ADAMS RESOURCES & ENERGY, INC. - Annual Report: 2008 (Form 10-K)

form10k.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

X	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year ended December 31, 2008

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 1-7908

ADAMS RESOURCES & ENERGY, INC.

(Exact name of registrant as specified in its charter)

Delaware	74-1753147
(State of Incorporation)	(I.R.S. Employer Identification No.)

4400 Post Oak Parkway Ste. 2700
Houston, Texas	77027
(Address of Principal executive offices)	(Zip Code)

Registrant's telephone number, including area code: (713) 881-3600

Securities registered pursuant to Section 12(b) of the Act: None

Title of each class	Name of each exchange on which registered
Common Stock, $.10 Par Value	NYSE Amex

Indicate by check mark whether the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.YES ___NO _X_

Indicate by check mark whether the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.YES ____ NO _X_

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports, and (2) has been subject to the filing requirements for the past 90 days. YES_X_ NO ___

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ___X___

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer” and “accelerated filer and smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ____ Accelerated filer ____

Non-accelerated filer _X_ Smaller reporting company _____

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Act).

YES ___NO _X_

The aggregate market value of the voting and non-voting common equity held by nonaffiliates as of the close of business on June 30, 2008 was $70,944,123 based on the closing price of $33.90 per one share of common stock as reported on the NYSE AMEX Exchange for such date. A total of 4,217,596 shares of Common Stock were outstanding at March 10, 2009.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held May 27, 2009 are incorporated by reference into Part III of this report.

PART I

Items 1 and 2. BUSINESS AND PROPERTIES

Forward-Looking Statements –Safe Harbor Provisions

This annual report on Form 10-K for the year ended December 31, 2008 contains certain forward-looking statements covered by the safe harbors provided under Federal securities law and regulations. To the extent such statements are not recitations of historical fact, forward-looking statements involve risks and uncertainties. In particular, statements under the captions (a) Production and Reserve Information, (b) Regulatory Status and Potential Environmental Liability, (c) Management’s Discussion and Analysis of Financial Condition and Results of Operations, (d) Critical Accounting Policies and Use of Estimates, (e) Quantitative and Qualitative Disclosures about Market Risk, (f) Income Taxes, (g) Concentration of Credit Risk, (h) Price Risk Management Activities, and (i) Commitments and Contingencies, among others, contain forward-looking statements. Where the Company expresses an expectation or belief regarding future results of events, such expression is made in good faith and believed to have a reasonable basis in fact. However, there can be no assurance that such expectation or belief will actually result or be achieved.

With the uncertainties of forward looking statements in mind, the reader should consider the risks discussed elsewhere in this report and other documents filed with the Securities and Exchange Commission from time to time and the important factors described under “Item 1A Risk Factor” that could cause actual results to differ materially from those expressed in any forward-looking statement made by or on behalf of the Company.

Business Activities

Adams Resources & Energy, Inc. (“ARE”) and its subsidiaries collectively, (the "Company") are engaged in the business of marketing crude oil, natural gas and petroleum products; tank truck transportation of liquid chemicals; and oil and gas exploration and production. Adams Resources & Energy, Inc. is a Delaware corporation organized in 1973. The Company’s headquarters are located in 20,700 square feet of leased office space at 4400 Post Oak Parkway, Suite 2700, Houston, Texas 77027 and the telephone number of that address is (713)-881-3600. The revenues, operating results and identifiable assets of each industry segment for the three years ended December 31, 2008 are set forth in Note (9) of Notes to Consolidated Financial Statements included elsewhere herein.

Marketing Segment Subsidiaries

Gulfmark Energy, Inc. (“Gulfmark”), a subsidiary of ARE, purchases crude oil and arranges sales and deliveries to refiners and other customers. Activity is concentrated primarily onshore in Texas and Louisiana with additional operations in Michigan and New Mexico. During 2008, Gulfmark purchased approximately 67,800 barrels per day of crude oil at the wellhead or lease level. Gulfmark also operates 113 tractor-trailer rigs and maintains over 50 pipeline inventory locations or injection stations. Gulfmark has the ability to barge oil from five oil storage facilities along the intercoastal waterway of Texas and Louisiana and maintains 50,000 barrels of storage capacity at certain of the dock facilities in order to access waterborne markets for its products. Gulfmark arranges transportation for sales to customers or enters into exchange transactions with third parties when the cost of the exchange is less than the alternate cost incurred in transporting or storing the crude oil.

Adams Resources Marketing, Ltd. (“ARM”), a subsidiary of ARE, operates as a wholesale purchaser, distributor and marketer of natural gas. ARM’s focus is on the purchase of natural gas at the producer level. During 2008, ARM purchased approximately 437,000 million british thermal units (“mmbtu’s”) of natural gas per day at the wellhead and pipeline pooling points. Business is concentrated among approximately 60 independent producers with the primary production areas being the Louisiana and Texas Gulf Coast and the offshore Gulf of Mexico region. ARM provides value added services to its customers by providing access to common carrier pipelines and handling daily volume balancing requirements as well as risk management services.

Ada Resources, Inc. (“Ada”), a subsidiary of ARE, markets branded and unbranded refined petroleum products, such as motor fuels and lubricants. Ada makes purchases based on the supplier’s established distributor prices, with such prices generally being lower than Ada’s sales price to its customers. Motor fuel sales include automotive gasoline, biodiesel and conventional diesel fuel. Lubricants consist of passenger car motor oils as well as a full complement of industrial oils and greases. Ada is also involved in the railroad servicing industry, including fueling and lubricating locomotives as well as performing routine maintenance on the power units. Further, the United States Coast Guard has certified Ada as a direct-to-vessel approved marine fuel and lube vendor. In addition, Ada is approved by the Internal Revenue Service as a Certified Biodiesel Blender, which provides enhanced margin opportunities. Ada’s marketing area primarily includes the Texas Gulf Coast and southern Louisiana. The primary product distribution and warehousing facility is located on 5.5 Company-owned acres in Houston, Texas. The property includes a 60,000 square foot warehouse, 11,000 square feet of office space and bulk storage for 320,000 gallons of lubricating oil.

Operating results are sensitive to a number of factors. Such factors include commodity location, grades of product, individual customer demand for grades or location of product, localized market price structures, availability of transportation facilities, actual delivery volumes that vary from expected quantities and, the timing and costs to deliver the commodity to the customer.

Transportation Segment Subsidiary

Service Transport Company (“STC”), a subsidiary of ARE, transports liquid chemicals on a "for hire" basis throughout the continental United States and Canada. Transportation service is provided to over 400 customers under multiple load contracts in addition to loads covered under STC’s standard price list. Pursuant to regulatory requirements, STC holds a Hazardous Materials Certificate of Registration issued by the U.S. Department of Transportation. Presently, STC operates 318 truck tractors of which 40 are independent owner-operator units. STC also maintains 428 tank trailers. In addition, STC maintains truck terminals in Houston, Corpus Christi, and Nederland, Texas as well as Baton Rouge (St. Gabriel), Louisiana and Mobile (Saraland), Alabama. Transportation operations are headquartered at a terminal facility situated on 22 Company-owned acres in Houston, Texas. This property includes maintenance facilities, an office building, tank wash rack facilities and a water treatment system. The St. Gabriel, Louisiana terminal is situated on 11.5 Company-owned acres and includes an office building, maintenance bays and tank cleaning facilities.

STC is compliant with International Organization for Standardization (“ISO”) 9001:2000 Standard. The scope of this Quality System Certificate covers the carriage of bulk liquids throughout STC’s area of operations as well as the tank trailer cleaning facilities and equipment maintenance. STC’s quality management process is one of its major assets. The practice of using statistical process control covering safety, on-time performance and customer satisfaction aids continuous improvement in all areas of quality service. In addition to its ISO 9001:2000 practices, the American Chemistry Council recognizes STC as a Responsible CareÓ Partner. Responsible Care Partners serve the chemical industry and implement and monitor the seven Codes of Management Practices. The seven codes address compliance and continuing improvement in (1) Community Awareness and Emergency Response, (2) Pollution Prevention, (3) Process Safety, (4) Distribution, (5) Employee Health and Safety, (6) Product Stewardship and (7) Security.

Oil and Gas Segment Subsidiary

Adams Resources Exploration Corporation (“AREC”), a subsidiary of ARE, is actively engaged in the exploration and development of domestic oil and natural gas properties primarily along the Louisiana and Texas Gulf Coast. Exploration offices are maintained at the Company's headquarters in Houston and the Company holds an interest in 323 wells of which 39 are Company operated.

Producing Wells--The following table sets forth the Company's gross and net productive wells as of December 31, 2008. Gross wells are the total number of wells in which the Company has an interest, while net wells are the sum of the fractional interests owned.

	Oil Wells				Gas Wells				Total Wells
	Gross		Net		Gross		Net		Gross		Net
Texas		56		8.07		106		11.58		162		19.65
Louisiana		11		.62		24		1.12		35		1.74
Other		85		3.85		41		4.78		126		8.63
		152		12.54		171		17.48		323		30.02

Acreage--The following table sets forth the Company's gross and net developed and undeveloped acreage as of December 31, 2008. Gross acreage represents the Company’s direct ownership and net acreage represents the sum of the fractional interests owned. The Company’s developed acreage is held by current production while undeveloped acreage is held by oil and gas leases with various remaining terms from six months to three years.

	Developed Acreage				Undeveloped Acreage
	Gross		Net		Gross		Net
Texas		73,373		12,396		168,960		16,433
Louisiana		5,072		282		1,082		145
Kansas		-		-		31,334		3,133
Other		4,226		718		2,368		1,206
		82,671		13,396		203,744		20,917

Drilling Activity--The following table sets forth the Company's drilling activity for each of the three years ended December 31, 2008. All drilling activity was onshore in Texas, Louisiana and Alabama.

	2008				2007				2006
	Gross		Net		Gross		Net		Gross		Net
Exploratory wells drilled
- Productive		2		.13		3		.15		6		.52
- Dry		2		.22		2		.10		3		.35

Development wells drilled
- Productive		17		1.06		18		1.37		26		1.89
- Dry		7		.68		6		.35		2		.08

Production and Reserve Information--The Company's estimated net quantities of proved oil and natural gas reserves and the standardized measure of discounted future net cash flows calculated at a 10% discount rate for the three years ended December 31, 2008, are presented in the table below (in thousands):

	December 31,
	2008		2007		2006
Crude oil (barrels)		230		297		396
Natural gas (mcf)		6,443		7,068		8,300
Standardized measure of discounted future
net cash flows from oil and gas reserves	$	11,547	$	19,590	$	18,770

The estimated value of oil and natural gas reserves and future net revenues from oil and natural gas reserves was made by the Company's independent petroleum engineers. The reserve value estimates provided at each of December 31, 2008, 2007 and 2006 are based on year-end market prices of $37.87, $92.50 and $57.00 per barrel for crude oil and $5.65, $7.31 and $5.58 per mcf for natural gas, respectively.

Reserve estimates are based on many subjective factors. The accuracy of reserve estimates depends on the quantity and quality of geological data, production performance data, the current prices being received and reservoir engineering data, as well as the skill and judgment of petroleum engineers in interpreting such data. The process of estimating reserves requires frequent revision of estimates (usually on an annual basis) as additional information is made available through drilling, testing, reservoir studies and acquiring historical pressure and production data. In addition, the discounted present value of estimated future net revenues should not be construed as the fair market value of oil and natural gas producing properties. Such estimates do not necessarily portray a realistic assessment of current value or future performance of such properties. Such revenue calculations are based on estimates as to the timing of oil and natural gas production, and there is no assurance that the actual timing of production will conform to or approximate such estimates. Also, certain assumptions have been made with respect to pricing. The estimates assume prices will remain constant from the date of the engineer's estimates, except for changes reflected under natural gas sales contracts. There can be no assurance that actual future prices will not vary as industry conditions, governmental regulation and other factors impact the market price for oil and natural gas.

The Company's oil and natural gas production for the three years ended December 31, 2008 was as follows:

Years Ended	Crude Oil		Natural
December 31,	(barrels)		Gas (mcf)
2008		50,500		1,243,000
2007		69,250		1,182,000
2006		75,900		1,604,000

Certain financial information relating to the Company's oil and natural gas division is summarized as follows:

	Years Ended December 31,
	2008		2007		2006
Average oil and condensate
sales price per barrel	$	99.25	$	70.21	$	64.26
Average natural gas
sales price per mcf	$	9.84	$	7.54	$	7.53
Average production cost, per equivalent
barrel, charged to expense	$	18.34	$	15.32	$	12.40

North Sea Exploration Licenses-- In the United Kingdom’s Central Sector of the North Sea, the Company previously held an undivided 30 percent working interest in Blocks 21-1b, 21-2b and 21-3d. These Blocks are located approximately 200 miles east of Aberdeen, Scotland not far from the Forties and Buchan Fields. Together with its joint interest partners, the Company obtained its interests through the United Kingdom’s “Promote License” program and the license was awarded in February 2007. A Promote License affords the opportunity to analyze and assess the licensed acreage for an initial two-year period without the stringent financial requirements of the more traditional Exploration License. The Company’s investment group was unsuccessful in obtaining a partner to fund these two projects and therefore both were dropped at no additional cost to the Company. The Company also held an approximate nine percent equity interest in a promote licensing right to Block 42-27b located in the Southern Sector of the U. K. North Sea. The Company continues to seek a partner to drill the first exploration well on the Block 42-27b acreage. The licensing rights to this acreage were due to expire in March 2009 but the Company has requested an extension of the license through November 2009.

The Company has had no reports to federal authorities or agencies of estimated oil and gas reserves except for a required report on the United States Department of Energy’s “Annual Survey of Domestic Oil and Gas Reserves.” The Company is not obligated to provide any fixed and determinable quantities of oil or gas in the future under existing contracts or agreements associated with its oil and gas exploration and production segment.

Reference is made to Note (11) of the Notes to Consolidated Financial Statements for additional disclosures relating to oil and natural gas exploration and production activities.

