8 million in charges related to crude oil and natural gas inventory liquidations and valuation write-downs, a $1.9 million bad debt provision resulting from Enron North America Corp's bankruptcy, a $1.6 million loss on the sale of excess retail level natural gas volumes, $800,000 of severance costs accrued following the dissolution of a joint venture, and a $1.1 million write-down in the carrying value of certain oil and gas properties.
II-30
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
SUPPLEMENTARY FINANCIAL DATA
Oil and Gas Producing Activities (Unaudited) -
Total costs incurred in oil and gas exploration and development activities, all incurred within the United States, were as follows (in thousands, except per barrel information):
The aggregate capitalized costs relative to oil and gas producing activities are as follows (in thousands):
II-31
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
SUPPLEMENTARY FINANCIAL DATA
Estimated Oil and Natural Gas Reserves (Unaudited) -
The following information regarding estimates of the Company's proved oil and gas reserves, all located in the United States, is based on reports prepared on behalf of the Company by petroleum engineers. Because oil and gas reserve estimates are inherently imprecise and require extensive judgments of reservoir engineering data, they are generally less precise than estimates made in conjunction with financial disclosures. The revisions of previous estimates as reflected in the table below result from more precise engineering calculations based upon additional production histories and price changes.
Standardized Measure of Discounted Future Net Cash Flows from Oil and Gas Operations and Changes Therein (Unaudited) -
The standardized measure of discounted future net cash flows was determined based on the economic conditions in effect at the end of the years presented, except in those instances where fixed and determinable gas price escalations are included in contracts. The disclosures below do not purport to present the fair market value of the Company's oil and gas reserves. An estimate of the fair market value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, a discount factor more representative of the time value of money and risks inherent in reserve estimates.
II-32
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
SUPPLEMENTARY FINANCIAL DATA
The reserve estimates provided at December 31, 2001 and 2000 are based on year-end market prices of $17.55 and $25.08 per barrel for crude oil and $2.34 and $8.79 per Mcf for natural gas, respectively.
The following are the principal sources of changes in the standardized measure of discounted future net cash flows:
II-33
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
SUPPLEMENTARY FINANCIAL DATA
Results of Operations for Oil and Gas Producing Activities (Unaudited) -
The results of oil and gas producing activities, excluding corporate overhead and interest costs, are as follows:
Item 9.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
II-34
PART III
Item 10.
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
The information concerning executive officers of the Company is included in Part I. The information concerning directors of the Company is incorporated by reference from the Company's definitive Proxy Statement for the Annual Meeting of Shareholders to be held April 24, 2002, to be filed with the Commission not later than 120 days after the end of the fiscal year covered by this Form 10-K.
Item 11.
Item 11. EXECUTIVE COMPENSATION
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by Items 11, 12 and 13 is incorporated by reference from the Company's definitive Proxy Statement for the Annual Meeting of Shareholders to be held April 24, 2002, to be filed with the Commission not later than 120 days after the end of the fiscal year covered by this Form 10-K.
III-1
PART IV
Item 14.
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) The following documents are filed as a part of this Form 10-K:
1. Financial Statements
Report of Independent Public Accountants
Consolidated Balance Sheet as of December 31, 2001 and 2000
Consolidated Statement of Earnings for the Years Ended December 31, 2001, 2000 and 1999
Consolidated Statement of Shareholders' Equity for the Years Ended December 31, 2001, 2000 and 1999
Consolidated Statement of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999
Notes to Consolidated Financial Statements
Supplementary Financial Data (All unaudited)
2. Exhibits required to be filed
3(a) - Certificate of Incorporation of the Company, as amended. (Incorporated by reference to Exhibit 3(a) filed with the Annual Report on Form 10-K of the Company for the fiscal year ended December 31, 1987)
3(b) - Bylaws of the Company, as amended (Incorporated by reference to Exhibits 3.2 and 3.2.1 of Amendment No. 1 to the Registration Statement on Form S-1 filed with the Securities and Exchange Commission on October 29, 1973 - File No. 2-48144)
3(c) - Amendment to the Bylaws of the Company to add an Article VII, Section 8. Indemnification of Directors, Officers, Employees and Agents (Incorporated by reference to Exhibit 3(c) of the Annual Report on Form 10-K of the Company for the fiscal year ended December 31, 1986)
4(a) - Specimen common stock Certificate (Incorporated by reference to Exhibit 4(a) of the Annual Report on Form 10-K of the Company for the fiscal year ended December 31, 1991)
IV-1
4(c)* - Ninth Amendment to Loan Agreement between Service Transport Company et al and Bank of America, N.A. dated March 21, 2002.
21* - Subsidiaries of the Registrant
23.1* - Consent of Arthur Andersen LLP
99.1* - Financial Statements of Williams-Gulfmark Energy Company
- ----------
* - Filed herewith
All other financial schedules have been omitted because they are not applicable or the required information is shown in the financial statements or notes thereto.
The separate financial statements of Adams Resources & Energy, Inc. (the "Parent") are omitted because the conditions specified in Rules 5-04 and 12-04 of regulation S-X are met.
Copies of all agreements defining the rights of holders of long-term debt of the Company and its subsidiaries, which agreements authorize amounts not in excess of 10% of the total consolidated assets of the Company, are not filed herewith but will be furnished to the Commission upon request.
IV-2
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.
ADAMS RESOURCES & ENERGY, INC. (Registrant)
By /s/ RICHARD B. ABSHIRE By /s/ K. S. ADAMS, JR. --------------------------------- -------------------------------- (Richard B. Abshire, (K. S. Adams, Jr., Vice President-Finance, Director President,Chairman of the Board, and Chief Financial Officer) and Chief Executive Officer)
Date: March 21, 2002
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.
By /s/CLAUDE H. LEWIS By /s/ E. C. REINAUER, JR. --------------------------------- -------------------------------- (Claude H. Lewis, Director) (E. C. Reinauer, Jr., Director)
By /s/ THOMAS S. SMITH By /s/ E. JACK WEBSTER, JR. --------------------------------- -------------------------------- (Thomas S. Smith, Director) (E. Jack Webster, Jr., Director)
By /s/ JUANITA G. SIMMONS By /s/ EDWARD WIECK --------------------------------- -------------------------------- (Juanita G. Simmons, Director) (Edward Wieck, Director)
By /s/ JOHN A. BARRETT --------------------------------- (John A. Barrett, Director)
Date: March 21, 2002
IV-3
EXHIBIT INDEX
- ----------
* - Filed herewith