Environmental Compliance and Regulation

The Company is subject to an extensive variety of evolving United States federal, state and local laws, rules and regulations governing the storage, transportation, manufacture, use, discharge, release and disposal of product and contaminants into the environment, or otherwise relating to the protection of the environment. Presented below is a non-exclusive listing of the environmental laws that potentially impact the Company’s activities.

-	The Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, as amended.

-	Comprehensive Environmental Response, Compensation and Liability Act of 1980 ("CERCLA" or "Superfund"), as amended.

-	The Clean Water Act of 1972, as amended.

-	Federal Oil Pollution Act of 1990, as amended.

-	The Clean Air Act of 1970, as amended.

-	The Toxic Substances Control Act of 1976, as amended.

-	The Emergency Planning and Community Right-to-Know Act.

-	The Occupational Safety and Health Act of 1970, as amended.

-	Texas Clean Air Act.

-	Texas Solid Waste Disposal Act.

-	Texas Water Code.

-	Texas Oil Spill Prevention and Response Act of 1991, as amended.

Railroad Commission of Texas (“RRC”)--The RRC regulates, among other things, the drilling and operation of oil and natural gas wells, the operation of oil and gas pipelines, the disposal of oil and natural gas production wastes and certain storage of unrefined oil and gas. RRC regulations govern the generation, management and disposal of waste from such oil and natural gas operations and provide for the clean up of contamination from oil and natural gas operations. The RRC has promulgated regulations that provide for civil and/or criminal penalties and/or injunctive relief for violations of the RRC regulations.

Louisiana Office of Conservation--This agency has primary statutory responsibility for regulation and conservation of oil, gas, and other natural resources in the State of Louisiana. Their objectives are to (i) regulate the exploration and production of oil, natural gas and other hydrocarbons; (ii) control and allocate energy supplies and distribution; and (iii) protect public safety and the State’s environment from oilfield waste, including regulation of underground injection and disposal practices.

State and Local Government Regulation--Many states are authorized by the United States Environmental Protection Agency (“EPA”) to enforce regulations promulgated under various federal statutes. In addition, there are numerous other state and local authorities that regulate the environment, some of which impose more stringent environmental standards than federal laws and regulations. The penalties for violations of state law vary, but typically include injunctive relief, recovery of damages for injury to air, water or property and fines for non-compliance.

Oil and Gas Operations--The Company's oil and gas drilling and production activities are subject to laws and regulations relating to environmental quality and pollution control. One aspect of the Company's oil and gas operation is the disposal of used drilling fluids, saltwater, and crude oil sediments. In addition, low-level naturally occurring radiation may, at times, occur with the production of crude oil and natural gas. The Company's policy is to comply with environmental regulations and industry standards. Environmental compliance has become more stringent and the Company, from time to time, may be required to remediate past practices. Management believes that such required remediation in the future, if any, will not have a material adverse impact on the Company's financial position or results of operations.

All states in which the Company owns producing oil and gas properties have statutory provisions regulating the production and sale of crude oil and natural gas. Regulations typically require permits for the drilling of wells and regulate the spacing of wells, the prevention of waste, protection of correlative rights, the rate of production, prevention and clean-up of pollution and other matters.

Marketing Operations--The Company's marketing facilities are subject to a number of state and federal environmental statutes and regulations, including the regulation of underground fuel storage tanks. While the Company does not own or operate underground tanks as of December 31, 2008, historically, the Company has been an owner and operator of underground storage tanks. The EPA's Office of Underground Tanks and applicable state laws establish regulations requiring owners or operators of underground fuel tanks to demonstrate evidence of financial responsibility for the costs of corrective action and the compensation of third parties for bodily injury and property damage caused by sudden and non-sudden accidental releases arising from operating underground tanks. In addition, the EPA requires the installation of leak detection devices and stringent monitoring of the ongoing condition of underground tanks. Should leakage develop in an underground tank, the operator is obligated for clean up costs. During the period when the Company was an operator of underground tanks, it secured insurance covering both third party liability and clean up costs.

Transportation Operations--The Company's tank truck operations are conducted pursuant to authority of the United States Department of Transportation (“DOT”) and various state regulatory authorities. The Company's transportation operations must also be conducted in accordance with various laws relating to pollution and environmental control. Interstate motor carrier operations are subject to safety requirements prescribed by DOT. Matters such as weight and dimension of equipment are also subject to federal and state regulations. DOT regulations also require mandatory drug testing of drivers and require certain tests for alcohol levels in drivers and other safety personnel. The trucking industry is subject to possible regulatory and legislative changes such as increasingly stringent environmental regulations or limits on vehicle weight and size. Regulatory change may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. In addition, the Company’s tank wash facilities are subject to increasingly stringent local, state and federal environmental regulations.

The Company has implemented security procedures for drivers and terminal facilities. Satellite tracking transponders installed in the power units are used to communicate en route emergencies to the Company and to maintain constant information as to the unit’s location. If necessary, the Company’s terminal personnel will notify local law enforcement agencies. In addition, the Company is able to advise a customer of the status and location of their loads. Remote cameras and better lighting coverage in the staging and parking areas have augmented terminal security.

Regulatory Status and Potential Environmental Liability--The operations and facilities of the Company are subject to numerous federal, state and local environmental laws and regulations including those described above, as well as associated permitting and licensing requirements. The Company regards compliance with applicable environmental regulations as a critical component of its overall operation, and devotes significant attention to providing quality service and products to its customers, protecting the health and safety of its employees, and protecting the Company’s facilities from damage. Management believes the Company has obtained or applied for all permits and approvals required under existing environmental laws and regulations to operate its current business. Management has reported that the Company is not subject to any pending or threatened environmental litigation or enforcement action(s), which could materially and adversely affect the Company's business. The Company has, where appropriate, implemented operating procedures at each of its facilities designed to assure compliance with environmental laws and regulation. However, given the nature of the Company’s business, the Company is subject to environmental risks and the possibility remains that the Company's ownership of its facilities and its operations and activities could result in civil or criminal enforcement and public as well as private action(s) against the Company, which may necessitate or generate mandatory clean up activities, revocation of required permits or licenses, denial of application for future permits, and/or significant fines, penalties or damages, any and all of which could have a material adverse effect on the Company. At December 31, 2008, the Company is unaware of any unresolved environmental issues for which additional accounting accruals are necessary.

Employees

At December 31, 2008 the Company employed 806 persons, 14 of whom were employed in the exploration and production of oil and gas, 312 in the marketing of crude oil, natural gas and petroleum products, 457 in transportation operations, and 23 in administrative capacities. None of the Company's employees are represented by a union. Management believes its employee relations are satisfactory.

Federal and State Taxation

The Company is subject to the provisions of the Internal Revenue Code of 1986, as amended (the “Code”). In accordance with the Code, the Company computes its income tax provision based on a 35 percent tax rate. The Company's operations are, in large part, conducted within the State of Texas. Texas operations are subject to a one-half percent state tax on its revenues net of cost of goods sold as defined by the state. Oil and gas activities are also subject to state and local income, severance, property and other taxes. Management believes the Company is currently in compliance with all federal and state tax regulations.

Available Information

As a public company, the Company is required to file periodic reports, as well as other information, with the Securities and Exchange Commission (“SEC”) within established deadlines. Any document filed with the SEC may be viewed or copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Additional information regarding the Public Reference Room can be obtained by calling the SEC at (800) SEC-0330. The Company’s SEC filings are also available to the public through the SEC’s web site located at http://www.sec.gov.

The Company maintains a corporate website at http://www.adamsresources.com, on which investors may access free of charge the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as is reasonably practicable after filing or furnishing such material with the SEC. Additionally, the Company has adopted and posted on its website a Code of Business Ethics designed to reflect requirements of the Sarbanes-Oxley Act of 2002, NYSE Amex Exchange rules and other applicable laws, rules and regulations. The Code of Business Ethics applies to all of the Company’s directors, officers and employees. Any amendment to the Code of Business Ethics will be posted promptly on the Company’s website. The information contained on or accessible from the Company’s website does not constitute a part of this report and is not incorporated by reference herein. The Company will also provide a printed copy of any of these aforementioned documents free of charge upon request by calling ARE at (713)-881-3600 or by writing to:

Adams Resources & Energy, Inc.

ATTN: Richard B. Abshire

4400 Post Oak Parkway, Suite 2700

Houston, Texas 77027

Item 1A RISK FACTORS

Worldwide economic developments could damage operations and materially reduce profitability and cash flows.

Recent disruptions in the credit markets and concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices, both of which may have contributed to a decline in the Company’s stock price and corresponding market capitalization. Further commodity price decreases during 2009 could result in reduced earnings. Since the Company has no bank debt obligations nor covenants tied to its stock price, potential declines in the Company’s stock price do not affect the Company’s liquidity or overall financial condition. Should the capital and credit markets continue to experience volatility and the availability of funds remains limited, the Company’s customers and suppliers may incur increased costs associated with issuing commercial paper and/or other debt instruments and this, in turn, could adversely affect the Company’s ability to secure supply and make profitable sales.

General economic conditions could reduce demand for chemical based trucking services.

Customer demand for the Company’s products and services is substantially dependent upon the general economic conditions for the United States which have deteriorated in the last several months and continue to be challenging. In particular, demand for liquid chemical truck transportation services is dependent on activity within the petrochemical sector of the U. S. economy. Chemical sector demand typically varies with the housing and auto markets as well as the relative strength of the U. S. dollar to foreign currencies. A relatively weak U.S. dollar exchange rate as currently exists, tends to suppress export demand for petrochemicals which is adverse to the Company’s transportation operation.

The Company’s business is dependent on the ability to obtain trade and other credit.

The Company’s future development and growth depends in part on its ability to successfully obtain credit from suppliers and other parties. Credit arrangements are relied upon as a significant source of liquidity for capital requirements not satisfied by operating cash flow.

Recently, global financial markets and economic conditions have been, and may continue to be, disrupted and volatile. As a result of concerns about the stability of financial markets generally and the solvency of creditors specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt on terms similar to current debt and in some cases, ceased to provide funding to borrowers. These issues, along with significant write-offs in the financial services sector and the current weak economic conditions have made, and may continue to make, it more difficult for the Company and its suppliers and customers to obtain funding.

If the Company is unable to obtain trade or other forms credit on reasonable and competitive terms, its ability to continue its marketing and exploration businesses, pursue improvements, and continue future growth will be limited. There is no assurance that the Company will be able to maintain future credit arrangements on commercially reasonable terms.

The financial soundness of customers could affect our business and operating results

As a result of the disruptions in the financial markets and other macro-economic challenges currently affecting the economy of the United States and other parts of the world, the Company’s customers may experience cash flow concerns. As a result, if customers’ operating and financial performance deteriorates, or if they are unable to make scheduled payments or obtain credit, customers may not be able to pay, or may delay payment of, accounts receivable owed to the Company. Any inability of current and/or potential customers to pay for services may adversely affect the Company’s financial condition and results of operations.

Counterparty credit default could have an adverse effect on the Company.

The Company’s revenues are generated under contracts with various counterparties. Results of operations would be adversely affected as a result of non-performance by any of these counterparties of their contractual obligations under the various contracts. A counterparty’s default or non-performance could be caused by factors beyond the Company’s control. A default could occur as a result of circumstances relating directly to the counterparty, or due to circumstances caused by other market participants having a direct or indirect relationship with such counterparty. The Company seeks to mitigate the risk of default by evaluating the financial strength of potential counterparties; however, despite mitigation efforts, defaults by counterparties may occur from time to time.

Fluctuations in oil and gas prices could have an effect on the Company.

The Company’s future financial condition, revenues, results of operations and future rate of growth are materially affected by oil and natural gas prices. Oil and natural gas prices historically have been volatile and are likely to continue to be volatile in the future. Moreover, oil and natural gas prices depend on factors outside the control of the Company. These factors include:

·	supply and demand for oil and gas and expectations regarding supply and demand;

·	political conditions in other oil-producing countries, including the possibility of insurgency or war in such areas;

·	economic conditions in the United States and worldwide;

·	governmental regulations and taxation;

·	impact of energy conservation efforts;

·	the price and availability of alternative fuel sources;

·	weather conditions;

·	availability of local, interstate and intrastate transportation systems; and

·	market uncertainty.

Revenues are generated under contracts that must be renegotiated periodically.

Substantially all of the Company’s revenues are generated under contracts which expire periodically or which must be frequently renegotiated, extended or replaced. Whether these contracts are renegotiated, extended or replaced is often times subject to factors beyond the Company’s control. Such factors include sudden fluctuations in oil and gas prices, counterparty ability to pay for or accept the contracted volumes and, most importantly, an extremely competitive marketplace for the services offered by the Company. There is no assurance that the costs and pricing of the Company’s services can remain competitive in the marketplace or that the Company will be successful in renegotiating its contracts.

Anticipated or scheduled volumes will differ from actual or delivered volumes.

The Company’s crude oil and natural gas marketing operation purchases initial production of crude oil and natural gas at the wellhead under contracts requiring the Company to accept the actual volume produced. The resale of such production is generally under contracts requiring a fixed volume to be delivered. The Company estimates its anticipated supply and matches such supply estimate for both volume and pricing formulas with committed sales volumes. Since actual wellhead volumes produced will never equal anticipated supply, the Company’s marketing margins may be adversely impacted. In many instances, any losses resulting from the difference between actual supply volumes compared to committed sales volumes must be absorbed by the Company.

Environmental liabilities and environmental regulations may have an adverse effect on the Company.

The Company’s business is subject to environmental hazards such as spills, leaks or any discharges of petroleum products and hazardous substances. These environmental hazards could expose the Company to material liabilities for property damage, personal injuries and/or environmental harms, including the costs of investigating and rectifying contaminated properties.

Environmental laws and regulations govern many aspects of the Company’s business, such as drilling and exploration, production, transportation and waste management. Compliance with environmental laws and regulations can require significant costs or may require a decrease in production. Moreover, noncompliance with these laws and regulations could subject the Company to significant administrative, civil and/or criminal fines and/or penalties.

Operations could result in liabilities that may not be fully covered by insurance.

The oil and gas business involves certain operating hazards such as well blowouts, explosions, fires and pollution. Any of these operating hazards could cause serious injuries, fatalities or property damage, which could expose the Company to liability. The payment of any of these liabilities could reduce, or even eliminate, the funds available for exploration, development, and acquisition, or could result in a loss of the Company’s properties and may even threaten survival of the enterprise.

Consistent with the industry standard, the Company’s insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences. Insurance might be inadequate to cover all liabilities. Moreover, from time to time, obtaining insurance for the Company’s line of business can become difficult and costly. Typically, when insurance cost escalates, the Company may reduce its level of coverage and more risk may be retained to offset cost increases. If substantial liability is incurred and damages are not covered by insurance or exceed policy limits, the Company’s operation and financial condition could be materially adversely affected.

Changes in tax laws or regulations could adversely affect the Company.

The Internal Revenue Service, the United States Treasury Department and Congress frequently review federal income tax legislation. The Company cannot predict whether, when or to what extent new federal tax laws, regulations, interpretations or rulings will be adopted. Any such legislative action may prospectively or retroactively modify tax treatment and, therefore, may adversely affect taxation of the Company.

The Company’s business is subject to changing government regulations.

Federal, state or local government agencies may impose environmental, labor or other regulations that increase costs and/or terminate or suspend operations. The Company’s business is subject to federal, state and local laws and regulations. These regulations relate to, among other things, the exploration, development, production and transportation of oil and natural gas. Existing laws and regulations could be changed, and any changes could increase costs of compliance and costs of operations.

Estimating reserves, production and future net cash flow is difficult.

Estimating oil and natural gas reserves is a complex process that involves significant interpretations and assumptions. It requires interpretation of technical data and assumptions relating to economic factors such as future commodity prices, production costs, severance and excise taxes, capital expenditures and remedial costs, and the assumed effect of governmental regulation. As a result, actual results may differ from our estimates. Also, the use of a 10 percent discount factor for reporting purposes, as prescribed by the SEC, may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which the Company’s business is subject. Any significant variations from the Company’s estimates could cause the estimated quantities and net present value of the Company’s reserves to differ materially.

The reserve data included in this report is only an estimate. The reader should not assume that the present values referred to in this report represent the current market value of the Company’s estimated oil and natural gas reserves. The timing of the production and the expenses from development and production of oil and natural gas properties will affect both the timing of actual future net cash flows from the Company’s proved reserves and their present value.

The Company’s business is dependent on the ability to replace reserves.

Future success depends in part on the Company’s ability to find, develop and acquire additional oil and natural gas reserves. Without successful acquisition or exploration activities, reserves and revenues will decline as a result of current reserves being depleted by production. The successful acquisition, development or exploration of oil and natural gas properties requires an assessment of recoverable reserves, future oil and natural gas prices and operating costs, potential environmental and other liabilities, and other factors. These assessments are necessarily inexact. As a result, the Company may not recover the purchase price of a property from the sale of production from the property, or may not recognize an acceptable return from properties acquired. In addition, exploration and development operations may not result in any increases in reserves. Exploration or development may be delayed or canceled as a result of inadequate capital, compliance with governmental regulations or price controls or mechanical difficulties. In the future, the cost to find or acquire additional reserves may become unacceptable.

Fluctuations in commodity prices could have an adverse effect on the Company.

Revenues depend on volumes and rates, both of which can be affected by the prices of oil and natural gas. Decreased prices could result in a reduction of the volumes purchased or transported by the Company’s customers. The success of the Company’s operations is subject to continued development of additional oil and natural gas reserves. A decline in energy prices could precipitate a decrease in these development activities and could cause a decrease in the volume of reserves available for processing and transmission. Fluctuations in energy prices are caused by a number of factors, including:

·	regional, domestic and international supply and demand;

·	availability and adequacy of transportation facilities;

·	energy legislation;

·	federal and state taxes, if any, on the sale or transportation of natural gas;

·	abundance of supplies of alternative energy sources;

·	political unrest among oil producing countries; and

·	opposition to energy development in environmentally sensitive areas.

Revenues are dependent on the ability to successfully complete drilling activity.

Drilling and exploration are one of the main methods of replacing reserves. However, drilling and exploration operations may not result in any increases in reserves for various reasons. Drilling and exploration may be curtailed, delayed or cancelled as a result of:

·	lack of acceptable prospective acreage;

·	inadequate capital resources;

weather;

·	title problems;

·	compliance with governmental regulations; and

·	mechanical difficulties.

Moreover, the costs of drilling and exploration may greatly exceed initial estimates. In such a case, the Company would be required to make additional expenditures to develop its drilling projects. Such additional and unanticipated expenditures could adversely affect the Company’s financial condition and results of operations.

Security issues related to drivers and terminal facilities

The Company transports liquid combustible materials such as gasoline and petrochemicals. Such materials may be a target for terrorist attacks. The Company employs a variety of security measures to mitigate the risk of such events.

Current and future litigation could have an adverse effect on the Company.

The Company is currently involved in several administrative and civil legal proceedings in the ordinary course of its business. Moreover, as incidental to operations, the Company sometimes becomes involved in various lawsuits and/or disputes. Lawsuits and other legal proceedings can involve substantial costs, including the costs associated with investigation, litigation and possible settlement, judgment, penalty or fine. Although insurance is maintained to mitigate these costs, there can be no assurance that costs associated with lawsuits or other legal proceedings will not exceed the limits of insurance policies. The Company’s results of operations could be adversely affected if a judgment, penalty or fine is not fully covered by insurance.

Item 1B UNRESOLVED STAFF COMMENTS

None.

Item 3. LEGAL PROCEEDINGS

From time to time as incident to its operations, the Company may become involved in various lawsuits and/or disputes. Primarily as an operator of an extensive trucking fleet, the Company is a party to motor vehicle accidents, worker compensation claims and other items of general liability as would be typical for the industry. Management of the Company is presently unaware of any claims against the Company that are either outside the scope of insurance coverage, or that may exceed the level of insurance coverage, and could potentially represent a material adverse effect on the Company’s financial position or results of operations.

Item 4. SUBMISSION OF MATTER TO A VOTE OF SECURITY HOLDERS

None.

PART II

Item 5.

MARKET FOR THE REGISTRANT'S COMMON STOCK, RELATED SECURITY HOLDER MATTERS AND ISSUER REPURCHASE OF EQUITY SECURITIES

The Company's common stock is traded on the NYSE Amex Exchange. The following table sets forth the high and low sales prices of the common stock as reported by the American Stock Exchange for each calendar quarter since January 1, 2007.

	American Stock Exchange
	High		Low
2007
First Quarter	$	40.85	$	26.95
Second Quarter		41.40		27.91
Third Quarter		30.65		20.06
Fourth Quarter		32.85		24.29

2008
First Quarter	$	28.65	$	22.00
Second Quarter		35.35		26.35
Third Quarter		34.95		22.32
Fourth Quarter		23.00		13.55

At March 9, 2009, there were approximately 265 shareholders of record of the Company's common stock and the closing stock price was $13.45 per share. The Company has no securities authorized for issuance under equity compensation plans. The Company made no repurchases of its stock during 2008 and 2007.

On December 16, 2008, the Company paid an annual cash dividend of $.50 per common share to common stockholders of record on December 2, 2008. On December 17, 2007, the Company paid an annual cash dividend of $.47 per common share to common stockholders of record on December 3, 2007. Such dividends totaled $2,108,798 and $1,982,129 for each of 2008 and 2007, respectively.

The terms of the Company's bank loan agreement require the Company to maintain consolidated net worth in excess of $60,909,000. 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.

Performance Graph

The performance graph shown below was prepared under the applicable rules of the SEC based on data supplied by Standard & Poor’s Compustat. The purpose of the graph is to show comparative total stockholder returns for the Company versus other investment options for a specified period of time. The graph was prepared based upon the following assumptions:

1.	$100.00 was invested on December 31, 2003 in the Company’s common stock, the S&P 500 Index, and the S&P 500 Integrated Oil and Gas Index.

2.	Dividends are reinvested on the ex-dividend dates.

Note: The stock price performance shown on the graph below is not necessarily indicative of future price performance.

Total Return To Shareholders

(Includes reinvestment of dividends)

		INDEXED RETURNS
	Base	Years Ending
	Period
Company / Index	Dec03	Dec04	Dec05	Dec06	Dec07	Dec08
Adams Resources & Energy, Inc.	100	132.38	174.27	232.92	202.56	138.45
S&P 500 Index	100	110.88	116.33	134.70	142.10	89.53
S&P 500 Integrated Oil & Gas Index	100	128.83	151.55	204.33	265.33	207.51

Item 6. SELECTED FINANCIAL DATA

FIVE YEAR REVIEW OF SELECTED FINANCIAL DATA

	Years Ended December 31,
	2008			2007			2006			2005			2004
Revenues:	(In thousands, except per share data)
Marketing	$	4,074,677		$	2,558,545		$	2,167,502		$	2,292,029		$	2,010,968
Transportation		67,747			63,894			62,151			57,458			47,323
Oil and gas		17,248			13,783			16,950			15,346			10,796
	$	4,159,672		$	2,636,222		$	2,246,603		$	2,364,833		$	2,069,087
Operating Earnings:
Marketing	$	(2,704	)	$	20,152		$	12,975		$	22,481		$	13,597
Transportation		4,245			5,504			5,173			5,714			5,687
Oil and gas operations		(3,348	)		(2,853	)		5,355			6,765			2,362
Oil and gas property sale		-			12,078			-			-			-
General and administrative		(9,667	)		(10,974	)		(8,536	)		(9,668	)		(7,867	)
		(11,474	)		23,907			14,967			25,292			13,779
Other income (expense):
Interest income		1,103			1,741			965			188			62
Interest expense		(187	)		(134	)		(159	)		(128	)		(107	)
Earnings (loss) from continuing operations
before income taxes		(10,558	)		25,514			15,773			25,352			13,734

Income tax benefit (provision)		4,986			(8,458	)		(5,290	)		(8,583	)		(4,996	)

Earnings (loss) from continuing operations		(5,572	)		17,056			10,483			16,769			8,738
Earnings (loss) from discontinued
operations, net of taxes		-			-			-			872			(130	)
Net earnings (loss)	$	(5,572	)	$	17,056		$	10,483		$	17,641		$	8,608

Earnings (Loss) Per Share
From continuing operations	$	(1.32	)	$	4.04		$	2.49		$	3.97		$	2.07
From discontinued operations		-			-			-			.21			(.03	)

Basic earnings (loss) per share	$	(1.32	)	$	4.04		$	2.49		$	4.18		$	2.04

Dividends per common share	$	.50		$	.47		$	.42		$	.37		$	.30

Financial Position

Working capital	$	41,559		$	50,572		$	35,208		$	39,321		$	35,789
Total assets		210,926			357,075			289,287			312,662			238,854
Long-term debt, net of
current maturities		-			-			3,000			11,475			11,475
Shareholders’ equity		81,761			89,442			74,368			65,656			49,575
Dividends on common shares		2,109			1,982			1,771			1,560			1,265

________________________________

Notes:

-	In 2007, certain oil and natural gas producing properties were sold for $14.9 million producing a net gain of $12.1 million.

Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Results of Operations

- Marketing

Marketing revenues, operating earnings and depreciation are as follows (in thousands):

	2008			2007			2006
Revenues
Crude oil	$	3,849,531		$	2,373,838		$	1,975,972
Natural gas		11,586			13,764			13,621
Refined products		213,560			170,943			177,909
Total	$	4,074,677		$	2,558,545		$	2,167,502

Operating Earnings (loss)
Crude oil	$	(4,545	)	$	15,321		$	5,088
Natural gas		2,247			4,999			6,558
Refined products		(406	)		(168	)		1,329
Total	$	(2,704	)	$	20,152		$	12,975

Depreciation
Crude oil	$	2,039		$	657		$	857
Natural gas		163			162			59
Refined products		565			457			428
Total	$	2,767		$	1,276		$	1,344

Supplemental volume and price information is:

	2008	2007	2006

Field Level Purchases per day (1)
- Crude Oil	67,800 bbls	61,500 bbls	61,800 bbls
- Natural Gas	437,000 mmbtu	423,000 mmbtu	354,000 mmbtu

Average Purchase Price
- Crude Oil	$ 99.72/bbl	$ 70.70/bbl	$ 62.40/bbl
- Natural Gas	$ 8.63/mmbtu	$ 6.79/mmbtu	$ 6.62/mmbtu

(1) Reflects the volume purchased from third parties at the oil and natural gas field level and pipeline pooling points.

Comparison 2008 to 2007 –

Crude oil revenues increased by 62 percent in the current year due to significantly increased commodity prices during major portions of the year. The Company’s monthly average crude oil acquisition price rose from the $91 per barrel level at year-end 2007 to the $133 per barrel level in June 2008 with a subsequent steep decline beginning in August 2008 to the $41 per barrel range by year-end. The effect of fluctuating prices was to cause inventory liquidation gains during the first half of 2008 as prices increased, with inventory liquidation and valuation losses occurring during the second half of 2008 as the market price declined. Net inventory driven losses for 2008 were $11.8 million. In contrast, rising prices produced $4.3 million of inventory liquidation gains in 2007. The Company’s inventory holdings result from shipments in transit and as of December 31, 2008, the Company held 285,919 barrels of inventory valued at an average price of $41.06 per barrel.

Excluding the impact of inventory values as described above, crude oil operating earnings for 2008 and 2007 would have been $7,338,000 and $11,021,000, respectively. Absent the inventory items, crude oil earnings from operations were reduced in 2008 as a result of escalated prices for the diesel fuel consumed in the trucking function of this business. Diesel fuel expense was $7.3 million in 2008 compared to $4.3 million for 2007.

Natural gas sales are reported net of underlying natural gas purchase costs and thus reflect margins before operating costs. As shown above, such margins were reduced in 2008 relative to 2007 as the 2008 marketplace did not provide a normal level of opportunities to enhance margins by meeting short-term day-to-day demand needs. Such conditions existed, in part from 2008 weather patterns not stimulating localized demand spikes. Excluding temporary volume reductions caused by third quarter 2008 hurricane activity in the Gulf of Mexico, the Company continues to add purchase volumes while still attempting to enhance per unit margins.

Refined products revenues increased during 2008 consistent with increased commodity prices partially offset by reduced volumes as the Company reduced its sales activity to less credit worthy accounts. Refined product driven operating earnings were reduced during 2008 because of an increased allowance for doubtful accounts receivable through a bad debt charge of $700,000. The Company has a number of construction industry customers that experienced significantly increased fuel costs coupled with a downturn in the housing development market. With an elevated likelihood of this class of customer experiencing financial insolvency, the Company’s bad debt provision was increased accordingly.

Historically, prices received for crude oil, natural gas and refined products have been volatile and unpredictable with price volatility expected to continue. See also discussion under Item 3 – Commodity Price Risk.

-	Comparison 2007 to 2006 –

Crude oil revenues increased during 2007 relative to 2006 due to higher commodity prices as reflected above. Crude oil operating earnings improved in 2007 relative to 2006 because of the $4.3 million in inventory liquidation gains coupled with improved end-market pricing received from the Company’s customers relative to crude oil acquisition costs. The year 2007 also benefited from a $1,960,906 reduction in operating expenses from the reversal of certain previously recorded accrual items following a negotiated settlement of disputed amounts. During 2006, crude oil prices fluctuated from periods of increasing prices to periods of decreasing prices with little affect on full year results. Natural gas operating earnings were reduced in 2007 relative to 2006 due to increased transportation and salary costs.

Refined product revenues were reduced in 2007 despite increased commodity prices for gasoline and diesel fuel. Motor fuel sales volumes for 2007 were reduced due to a heightened competitive marketplace and weather related reductions in construction demand. Coupled with escalating fuel and wage costs, the competitive picture in 2007 produced an operating loss for the Company’s refined products business.

- Transportation

The transportation segment revenues and operating earnings were as follows (in thousands):

	2008					2007					2006
	Amount		Change(1)			Amount		Change(1)			Amount		Change(1)

Revenues	$	67,747		6	%	$	63,894		3	%	$	62,151		8	%

Operating earnings	$	4,245		(23	)%	$	5,504		6	%	$	5,173		(9	)%

Depreciation	$	3,843		(10	)%	$	4,275		(6	)%	$	4,538		45	%

______________

(1)	Represents the percentage increase (decrease) from the prior year.

-	Comparison 2008 to 2007

Transportation revenues include various component parts, the most significant being standard line haul charges, fuel adjustment charges and demurrage. Line haul revenues declined slightly during 2008 to $48.3 million versus $49.2 million in 2007 as demand for the Company’s services generally remained consistent. Fuel adjustment billings increased to $12.6 million in 2008 compared to $7.6 million in 2007 for comparative additional 2008 revenue of $5 million. However, actual fuel expense incurred increased by $5.6 million during 2008 to $17.1 million. The partial inability to fully pass along fuel increases coupled with increased salary and wage cost during 2008 reduced operating earnings for the year.

Based on the current level of infrastructure, the Company’s transportation segment is designed to maximize efficiency when revenues excluding fuel adjustments are in the $60 million per year range. Demand for the Company’s trucking service is closely tied to the domestic petrochemical industry that has experienced general weakness in recent months. The Company’s transportation business tends to contract when United States and world economies weaken and is further hindered by a current relatively strong exchange value for the U.S. dollar. Other important factors include levels of competition within the tank truck industry as well as competition from the railroads.

Comparison 2007 to 2006

Demand for the Company’s liquid chemical truck hauling business was generally sound during 2007, especially as it relates to agricultural chemical product movements. A slight overall improvement in demand led to increased 2007 revenues and operating earnings.

- 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 for revenues, operating earnings and depreciation and depletion were as follows (in thousands):

	2008						2007						2006
	Amount			Change(1)			Amount			Change(1)			Amount		Change(1)

Revenues	$	17,248			25	%	$	13,783			(19	)%	$	16,950		10	%

Operating earnings (loss)		(3,348	)		17	%		(2,853	)		(153	)%		5,355		(21	)%

Depreciation and depletion		6,763			16	%		5,833			62	%		3,603		60	%

Producing Property Impairments		3,078			153	%		1,216			43	%		841		96	%

______________

(1)	Represents the percentage increase (decrease) from the prior year.

Comparative volumes and prices were as follows:

	2008	2007	2006

Production Volumes
- Crude Oil	50,500 bbls	69,250 bbls	75,900 bbls
- Natural Gas	1,243,000 mcf	1,182,000 mcf	1,604,000 mcf

Average Price
- Crude Oil	$ 99.25/bbl	$ 70.21/bbl	$ 64.26/bbl
- Natural Gas	$ 9.84/mcf	$ 7.54/mcf	$ 7.53/mcf

Improved current year oil and gas segment revenues resulted from increased overall average commodity prices for both crude oil and natural gas as shown above. Crude oil volumes are reduced in 2008 and 2007 as a result of normal production declines while natural gas volumes increased with favorable drilling results for 2008.

Although oil and gas revenues improved during 2008, the operating loss sustained also increased for the current year due to higher charges for depreciation and depletion, producing property impairments and exploration expense. At year-end 2008, world crude oil prices fell to the $40 per barrel range. As a result, the Company’s year-end 2008 oil and gas reserves evaluation were based on average crude oil prices of $37.87 per barrel and average natural gas prices of $5.65 per mcf as compared to average prices of $92.50 per barrel and $7.31 per mcf utilized for the 2007 evaluation. Reduced prices act to suppress estimated oil and natural gas reserve quantities which in turn increase the rate of depreciation and depletion and producing property impairment valuations. Additionally, operating earnings were burdened in 2008 and 2007 when exploration expenses were incurred as follows (in thousands):

	2008		2007		2006
Dry hole expense	$	2,421	$	3,187	$	1,230
Prospect abandonment		2,834		845		564
Seismic and geological		775		1,475		1,101

Total	$	6,030	$	5,507	$	2,895

During 2008, the Company participated in the drilling of 28 wells with 19 successful and 9 dry holes. Additionally, the Company had 14 wells in process on December 31, 2008 with ultimate evaluation anticipated during 2009. Converting natural gas volumes to equate with crude oil volumes at a ratio of six to one, oil and gas production and proved reserve volumes summarize as follows on an equivalent barrel (Eq. Bbls) basis:

	2008			2007			2006
	(Eq. Bbls.)			(Eq. Bbls.)			(Eq. Bbls.)

Beginning of year		1,475,000			1,779,000			2,003,000
Estimated reserve additions		395,000			246,000			577,000
Production		(258,000	)		(266,000	)		(343,000	)
Reserves sold		-			(245,000	)		-
Revisions of previous estimates		(308,000	)		(39,000	)		(458,000	)

End of year		1,304,000			1,475,000			1,779,000

During 2008 and in total for the three year period ended December 31, 2008, estimated reserve additions represented 153 percent and 140 percent, respectively, of production volumes.

The Company’s current drilling and exploration efforts are primarily focused as follows:

Eaglewood Project

The Eaglewood project area encompasses a ten county area from South Texas along the Gulf Coast and northward into East Texas. In this area, the Company purchased existing 3-D seismic data and reprocessed it using proprietary techniques. During 2008 five wells were successfully drilled and future drilling is anticipated as costs and prices dictate. The focus for 2009 will be on identifying economically viable prospects for future drilling. The Company has a five percent working interest in this project.

East Texas Project

Beginning in 2005, the Company and its partners began acquiring acreage in East Texas and currently hold an interest in approximately 25,000 acres in Nacogdoches and Shelby Counties. Seven marginally successful wells were drilled in this area during 2006 and 2007. In 2008, the working interest owners elected to replace the operator as results were not meeting expectations. Subsequently, five productive wells were drilled and future drilling awaits evaluation of the success of the 2008 program. Based on the outcome of recent efforts, as many as twelve additional wells could be drilled. The Company has a five percent working interest in this project.

Southwestern Arkansas

The Company is participating in three 3-D seismic surveys in Southwestern Arkansas covering approximately 160 square miles. Two dry holes were drilled in the first survey both of which will be sidetracked as analysis indicates the objective zone was not penetrated. The first well in the second survey will spud in the first quarter of 2009 and the third survey is complete with data being processed. Early indications point to multiple drillable prospects being identified. The Company’s working interest in this project varies from 4.5 percent to 11.6 percent.

South Central Kansas

The Company is participating with a ten percent working interest in a large 3-D seismic survey in South Central Kansas. Data acquisition on this survey will begin in the first quarter of 2009.

Assumption Parish, Louisiana

The Company participated in a proprietary 3-D seismic survey in Assumption Parish, Louisiana during 2007. Eight prospects have been identified with two initial wells scheduled for drilling in the first quarter of 2009. Future drilling is contingent on the results of the first two wells and the Company holds a six percent working interest in this project.

Irion County, Texas

In 2008 the Company participated with a 7-1/2 percent working interest in the acquisition of approximately 49,012 gross acres to develop the Wolfcamp formation. Four wells were spudded in 2008 with two wells on production and two wells completing. Further drilling activity is deferred pending price stabilization and completion of well performance evaluation.

-	Oil and gas property sale

In May 2007, the Company sold its interest in certain Louisiana producing oil and gas properties. Sale proceeds totaled $14.9 million resulting in a pre-tax gain on sale of approximately $12.1 million.

-	General and administrative, interest income and income tax

General and administrative expenses were elevated during 2007 due primarily to federally mandated Sarbanes-Oxley compliance costs. Interest income increased in 2007 and 2006 due to larger cash balances available during the year for overnight investment coupled with interest earned on insurance related cash deposits. Interest income declined in 2008 as interest rates on overnight deposits declined to near zero. The provision for income taxes is based on Federal and State tax rates and variations are consistent with taxable income in the respective accounting periods.

-Outlook

Recent disruptions in the credit markets, declining crude oil prices and deteriorating financial conditions among some of the Company’s customers has adversely affected results of operations. In response, the Company has scaled back its 2009 capital budget and tightened customer credit requirements. Importantly, the Company has no bank debt outstanding and is in a position to fund and sustain its operations through existing available cash flow.

Given current economic conditions, planned activities for 2009 are reduced and the Company has the following major objectives for 2009:

-	Establish marketing operating earnings at the $10 million level.

-	Maintain transportation operating earnings at the $2 million level.

-	Establish oil and gas operating earnings at the $2 million level and replace 80 percent of 2009 production with current reserve additions.

Liquidity and Capital Resources

The Company’s liquidity primarily derives from net cash provided from operating activities, which was $13,639,000, $9,201,000 and $29,245,000 for each of 2008, 2007 and 2006, respectively. Changes in cash provided by operations for these periods were primarily driven by changes in working capital and such changes generally reflect timing differences that occur in the ordinary course of business and are not expected to have a significant impact on overall liquidity. As of December 31, 2008 and 2007, the Company had no bank debt or other forms of debenture obligations. Cash and cash equivalents totaled $18,208,000 as of December 31, 2008, and such balances are maintained in order to meet the timing of day-to-day cash needs. Working capital, the excess of current assets over current liabilities, totaled $41,559,000 as of December 31, 2008. Management believes current cash balances, together with expected cash generated from future operations, will be sufficient to meet short-term and long-term liquidity needs.

The Company utilizes cash from operations to make discretionary investments in its oil and natural gas exploration, marketing and transportation businesses, which comprise substantially all of the Company’s investing cash outflows for each of the past three years. The Company does not look to proceeds from property sales to fund its cash flow needs. However, during May 2007, the Company did receive net proceeds of $14,954,000 related to the sale of oil and gas properties. Such sale was made due to attractive pricing. Currently, the Company does not plan to make significant dispositions of its oil and gas properties in the future, but certain oil and gas interests may be disposed of should favorable opportunities arise. Except for a total of $3.8 million in operating lease commitments for transportation equipment and office lease space, the Company’s future commitments and planned investments can be readily curtailed if operating cash flows contract.

Capital expenditures during 2008 included $5,650,000 for marketing and transportation equipment additions and $12,038,000 in property additions associated with oil and gas exploration and production activities. Included in marketing equipment additions was approximately $4 million expended to acquire 44 used truck-tractor combinations for use in the Company’s crude oil marketing business in Michigan, West Texas and New Mexico. For 2009, the Company anticipates expending approximately $8 million on oil and gas exploration projects to be funded from operating cash flow and available working capital. In addition, approximately $4 million will be expended toward replacement of older truck-tractors within the Company’s marketing and transportation businesses with funding from available cash flow.

Historically, the Company pays an annual dividend in the fourth quarter of each year, and the Company paid a $.50 per common share or $2,109,000 dividend to shareholders of record as of December 2, 2008. The most significant item affecting future increases or decreases in liquidity is earnings from operations and such earnings are dependent on the success of future operations (see Item 1A Risk Factors in this annual report of Form 10-K). While the Company has available bank lines of credit (see below) management has no current intention to utilize such lines of credit or issue additional equity.

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 ¼ of one percent. The working capital loan provides for borrowings based on 80 percent of eligible accounts receivable and 50 percent of eligible inventories. Available capacity under the line is calculated monthly and as of December 31, 2008 the Company elected to establish the line at $5 million. The oil and gas production loan provides for flexible borrowings subject to a borrowing base requested by the Company and approved semi-annually by the bank. The borrowing base was established at $5 million as of December 31, 2008. The working capital facilities are subject to a ½ of one percent commitment fee. The line of credit loans are scheduled to expire on October 31, 2009, with the then present balance outstanding converting to a term loan payable in eight equal quarterly installments. As of December 31, 2008 and 2007, there was no bank debt outstanding under the Company’s two revolving credit facilities.

The Bank of America 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 2.0 to 1.0 ratio of earnings before interest and taxes to interest expense, and consolidated net worth in excess of $60,909,000. Should the Company’s net worth fall below this threshold, the Company may be restricted from payment of additional cash dividends on its common stock. Due to the pre-tax loss sustained during 2008, the Company obtained a waiver of the interest coverage ratio as of December 31, 2008 and otherwise, the Company is in compliance with these restrictions.

Previously, the Company’s Gulfmark and ARM subsidiaries maintained a separate banking relationship with BNP Paribas in order to provide letters of credit to support its crude oil and natural gas purchasing activities. Due to rate increases imposed by the bank, effective February 27, 2009, the Company discontinued this facility. Previously, letters of credit outstanding under this facility totaled approximately $10.1 million as of December 31, 2008. From time to time the Company may utilize available cash balances to pre-pay for crude oil and natural gas supply in lieu of providing a letter of credit.

Off-balance Sheet Arrangements

The Company maintains certain operating lease arrangements primarily with independent truck owner-operators in order to provide truck-tractor equipment for the Company’s fleet. Any commitments with independent truck owner-operators are on a month-to-month basis. All operating lease commitments qualify for off-balance sheet treatment as provided by Statement of Financial Accounting Standards No. 13, “Accounting for Leases”. Rental expense for the years ended December 31, 2008, 2007, and 2006 was $13,423,000, $11,885,000, and $9,887,000, respectively. As of December 31, 2008, commitments under long-term non-cancelable operating leases for the next five years are payable as follows: 2009 - $1,878,000; 2010 - $1,047,000; 2011 - $702,000; 2012 - $100,000; 2013 - $47,000 and none thereafter.

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. The Company has no capital lease obligations. A summary of the payment periods for contractual debt and lease obligations is as follows (in thousands):

	2009		2010		2011		2012		2013		Thereafter		Total
Long-term debt	$	-	$	-	$	-	$	-	$	-	$	-	$	-
Lease payments		1,878		1,047		702		100		47		-		3,774
Total	$	1,878	$	1,047	$	702	$	100	$	47	$	-	$	3,774

In addition to its lease financing obligations, the Company is also committed to purchase certain quantities of crude oil and natural gas in connection with its marketing activities. Such commodity purchase obligations are the basis for commodity sales, which generate the cash flow necessary to meet such purchase obligations. Approximate commodity purchase obligations as of December 31, 2008 are as follows (in thousands):

	January		Remaining
	2009		2009		2010		2011		Thereafter		Total
Crude Oil	$	57,776	$	8,139	$	-	$	-	$	-	$	65,915
Natural Gas		50,651		21,097		-		-		-		71,748
	$	108,427	$	29,236	$	-	$	-	$	-	$	137,663

Insurance

From time to time, the marketplace for all forms of insurance enters into periods of severe cost increases. In the past, during such cyclical periods, the Company has seen costs escalate to the point where desired levels of insurance were either unavailable or unaffordable. The Company’s primary insurance needs are in the areas of worker’s compensation, automobile and umbrella coverage for its trucking fleet and medical insurance for employees. During each of 2008, 2007 and 2006, insurance cost stabilized and totaled $10.6 million, $10.3 million and $9.5 million, respectively. Overall insurance cost may experience renewed rate increases during 2009. Since the Company is generally unable to pass on such cost increases, any increase will 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 financial resources substantially in excess of those of the Company. The Company faces competition principally in establishing trade credit, pricing of available materials 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 major oil companies and other large industrial concerns that own or control significant 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.

Critical Accounting Policies and Use of Estimates

Fair Value Accounting

The Company enters into certain forward commodity contracts that are required to be recorded at fair value in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities” and related accounting pronouncements. Such contracts are recorded as either an asset or liability measured at its fair value. Changes in fair value are recognized immediately in earnings unless the derivatives qualify for, and the Company elects, cash flow hedge accounting. The Company had no contracts designated for hedge accounting under SFAS No. 133.

Consistent with SFAS No. 157, “Fair Value Measurements” the Company utilizes a market approach to valuing its contracts. On a contract by contract, forward month by forward month basis, the Company obtains observable market data for valuing its contracts. Such contracts typically have durations that are less than 18 months. As of December 31, 2008, all of the Company’s measurements were defined as either Level 1 or Level 2 inputs by SFAS No. 157, representing quoted prices and inputs based on observable market data, respectively. See discussion under “Fair Value Measurements” in Note 1 to the Consolidated Financial Statements.

Trade Accounts

Accounts receivable and accounts payable typically represent the most significant assets and liabilities of the Company. Particularly within the Company’s energy marketing, oil and gas exploration, and production operations, there is a high degree of interdependence with and reliance upon third parties (including transaction counterparties) to provide adequate information for the proper recording of amounts receivable or payable. Substantially all such third parties are larger firms providing the Company with the source documents for recording trade activity. It is commonplace for these entities to retroactively adjust or correct such documents. This typically requires the Company to absorb, benefit from, or pass along such corrections to another third party.

Due to the volume of and complexity of transactions and the high degree of interdependence with third parties, this is a difficult area to control and manage. The Company manages this process by participating in a monthly settlement process with each of its counterparties. Ongoing account balances are monitored monthly and the Company attempts to gain the cooperation of such counterparties to reconcile outstanding balances. The Company also places great emphasis on collecting cash balances due and paying only bonafide and properly supported claims. In addition, the Company maintains and monitors its bad debt allowance. Nevertheless a degree of risk remains due to the custom and practices of the industry.

Oil and Gas Reserve Estimate

The value of capitalized cost of oil and natural gas exploration and production related assets are dependent on underlying oil and natural gas reserve estimates. Reserve estimates are based on many subjective factors. The accuracy of reserve estimates depends on the quantity and quality of geological data, production performance data and reservoir engineering data, changing prices, as well as the skill and judgment of petroleum engineers in interpreting such data. The process of estimating reserves requires frequent revision of estimates (usually on an annual basis) as additional information becomes available. Calculations of estimated future oil and natural gas revenues are also based on estimates of the timing of oil and natural gas production, and there are no assurances that the actual timing of production will conform to or approximate such estimates. Also, certain assumptions must be made with respect to pricing. The Company’s estimates assume prices will remain constant from the date of the engineer’s estimates, except for changes reflected under natural gas sales contracts. There can be no assurance that actual future prices will not vary as industry conditions, governmental regulation, political conditions, economic conditions, weather conditions, market uncertainty and other factors impact the market price for oil and natural gas.

The Company follows the successful efforts method of accounting, so only costs (including development dry hole costs) associated with producing oil and natural gas wells are capitalized. Estimated oil and natural gas reserve quantities are the basis for the rate of amortization under the Company’s units of production method for depreciating, depleting and amortizing of oil and natural gas properties. Estimated oil and natural gas reserve values also provide the standard for the Company’s periodic review of oil and natural gas properties for impairment.

Contingencies

From time to time as incident to its operations, the Company becomes involved in various accidents, lawsuits and/or disputes. Primarily as an operator of an extensive trucking fleet, the Company is a party to motor vehicle accidents, worker compensation claims or other items of general liability as are typical for the industry. In addition, the Company has extensive operations that must comply with a wide variety of tax laws, environmental laws and labor laws, among others. Should an incident occur, management evaluates the claim based on its nature, the facts and circumstances and the applicability of insurance coverage. To the extent management believes that such event may impact the financial condition of the Company, management will estimate the monetary value of the claim and make appropriate accruals or disclosure as provided in the guidelines of SFAS No. 5, “Accounting for Contingencies”.

Revenue Recognition

The Company’s crude oil, natural gas and refined products marketing customers are invoiced daily or monthly based on contractually agreed upon terms. Revenue is recognized in the month in which the physical product is delivered to the customer. Where required, the Company also recognizes fair value or mark-to-market gains and losses related to its commodity activities. A detailed discussion of the Company’s revenue recognition policy is included in Note (1) of Notes to Consolidated Financial Statements.

Transportation segment customers are invoiced, and the related revenue is recognized as the service is provided. Oil and natural gas revenue from the Company’s interests in producing wells is recognized as title and physical possession of the oil and natural gas passes to the purchaser.

Recent Accounting Pronouncements

In February 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities”. SFAS No. 159 provides an entity with the option to measure certain assets and liabilities and other items at fair value, with changes in fair value recognized in earnings as those changes occur. The provisions of SFAS No. 159 do not affect the fair value measurements of derivative financial instruments under SFAS No. 133. The provisions of SFAS No.159 became effective January 1, 2008. Management did not elect the fair value option for any eligible financial assets or liabilities not already carried at fair value.

In February 2008, the FASB issued FASB Staff Position No. FAS 157-2, “Effective Date of FASB Statement No. 157,” (“FSP FAS No. 157-2”). This Staff Position amends SFAS No. 157 to delay the effective date of SFAS No. 157 for non-financial assets and non-financial liabilities until fiscal years beginning after November 15, 2008, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis. The Company is currently assessing the impact of applying FSP FAS No. 157-2 to its financial and non-financial assets and liabilities. Future financial statements are expected to include enhanced disclosures with respect to fair value measurements.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133,” (“SFAS No. 161”) as amended and interpreted. SFAS No. 161 changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. Early adoption is permitted. The Company is currently evaluating the impact the adoption of SFAS No. 161 will have on its financial statements.

In December 2008, the Securities and Exchange Commission released Final Rule, Modernization of Oil and Gas Reporting to revise the existing Regulation S-K and Regulation S-X reporting requirements to align with current industry practices and technological advances. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. In addition, the new disclosure requirements require a company to (a) disclose its internal control over reserves estimation and report the independence and qualification of its reserves preparer or auditor, (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserve audit and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than period-end prices. The disclosures required by this final ruling will become effective for the Company’s Annual Report on Form 10-K for the year ended December 31, 2009.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company’s exposure to market risk includes potential adverse changes in interest rates and commodity prices.

Interest Rate Risk

The Company’s long-term debt facility provides for interest costs to fluctuate based on interest rate changes. Since the Company’s long-term debt is a floating rate, the fair value of such debt approximates the carrying value. More importantly, the Company had no long-term debt outstanding at December 31, 2008 and 2007. A hypothetical 10 percent adverse change in the floating rate would not have a material effect on the Company’s results of operations for the fiscal year ended December 31, 2008.

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 six-month to one-year term with no contracts extending longer than three years in duration.

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 fair value of such contracts is reflected on the balance sheet as fair value assets and liabilities and any revaluation is recognized on a net basis in the Company’s results of operations. See discussion under “Fair Value Measurements” in Note 1 to the Consolidated Financial Statements.

Historically, prices received for oil and natural gas sales have been volatile and unpredictable with price volatility expected to continue. From January 1, 2007 through December 31, 2008 natural gas price realizations ranged from a monthly low of $5.70 mmbtu to a monthly high of $11.85 per mmbtu. Oil prices ranged from a monthly average low of $40.34 per barrel to a high of $135.00 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 $2,896,000 and $2,622,000 for the comparative years ended December 31, 2008 and 2007, respectively.

ITEM 8. FINANCIAL STATEMENTS

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS

	Page

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM		28

FINANCIAL STATEMENTS:

Consolidated Balance Sheets as of December 31, 2008 and 2007		29

Consolidated Statements of Operations for the Years Ended
December 31, 2008, 2007 and 2006		30

Consolidated Statements of Shareholders’ Equity for the Years Ended
December 31, 2008, 2007 and 2006		31

Consolidated Statements of Cash Flows for the Years Ended
December 31, 2008, 2007 and 2006		32

Notes to Consolidated Financial Statements		33

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Adams Resources & Energy, Inc.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Adams Resources & Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of operations, shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 Adams Resources & Energy, Inc. and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for the each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.

/s/DELOITTE & TOUCHE LLP

Houston, Texas

March 20, 2009

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands)

	December 31,
ASSETS	2008			2007

CURRENT ASSETS:
Cash and cash equivalents	$	18,208		$	23,697
Accounts receivable, net of allowance for doubtful accounts of
$1,251 and $192, respectively		119,401			261,710
Inventories		14,207			14,776
Fair value contracts		8,697			5,388
Income tax receivable		3,629			2,554
Prepayments		5,224			3,768

Total current assets		169,366			311,893

PROPERTY AND EQUIPMENT:
Marketing		19,510			15,315
Transportation		32,661			32,087
Oil and gas (successful efforts method)		66,593			63,025
Other		99			99
		118,863			110,526

Less – Accumulated depreciation, depletion and amortization		(83,277	)		(70,828	)
		35,586			39,698
OTHER ASSETS:
Fair value contracts		-			1,563
Deferred income tax benefit		2,035			-
Cash deposits and other		3,939			3,921
	$	210,926		$	357,075
LIABILITIES AND SHAREHOLDERS’ EQUITY

CURRENT LIABILITIES:
Accounts payable	$	115,183		$	252,310
Accounts payable – related party		89			84
Fair value contracts		8,196			4,116
Accrued and other liabilities		3,930			3,707
Current deferred income taxes		409			1,104
Total current liabilities		127,807			261,321

LONG-TERM DEBT		-			-

OTHER LIABILITIES:
Asset retirement obligations		1,260			1,153
Deferred income taxes and other		98			4,063
Fair value contracts		-			1,096
		129,165			267,633
COMMITMENTS AND CONTINGENCIES (NOTE 8)

SHAREHOLDERS’ EQUITY:
Preferred stock, $1.00 par value, 960,000 shares authorized,
none outstanding		-			-
Common stock, $.10 par value, 7,500,000 shares authorized,
4,217,596 issued and outstanding		422			422
Contributed capital		11,693			11,693
Retained earnings		69,646			77,327
Total shareholders’ equity		81,761			89,442
	$	210,926		$	357,075

The accompanying notes are an integral part of these consolidated financial statements.

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	Years Ended December 31,
	2008			2007			2006
REVENUES:
Marketing	$	4,074,677		$	2,558,545		$	2,167,502
Transportation		67,747			63,894			62,151
Oil and gas		17,248			13,783			16,950
		4,159,672			2,636,222			2,246,603
COSTS AND EXPENSES:
Marketing		4,074,614			2,537,117			2,153,183
Transportation		59,659			54,115			52,440
Oil and gas operations		13,833			10,803			7,992
Oil and gas property sale		-			(12,078	)		-
General and administrative		9,667			10,974			8,536
Depreciation, depletion and amortization		13,373			11,384			9,485
		4,171,146			2,612,315			2,231,636

Operating Earnings (Loss)		(11,474	)		23,907			14,967

Other Income (Expense):
Interest income		1,103			1,741			965
Interest expense		(187	)		(134	)		(159	)

Earnings (loss) before income taxes		(10,558	)		25,514			15,773

Income Tax Benefit (Provision):
Current		(1,689	)		(8,093	)		(4,878	)
Deferred		6,675			(365	)		(412	)
		4,986			(8,458	)		(5,290	)

Net Earnings (Loss)	$	(5,572	)	$	17,056		$	10,483

EARNINGS (LOSS) PER SHARE:
Basic and diluted net earnings (loss) per share	$	(1.32	)	$	4.04		$	2.49

DIVIDENDS PER COMMON SHARE	$	.50		$	.47		$	.42

The accompanying notes are an integral part of these consolidated financial statements.

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

(In thousands)

								Total
	Common		Contributed		Retained			Shareholders’
	Stock		Capital		Earnings			Equity

BALANCE, January 1, 2006	$	422	$	11,693	$	53,541		$	65,656
Net earnings		-		-		10,483			10,483
Dividends paid on common stock		-		-		(1,771	)		(1,771	)
BALANCE, December 31, 2006	$	422	$	11,693	$	62,253		$	74,368
Net earnings		-		-		17,056			17,056
Dividends paid on common stock		-		-		(1,982	)		(1,982	)
BALANCE, December 31, 2007	$	422	$	11,693	$	77,327		$	89,442
Net earnings (loss)		-		-		(5,572	)		(5,572	)
Dividends paid on common stock		-		-		(2,109	)		(2,109	)
BALANCE, December 31, 2008	$	422	$	11,693	$	69,646		$	81,761

The accompanying notes are an integral part of these consolidated financial statements.

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Years Ended December 31,
	2008			2007			2006

CASH PROVIDED BY OPERATIONS:
Net earnings	$	(5,572	)	$	17,056		$	10,483
Adjustments to reconcile net earnings to net cash
from operating activities-
Depreciation, depletion and amortization		13,373			11,384			9,485
Loss (gain) on property sales		354			(12,025	)		(101	)
Dry hole costs incurred		2,421			3,187			1,230
Impairment of oil and gas properties		5,911			2,062			1,405
Provision for doubtful accounts		1,059			(33	)		(383	)
Other, net		(433	)		(93	)		262
Decrease (increase) in accounts receivable		141,250			(67,580	)		24,013
Decrease (increase) in inventories		569			(6,826	)		3,742
Net change in fair value contracts		1,238			(275	)		317
Decrease (increase) in tax receivable		(1,075	)		(1,158	)		(92	)
Decrease (increase) in prepayments		(1,456	)		771			3,047
Increase (decrease) in accounts payable		(137,548	)		66,556			(27,682	)
Increase (decrease) in accrued liabilities		223			(4,190	)		3,107
Deferred income taxes		(6,675	)		365			412
Net cash provided by operating activities		13,639			9,201			29,245

INVESTING ACTIVITIES:
Property and equipment additions		(17,688	)		(15,841	)		(15,832	)
Insurance and tax refunds (deposits)		502			(303	)		(1,458	)
Proceeds from property sales		167			14,954			142
Redemption of short-term investments		10,000			25,000			-
Investment in short-term investments		(10,000	)		(25,000	)		-
Net cash (used in) investing activities		(17,019	)		(1,190	)		(17,148	)

FINANCING ACTIVITIES:
Net repayments under credit agreements		-			(3,000	)		(8,475	)
Dividend payments		(2,109	)		(1,982	)		(1,771	)
Net cash (used in) financing activities		(2,109	)		(4,982	)		(10,246	)

Increase (decrease) in cash and cash equivalents		(5,489	)		3,029			1,851

Cash and cash equivalents at beginning of year		23,697			20,668			18,817

Cash and cash equivalents at end of year	$	18,208		$	23,697		$	20,668

The accompanying notes are an integral part of these consolidated financial statements.

ADAMS RESOURCES & ENERGY, INC.

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 order to conform to current year presentations, certain reclassifications have been made to prior year amounts in the Statement of Cashflows under “Provision for Doubtful Accounts”.

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 1,000 mile radius of Houston, Texas.

Cash, Cash Equivalents and Auction Rate Investments

Cash and cash equivalents include any Treasury bill, commercial paper, money market fund or federal funds with maturity of 90 days or less. Depending on cash availability and market conditions, investments in municipal bonds may also be made from time to time. The Company invests in tax-free municipal securities in order to enhance the after-tax rate of return from short-term investments of cash. The Company had no municipal investments or auction rate securities as of December 31, 2008 and 2007.

Allowance for Doubtful Accounts

Accounts receivable result from sales of crude oil, natural gas and refined products as well as from trucking services. Marketing business wholesale level sales of crude oil and natural gas comprise in excess of 86 percent of accounts receivable and under industry practices, such items are “settled” and paid in cash within 25 days of the month following the transaction date. For such receivables, an allowance for doubtful accounts is determined based on specific account identification. The balance of accounts receivable results primarily from sales of refined petroleum products and trucking services. For this component of receivables, the allowance for doubtful accounts is determined based on a review of specific accounts combined with a review of the general status of the aging of all accounts.

Inventories

Crude oil and petroleum product inventories are carried at the lower of average cost or market. Petroleum products inventory includes gasoline, lubricating oils and other petroleum products purchased for resale. Components of inventory are as follows (in thousands):

	December 31,
	2008		2007

Crude oil	$	11,710	$	12,437
Petroleum products		2,497		2,339

	$	14,207	$	14,776

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.

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. Such evaluations are made on a quarterly basis. If an exploratory well is determined to be nonproductive, the costs of drilling the well are charged to expense. Costs incurred to drill and complete development wells, including dry holes, are capitalized. As of December 31, 2008, the Company had no unevaluated or suspended exploratory drilling costs.

Producing oil and gas leases, equipment and intangible drilling costs are depleted or amortized over the estimated proved producing 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 fifteen years for marketing, three to fifteen years for transportation and ten to twenty years for all others.

The Company periodically reviews 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 quarterly for impairment triggers on a field-by-field basis. Any impairment recognized is permanent and may not be restored. During 2008, 2007 and 2006, an impairment provision on producing oil and gas properties totaling $3,078,000, $1,216,000 and $841,000, respectively, was recorded due to higher costs incurred on certain properties relative to their periodic oil and gas reserve valuations. In addition, on a quarterly basis, management evaluates the carrying value of non-producing properties and unevaluated properties and may deem them impaired for lack of drilling activity. Accordingly, impairment provisions on non-producing properties totaling $2,834,000, $846,000 and $564,000 were recorded for 2008, 2007 and 2006, respectively.

Cash deposits and other assets

The Company has established certain deposits to support its participation in its liability insurance program and such deposits totaled $2,794,000 and $2,699,000 as of December 31, 2008 and 2007, respectively. In addition, the Company maintains certain deposits to support oil and gas operations and the collection and remittance of state crude oil severance taxes. Such deposits totaled $252,000 and $545,000 as of December 31, 2008 and 2007, respectively. Also included in other assets is $503,000 of accounts and notes receivable from certain customers that are expected to be collected over a long-term period.

Revenue Recognition

Commodity purchases and sale contracts utilized by the Company’s marketing businesses qualify as derivative instruments under Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities.”

All natural gas, as well as certain specifically identified crude oil purchase and sale contracts are designated as trading activities under the guidance provided by SFAS No. 115, “Accounting for Certain Debt and Equity Securities.” From the time of contract origination, such contracts are marked-to-market under SFAS No. 133 and recorded on a net revenue basis in the accompanying financial statements in accordance with Emerging Issues Task Force (“EITF”) 02-03 “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.”

Substantially all crude oil and refined products purchase and sale contracts qualify and are designated as non-trading activities and the Company accordingly elects the normal purchases and sales exception under SFAS No. 133. For normal purchase and sale activities, the Company’s customers are invoiced monthly based upon contractually agreed upon terms and revenue is recognized in the month in which the physical product is delivered to the customer. Such sales are recorded gross in the financial statements based on the guidance provided by EITF 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.”

Certain crude oil contracts may be with a single counterparty to provide for similar quantities of crude oil to be bought and sold at different locations. These contracts are entered into for a variety of reasons, including effecting the transportation of the commodity, to minimize credit exposure, and/or to meet the competitive demands of the customer. Consistent with the requirements of EITF 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” these buy/sell arrangements are reflected on a net revenue basis in the accompanying financial statements.

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 title and physical possession of the oil and gas passes to the purchaser.

Statement of Cash Flows

Interest paid totaled $187,000, $115,000 and $158,000 during the years ended December 31, 2008, 2007 and 2006, respectively. Income taxes paid during these same periods totaled $3,768,000, $9,134,000, and $4,941,000, respectively. Non-cash investing activities for property and equipment in accounts payable were $561,000, $135,000 and $172,000 as of December 31, 2008, 2007 and 2006, respectively. There were no significant non-cash financing activities in any of the periods reported.

Earnings Per Share

The Company computes and presents earnings per share in accordance with 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 potentially dilutive common stock shares outstanding during the period. The weighted average number of shares outstanding was 4,217,596 for 2008, 2007 and 2006. There were no potentially dilutive securities during those periods.

Share-Based Payments

During the periods presented herein, the Company had no stock-based employee compensation plans, nor any other share-based payment arrangements.

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, revenue accruals, oil and gas property impairments, the provision for bad debts, insurance related accruals, income taxes, contingencies and valuation of fair value contracts.

Fair Value Measurements

The carrying amount reported in the balance sheet for cash and cash equivalents, accounts receivable and accounts payable approximates fair value because of the immediate or short-term maturity of these financial instruments.

Fair value contracts consist of derivative financial instruments as defined under SFAS No. 133 and such contracts are recorded as either an asset or liability measured at its fair value. Changes in fair value are recognized immediately in earnings unless the derivatives qualify for, and the Company elects, cash flow hedge accounting. The Company had no contracts designated for hedge accounting under SFAS No. 133 during any current reporting periods.

SFAS No. 157, “Fair Value Measurements”, defines fair value, establishes a framework for measuring fair value and expands disclosures related to fair value measurements. SFAS No. 157 clarifies that fair value should be based on assumptions that market participants would use when pricing an asset or liability and establishes a fair value hierarchy of three levels that prioritizes the information used to develop those assumptions. Currently, for all items presented herein, the Company utilizes a market approach to valuing its contracts. On a contract by contract, forward month by forward month basis, the Company obtains observable market data for valuing its contracts. The data utilized falls into a fair value hierarchy as defined by SFAS No. 157. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data. The fair value hierarchy is summarized as follows:

Level 1 – quoted prices in active markets for identical assets or liabilities that may be accessed at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company utilizes the New York Mercantile Exchange “NYMEX” for its Level 1 valuations

Level 2 – (a) quoted prices for similar assets or liabilities in active markets, (b) quoted prices for identical assets or liabilities but in markets that are not actively traded or in which little information is released to the public, (c) observable inputs other than quoted prices and (d) inputs derived from observable market data.

Level 3 – Unobservable market data inputs for assets or liabilities.

The Company adopted SFAS No. 157 effective January 1, 2008 and such adoption did not have a material impact on financial assets or liabilities recorded at fair value. As of December 31, 2008, the Company’s fair value assets and liabilities are summarized and categorized as follows (in thousands):

	Market Data Inputs
	Level 1		Level 2			Level 3
	Quoted Prices		Observable			Unobservable		Total
Derivatives
- Current assets	$	1,029	$	7,668		$	-	$	8,697
- Long-term assets		-		-			-		-
- Current liabilities		-		(8,196	)		-		(8,196	)
- Long-term liabilities		-		-			-		-
Net Value	$	1,029	$	(528	)	$	-	$	501

The Company’s fair value contracts 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 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. The Company’s gross transactions volumes for physically settled energy trading contracts were approximately 159,505,000 mmbtu’s, 154,395,000 mmbtu’s, and 129,210,000 mmbtu’s in 2008, 2007 and 2006, respectively.

When determining fair value measurements, the Company makes credit valuation adjustments to reflect both its own nonperformance risk and its counterparty’s nonperformance risk. When adjusting the fair value of derivative contracts for the effect of nonperformance risk, the impact of netting and any applicable credit enhancements, such as collateral postings, thresholds, and guarantees are considered. Credit valuation adjustments utilize Level 3 inputs, such as credit scores to evaluate the likelihood of default by the Company or its counterparties. As of December 31, 2008, credit valuation adjustments were not significant to the overall valuation of the Company’s fair value contracts. As a result, applicable fair value assets and liabilities in their entirety are classified in Level 2 of the fair value hierarchy.

The following table illustrates the factors impacting the change in the net value of the Company’s fair value contracts for the year ended December 31, 2008 (in thousands):

	Level 1			Level 2
	Quoted Prices			Observable			Total

Net Fair Value January 1,	$	344		$	1,395		$	1,739
- Net realized (gains) losses		(436	)		(835	)		(1,271	)
- Net unrealized gains (losses)
at inception of contract		1,121			(1,034	)		87
- Net unrealized gains (losses)
from valuation methodology change		-			-			-
- Net other unrealized gains (losses)		-			(54	)		(54	)

Net Fair Value December 31,	$	1,029		$	(528	)	$	501

Asset Retirement Obligations

The Company records a long-term liability for the estimated retirement costs associated with certain tangible long-lived assets. The estimated fair value of asset retirement obligations are recorded in the period in which they are incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. A summary of the Company’s asset retirement obligations is presented as follows (in thousands):

	2008			2007

Balance on January 1,	$	1,153		$	1,152
-Liabilities incurred		57			44
-Accretion of discount		70			135
-Liabilities settled		(20	)		(178	)
-Revisions to estimates		-			-
Balance on December 31,	$	1,260		$	1,153

In addition to an accrual for asset retirement obligations, the Company maintains $75,000 in escrow cash, which is legally restricted for the potential purpose of settling asset retirement costs in accordance with certain state regulations. Such cash deposits are included in other assets in the accompanying balance sheet.

New Accounting Pronouncements

In February 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities”. SFAS No. 159 provides an entity with the option to measure certain assets and liabilities and other items at fair value, with changes in fair value recognized in earnings as those changes occur. The provisions of SFAS No. 159 do not affect the fair value measurement of derivative financial instruments under SFAS No. 133 as shown above. The provisions of SFAS No. 159 became effective beginning January 1, 2008. Management did not elect the fair value option for any eligible financial assets or liabilities not already carried at fair value.

In February 2008, the FASB issued FASB Staff Position No. FAS 157-2, “Effective Date of FASB Statement No. 157”, (“FSP FAS No. 157-2”). This Staff Position amends SFAS No. 157 to delay the effective date of SFAS No. 157 for non-financial assets and non-financial liabilities until fiscal years beginning after November 15, 2008, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis. The Company is currently assessing the impact of applying FSP FAS No. 157-2 to its non-financial assets and liabilities. Future financial statements are expected to include enhanced disclosures with respect to fair value measurements.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133”, as amended and interpreted. SFAS No. 161 changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008 and early adoption is permitted. The Company is currently evaluating the impact the adoption of SFAS No. 161 will have on its financial statements.

In December 2008, the Securities and Exchange Commission released Final Rule, Modernization of Oil and Gas Reporting to revise the existing Regulation S-K and Regulation S-X reporting requirements to align with current industry practices and technological advances. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. In addition, the new disclosure requirements require a company to (a) disclose its internal control over reserves estimation and report the independence and qualification of its reserves preparer or auditor, (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserve audit and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than period-end prices. The disclosures required by this ruling will become effective for the Company’s Annual Report on Form 10-K for the year ended December 31, 2009.

(2) Long-Term Debt

The Company's bank loan agreement with Bank of America provides for two separate lines of credit with interest at the bank's prime rate minus ¼ of one percent. The working capital loan provides for borrowings based on the total of 80 percent of eligible accounts receivable and 50 percent of eligible inventories. Available capacity under the working capital line is calculated monthly and as of December 31, 2008 the Company elected to establish the line at $5 million with no amounts outstanding at December 31, 2008. The oil and gas production loan provides for flexible borrowings, subject to a borrowing base requested by the Company and approved by the bank. The borrowing base was established at $5 million as of December 31, 2008 with no amount outstanding. The working capital facilities are subject to a ½ of one percent commitment fee. 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 with no amounts outstanding as of December 31, 2008. The two bank lines of credit are secured by substantially all of the assets of the Company’s refined product, transportation and oil and gas exploration subsidiaries. Any borrowings under the line of credit loans would expire on October 31, 2009, with the then present balance outstanding converting to a term loan payable in eight equal quarterly installments.

Previously, the Company’s Gulfmark Energy, Inc. (“Gulfmark”) and Adams Resources Marketing, Ltd. (“ARM”) subsidiaries, maintained a separate banking relationship with BNP Paribas in order to provide letters of credit to support its crude oil and natural gas purchasing activities. Due to rate increases imposed by the bank, effective February 27, 2009, the Company discontinued this facility. Previously, letters of credit outstanding under this facility totaled approximately $10.1 million as of December 31, 2008.

The Company had no borrowings in 2008 and the Company’s weighted average effective interest rate for 2007 and 2006 was 7.75 percent, and 7.5 percent, respectively. No interest was capitalized during 2008, 2007 or 2006.

(3) Income Taxes

The following table shows the components of the Company's income tax benefit (provision) (in thousands):

	Years ended December 31,
	2008			2007			2006
Current:
Federal	$	(1,349	)	$	(6,637	)	$	(4,506	)
State		(340	)		(1,456	)		(372	)
		(1,689	)		(8,093	)		(4,878	)
Deferred:
Federal		6,199			(497	)		(504	)
State		476			132			92
	$	4,986		$	(8,458	)	$	(5,290	)

Taxes computed at the corporate federal income tax rate reconcile to the reported income tax provision as follows (in thousands):

	Years ended December 31,
	2008		2007			2006
Statutory federal income tax benefit (provision)	$	3,696	$	(8,930	)	$	(5,521	)
State income tax benefit (provision)		88		(860	)		(266	)
Federal statutory depletion		797		750			537
Domestic production deduction		62		141			-
Foreign investment write-off		-		148			-
Foreign tax rate change		-		-			108
Valuation allowance – foreign		-		(13	)		(475	)
Change in state tax rates		20		322			208
Reduction of prior FIN 48 liability		320		-			-
Texas rate change adjustment		-		-			108
Other		3		(16	)		11
	$	4,986	$	(8,458	)	$	(5,290	)

Deferred income taxes reflect the net difference between the financial statement carrying amounts and the underlying tax basis in such items. The components of the federal deferred tax asset (liability) are as follows (in thousands):

	Years Ended December 31,
	2008			2007
Current deferred tax asset (liability)
Bad debts	$	438		$	67
Prepaid insurance		(672	)		(562	)
Mark-to-market contracts		(175	)		(609	)

Net current deferred tax (liability)		(409	)		(1,104	)

Long-term deferred tax asset (liability)
Property		1,985			(3,724	)
Uniform capitalization		263			-
Insurance returns		(323	)		(214	)
Other		110			(7	)
Net long-term deferred tax asset (liability)		2,035			(3,945	)

Net deferred tax asset (liability)	$	1,626		$	(5,049	)

Financial Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”) establishes standards for recognition and measurement, in the financial statements, of positions taken, or expected to be taken, by an entity in its income tax returns taking into consideration the uncertainty and judgment involved in the determination and filing of income taxes. Positions taken in an income tax return that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by taxing authorities with full knowledge of all relevant information. As of December 31, 2008 and 2007, the Company had accrued approximately $114,000 and $434,000 including approximately $51,000 and $200,000 of potential interest and penalty, respectively, applicable to certain open and unfiled state tax returns. A reconciliation of the unrecognized tax benefits is as follows (in thousands):

	2008			2007
Balance as of January 1,	$	234		$	120
Additions for tax positions of prior years		-			114
Reductions of prior positions		(171	)
Balance as of December 31,	$	63		$	234

The Company is currently working to file all remaining open returns and expects to complete this process by year-end 2009. As the actual tax payments are made, the accrual will be reduced.

The Company adopted FIN 48 effective January 1, 2007. As discussed above, the Company had previously provided a liability accrual for open state tax returns and has no other unrecognized tax benefits. As such, the adoption of FIN 48 did not impact on the Company’s results for the year ended December 31, 2007. Interest and penalties associated with income tax liabilities are classified as income tax expense.

The earliest tax years remaining open from Federal and major states of operations are as follows:

	Earliest Open
	Tax Year

Federal	2005
Texas	2004
Louisiana	2005
Michigan	2005
Mississippi	2005
Alabama	2005
New Mexico	2005

(4) Fair Value of Financial Instruments and Concentration of Credit Risk

Fair Value of Financial Instruments

The carrying amounts of cash equivalents are believed to approximate their fair values because of the short maturities of these instruments. The Company’s long and short-term debt obligations bear interest at floating rates. At December 31, 2008 and 2007, the Company’s only debt obligations consisted of non-interest bearing accounts payable. As such, carrying amounts approximate fair values. For a discussion of the fair value of commodity financial instruments see “Fair Value Measurements” in Note (1) of Notes to Consolidated Financial Statements.

Concentration of Credit Risk

Credit risk represents the amount of loss 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 86 percent of the Company's total receivables as of December 31, 2008, and industry practice requires payment for such sales to occur within 25 days of the month following a transaction. The Company's credit policy and the relatively short duration of receivables mitigate the uncertainty typically associated with receivables management. The Company had accounts receivable from one customer that comprised 18.7 percent of total accounts receivable at December 31, 2008. Such customers also comprised 16.3 percent and a second customer comprised 40.3 percent of total revenues during 2008. The Company had accounts receivable from two customers that comprised 23 percent and 17 percent of total receivables at December 31, 2007. Such customers also comprised 42 percent and 14 percent, respectively, of total revenues during 2007. The Company had accounts receivable from one customer that comprised 14 percent of total receivables at December 31, 2006 and such customer also comprised more than 10 percent of the Company’s revenues in 2006.

During 2008, the Company increased its provision for bad debts as a result of a deteriorating economic outlook for the U. S. economy particularly as it might impact the collectability of the Company’s diesel fuel sales to the construction industry. An allowance for doubtful accounts is provided where appropriate and accounts receivable presented herein are net of allowances for doubtful accounts of $1,251,000 and $192,000 at December 31, 2008 and 2007, respectively.

An analysis of the changes in the allowance for doubtful accounts is presented as follows (in thousands):

	2008			2007			2006

Balance, beginning of year	$	192		$	225		$	608
Provisions for bad debts		1,099			121			346
Less: Write-offs and recoveries		(40	)		(154	)		(729	)

Balance, end of year	$	1,251		$	192		$	225

(5) Employee Benefits

The Company maintains a 401(k) savings plan for the benefit of its employees. The Company’s contributory expenses for the plan were $607,000, $582,000 and $541,000 in 2008, 2007 and 2006, respectively. No other pension or retirement plans are maintained by the Company.

(6) Transactions with Related Parties

Mr. K. S. Adams, Jr., Chairman and Chief Executive Officer, and certain of his family partnerships and affiliates have participated as working interest owners with the Company’s subsidiary, Adams Resources Exploration Corporation. Mr. Adams and such affiliates participate on terms similar to those afforded other non-affiliated working interest owners. In recent years, such related party transactions generally result after the Company has first identified oil and gas prospects of interest. Typically the available dollar commitment to participate in such transactions is greater than the amount management is comfortable putting at risk. In such event, the Company first determines the percentage of the transaction it wants to obtain, which allows a related party to participate in the investment to the extent there is excess available. In those instances where there was no excess availability there has been no related party participation. Similarly, related parties are not required to participate, nor is the Company obligated to offer any such participation to a related or other party. When such related party transactions occur, they are individually reviewed and approved by the Audit Committee comprised of the independent directors on the Company’s Board of Directors. During 2008 and 2007, the Company’s investment commitments totaled approximately $6.7 million and $7.4 million, respectively, in those oil and gas projects where a related party was also participating in such investments. As of December 31, 2008 and 2007, the Company owed a combined net total of $89,000 and $84,000, respectively, to these related parties. In connection with the operation of certain oil and gas properties, the Company also charges such related parties for administrative overhead primarily as prescribed by the Council of Petroleum Accountants Society Bulletin 5. Such overhead recoveries totaled $134,000, $125,000 and $118,000 for the year ended December 31, 2008, 2007, and 2006, respectively.

The Company also enters into certain transactions in the normal course of business with other affiliated entities including direct cost reimbursement for shared phone and secretarial services. For the year ended December 31, 2008, 2007 and 2006, the affiliated entities charged the Company $51,000, $80,000 and $37,000, respectively, of expense reimbursement and the Company charged the affiliates $97,000, $80,000 and $102,000, respectively, for such expense reimbursements.

(7) Commitments and Contingencies

Rental expense primarily results from payments to truck owner-operators for use of their equipment and services on a month-to-month basis. The Company has also entered into longer term operating lease arrangements for tractors, trailers, office space, and other equipment and facilities. Rental expense for the years ended December 31, 2008, 2007, and 2006 was $13,423,000, $11,885,000 and $9,887,000, respectively. At December 31, 2008, commitments under long-term non-cancelable operating leases for the next five years and thereafter are payable as follows: 2009 - $1,878,000; 2010 - $1,047,000; 2011 - $702,000; 2012 - $100,000; 2013 - $47,000 with none thereafter.

Under certain of the Company’s automobile and workers compensation insurance policies, the Company can either receive a return of premium paid or be assessed for additional premiums up to pre-established limits. Additionally under the policies in certain instances the risk of insured losses is shared with a group of similarly situated entities. As of December 31, 2008 and 2007, management has appropriately recognized estimated expenses and liability related to the program.

From time to time as incidental to its operations, the Company may become involved in various lawsuits and/or disputes. Primarily as an operator of an extensive trucking fleet, the Company is a party to motor vehicle accidents, worker compensation claims and other items of general liability as would be typical for the industry. Management of the Company is presently unaware of any claims against the Company that are either outside the scope of insurance coverage, or that may exceed the level of insurance coverage, and could potentially represent a material adverse effect on the Company’s financial position or results of operations.

(8) Guarantees

Pursuant to arranging operating lease financing for truck tractors and tank trailers, individual subsidiaries of the Company may guarantee the lessor a minimum residual equipment sales value upon the expiration of a lease and sale of the underlying equipment. The Company believes performance under these guarantees to be remote. Aggregate guaranteed residual values for tractors and trailers under operating leases as of December 31, 2008 are as follows (in thousands):

		2009				2010				2011				2012				Thereafter				Total
Equipment residual values		$	1,475			$	217			$	181			$	72			$	216			$	2,161

In connection with certain contracts for the purchase and resale of branded motor fuels, the Company has received certain price discounts from its suppliers toward the purchase of gasoline and diesel fuel. Such discounts have been passed through to the Company’s customers as an incentive to offset a portion of the costs associated with offering branded motor fuels for sale to the general public. Under the terms of the supply contracts, the Company and its customers are not obligated to return the price discounts, provided the gasoline service station offering such product for sale remains as a branded station for periods ranging from three to ten years. The Company has a number of customers and stations operating under such arrangements, and the Company’s customers are contractually obligated to remain a branded dealer for the required periods of time. Should the Company’s customers seek to void such contracts, the Company would be obligated to return a portion of such discounts received to its suppliers. As of December 31, 2008, the maximum amount of such potential obligation is approximately $2,336,000. Management of the Company believes its customers will adhere to their branding obligations and no such refunds will result.

Presently, neither Adams Resources & Energy, Inc. (“ARE”) nor any of its subsidiaries has any other types of guarantees outstanding that require liability recognition under the provisions of Financial Accounting Standards Board Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”.

ARE frequently issues parent guarantees of commitments resulting from the ongoing activities of its subsidiary companies. The guarantees generally result from subsidiary commodity purchase obligations, subsidiary lease commitments and subsidiary banking transactions. The nature of such items is to guarantee the performance of the subsidiary companies in meeting their respective underlying obligations. Except for operating lease commitments and letters of credit, all such underlying obligations are recorded on the books of the subsidiary companies and are included in the consolidated financial statements included herein. Therefore, no such obligation is recorded again on the books of the parent. The parent would only be called upon to perform under the guarantee in the event of a payment default by the applicable subsidiary company. In satisfying such obligations, the parent would first look to the assets of the defaulting subsidiary company.

As of December 31, 2008, parental guaranteed obligations are approximately as follows (in thousands):

	2009		2010		2011		2012		Thereafter		Total
Lease payments	$	1,878		1,047		702		100		47		3,774
Equipment residual values		1,475		217		181		72		216		2,161
Commodity purchases		27,751		-		-		-		-		27,751
Letters of credit		10,091		-		-		-		-		10,091
	$	41,195	$	1,264	$	883	$	172	$	263	$	43,777

(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):

			Segment Operating			Depreciation Depletion and		Property and Equipment
	Revenues		Earnings (loss)			Amortization		Additions
Year ended December 31, 2008-
Marketing
- Crude oil	$	3,849,531	$	(4,545	)	$	2,039	$	4,715
- Natural gas		11,586		2,247			163		12
- Refined products		213,560		(406	)		565		114
Marketing Total		4,074,677		(2,704	)		2,767		4,841
Transportation		67,747		4,245			3,843		809
Oil and gas		17,248		(3,348	)		6,763		12,038
	$	4,159,672	$	(1,807	)	$	13,373	$	17,688
Year ended December 31, 2007-
Marketing
- Crude oil	$	2,373,838	$	15,321		$	657	$	1,397
- Natural gas		13,764		4,999			162		497
- Refined products		170,943		(168	)		457		104
Marketing Total		2,558,545		20,152			1,276		1,998
Transportation		63,894		5,504			4,275		353
Oil and gas		13,783		9,225			5,833		13,490
	$	2,636,222	$	34,881		$	11,384	$	15,841
Year ended December 31, 2006-
Marketing
- Crude oil	$	1,975,972	$	5,088		$	857	$	1,395
- Natural gas		13,621		6,558			59		432
- Refined products		177,909		1,329			428		1,085
Marketing Total		2,167,502		12,975			1,344		2,912
Transportation		62,151		5,173			4,538		1,342
Oil and gas		16,950		5,355			3,603		11,578
	$	2,246,603	$	23,503		$	9,485	$	15,832

Intersegment sales are insignificant and all sales by the Company occurred in the United States.

Segment operating earnings reflect revenues net of operating costs and depreciation, depletion and amortization and are reconciled to earnings from continuing operations before income taxes, as follows (in thousands):

	Years Ended December 31,
	2008			2007			2006
Segment operating earnings (loss)	$	(1,807	)	$	34,881		$	23,503
- General and administrative expenses		(9,667	)		(10,974	)		(8,536	)
Operating earnings		(11,474	)		23,907			14,967
- Interest income		1,103			1,741			965
- Interest expense		(187	)		(134	)		(159	)
Earnings (loss) before income taxes	$	(10,558	)	$	25,514		$	15,773

Identifiable assets by industry segment are as follows (in thousands):

	Years Ended December 31,
	2008		2007
Marketing
- Crude oil	$	85,774	$	186,163
- Natural gas		46,599		74,585
- Refined products		13,037		21,844
Marketing Total		145,410		282,592
Transportation		14,915		18,282
Oil and gas		21,904		25,267
Other		28,697		30,934
	$	210,926	$	357,075

Other identifiable assets are primarily corporate cash, corporate accounts receivable, and properties not identified with any specific segment of the Company's business. Accounting policies for transactions between reportable segments are consistent with applicable accounting policies as disclosed herein.

(10) Quarterly Financial Data (Unaudited) -

Selected quarterly financial data and earnings per share of the Company are presented below for the years ended December 31, 2008 and 2007 (in thousands, except per share data):

							Net Earnings						Dividends
				Operating						Per					Per
		Revenues		Earnings			Amount			Share			Amount		Share
	2008 -
March 31		$	965,988	$	3,001		$	2,211		$	.52		$	-	$	-
June 30			1,280,352		7,133			4,825			1.15			-		-
September 30			1,288,322		(10,044	)		(6,276	)		(1.49	)		-		-
December 31			625,010		(11,564	)		(6,332	)		(1.50	)		2,109		.50
Total		$	4,159,672	$	(11,474	)	$	(5,572	)	$	(1.32	)	$	2,109	$	.50

	2007 -
March 31		$	486,366	$	827		$	912		$	.22		$	-	$	-
June 30			569,748		17,595			11,286			2.67			-		-
September 30			700,295		3,813			2,855			.68			-		-
December 31			879,813		1,672			2,003			.47			1,982		.47
Total		$	2,636,222	$	23,907		$	17,056		$	4.04		$	1,982	$	.47

Note:

First and second quarter 2008 earnings above included pre-tax inventory liquidation gains totaling $1,967,000 and $3,911,000, respectively, as crude oil prices increased during the periods, while third and fourth quarter 2008 earnings included pre-tax inventory liquidation losses totaling $11,600,000 and $6,122,000 respectively, as crude oil prices initially increased by $43 per barrel and then declined by $93 per barrel during the second half of 2008. Second quarter 2007 earnings include $12,078,000 of pre-tax earnings attributable to a gain on sale of certain producing oil and gas properties.

The above unaudited interim financial data reflect all adjustments that are in the opinion of management necessary to a fair statement of the results for the period presented. All such adjustments are of a normal recurring nature.

(11) Oil and Gas Producing Activities (Unaudited)

The following information concerning the Company’s oil and gas segment has been provided pursuant to SFAS No. 69, “Disclosures about Oil and Gas Producing Activities.” The Company’s oil and gas exploration and production activities are conducted in the United States, primarily along the Gulf Coast of Texas and Louisiana.

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):

	Years Ended December 31,
	2008		2007		2006
Property acquisition costs
Unproved	$	3,139	$	1,428	$	1,885
Proved		-		-		-
Exploration costs
Expensed		6,030		5,507		2,902
Capitalized		178		1,289		2,173
Development costs		3,466		6,741		5,628
Total costs incurred	$	12,813	$	14,965	$	12,588

The aggregate capitalized costs relative to oil and gas producing activities are as follows (in thousands):

	December 31,
	2008			2007

Unproved oil and gas properties	$	5,945		$	5,328
Proved oil and gas properties		60,648			57,697
		66,593			63,025
Accumulated depreciation, depletion
and amortization		(47,041	)		(40,525	)

Net capitalized cost	$	19,551		$	22,500

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 its independent 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.

Proved developed and undeveloped reserves are presented as follows (in thousands):

	Years Ended December 31,
	2008						2007						2006
	Natural						Natural						Natural
	Gas			Oil			Gas			Oil			Gas			Oil
	(Mcf’s)			(Bbls.)			(Mcf’s)			(Bbls.)			(Mcf’s)			(Bbls.)
Total proved reserves-
Beginning of year		7,068			297			8,300			396			9,643			396
Revisions of previous estimates		(1,350	)		(83	)		132			(61	)		(2,473	)		(45	)
Oil and gas reserves sold		-			-			(1,460	)		(2	)
Extensions, discoveries and
other reserve additions		1,968			67			1,278			33			2,734			121
Production		(1,243	)		(51	)		(1,182	)		(69	)		(1,604	)		(76	)
End of year		6,443			230			7,068			297			8,300			396

Proved developed reserves-
End of year		6,443			230			7,068			297			8,300			396

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. The standardized measure of discounted future net cash flows is presented as follows (in thousands):

	Years Ended December 31,
	2008			2007			2006

Future gross revenues	$	42,058		$	74,133		$	69,540
Future costs -
Lease operating expenses		(11,057	)		(20,792	)		(20,677	)
Development costs		(816	)		(860	)		(684	)
Future net cash flows before income taxes		30,185			52,481			48,179
Discount at 10% per annum		(12,421	)		(22,344	)		(17,904	)
Discounted future net cash flows
before income taxes		17,764			30,137			30,275
Future income taxes, net of discount at
10% per annum		(6,217	)		(10,547	)		(11,505	)
Standardized measure of discounted
future net cash flows	$	11,547		$	19,590		$	18,770

The reserve estimates provided at December 31, 2008, 2007 and 2006 are based on year-end market prices of $37.87, $92.50 and $57.00 per barrel for crude oil and $5.65, $7.31 and $5.58 per mcf for natural gas, respectively.

The following are the principal sources of changes in the standardized measure of discounted future net cash flows (in thousands):

	Years Ended December 31,
	2008			2007			2006
Beginning of year	$	19,590		$	18,770		$	29,960
Revisions to reserves proved in prior years -
Net change in prices and production costs		(10,041	)		6,072			(14,234	)
Net change due to revisions in quantity estimates		(6,293	)		(664	)		(12,078	)
Accretion of discount		2,234			1,790			3,512
Production rate changes and other		2,679			(2,424	)		(998	)
Total revisions		(11,421	)		4,774			(23,798	)
Sale of oil and gas reserves		-			(3,503	)		-
New field discoveries and extensions, net of future
production costs		11,571			8,294			18,445
Sales of oil and gas produced, net of production costs		(12,523	)		(9,703	)		(12,694	)
Net change in income taxes		4,330			958			6,857
Net change in standardized measure of discounted
future net cash flows		(8,043	)		820			(11,190	)
End of year	$	11,547		$	19,590		$	18,770

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 (in thousands):

	Years Ended December 31,
	2008			2007			2006

Revenues	$	17,248		$	13,783		$	16,950
Oil and gas property sale		-			12,078			-
Costs and expenses -
Production		(4,725	)		(4,080	)		(4,256	)
Producing property impairment		(3,078	)		(1,216	)		(841	)
Exploration		(6,030	)		(5,507	)		(2,895	)
Depreciation, depletion and amortization		(6,763	)		(5,833	)		(3,603	)
Operating income (loss) before income taxes		(3,348	)		9,225			5,355
Income tax expense (benefit)		1,172			(3,229	)		(1,875	)
Operating income (loss)	$	(2,176	)	$	5,996		$	3,480

Item 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

Item 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

The Company maintains “disclosure controls and procedures” (as defined in Rule 13a-15(e) and 15d-15(e) under the Securities and Exchange Act of 1934, as amended (the “Exchange Act”) that are designed to ensure that information required to be disclosed in the reports that the Company files or submits under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and is accumulated and communicated to management, including the Company’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely discussions regarding required disclosure. As of the end of the period covered by this annual report, an evaluation was carried out under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures. Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective as of December 31, 2008.

Management’s Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s Chief Executive Officer and the Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies and procedures may deteriorate.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2008. In making this assessment, management used the criteria described in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management concluded that it maintained effective internal control over financial reporting as of December 31, 2008.

This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by a registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.

This Management’s Report on Internal Control Over Financial Reporting shall not be deemed “filed” for purposes of Section 18 of the Exchange Act or incorporated by reference in any filing under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such a filing.

Changes in Internal Control Over Financial Reporting.

There have not been any changes in the Company’s internal control over financial reporting during the fiscal quarter ended December 31, 2008 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 9B. OTHER

None.

PART III

Item 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information concerning directors, corporate governance and executive officers of the Company is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Shareholders to be held May 27, 2009, under the heading “Election of Directors” and “Executive Officers”, respectively, 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.

EXECUTIVE COMPENSATION

The information required by Item 11 is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Shareholders to be held May 27, 2009, under the heading “Executive Compensation” 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 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by Item 12 is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Shareholders to be held May 27, 2009, under the heading “Voting Securities and Principal Holders Thereof” 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 13.

CERTAIN RELATIONSHIPS, RELATED PARTY TRANSACTIONS AND DIRECTOR INDEPENDENCE

The information required by Item 13 is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Shareholders to be held May 27, 2009, under the headings “Transactions with Related Parties” and “Director Independence” 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 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by Item 14 is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Shareholders to be held May 27, 2009, under the heading “Principal Accounting Fees and Services” to be filed with the Commission not later than 120 days after the end of the fiscal year covered by this Form 10-K.

PART IV

Item 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as a part of this Form 10-K:

1. Financial Statements

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of December 31, 2008 and 2007

Consolidated Statements of Operations for the Years Ended

December 31, 2008, 2007 and 2006

Consolidated Statements of Shareholders' Equity for the Years Ended

December 31, 2008, 2007 and 2006

Consolidated Statements of Cash Flows for the Years Ended

December 31, 2008, 2007 and 2006

Notes to Consolidated Financial Statements

2.	All financial schedules have been omitted because they are not applicable or the required information is shown in the financial statements or notes thereto.

3.	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 (-File No. 1-7908) 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 (-File No. 1-7908) of the Company for the fiscal year ended December 31, 1986)

3(d)

Adams Resources & Energy, Inc. and Subsidiaries’ Code of Ethics (Incorporated by reference to Exhibit 3(d) of the Annual Report on Form 10-K (-File No. 1-7908) of the Company for the fiscal year ended December 31, 2002)

4(a)

Specimen common stock Certificate (Incorporated by reference to Exhibit 4(a) of the Annual Report on Form 10-K of the Company (-File No. 1-7908) for the fiscal year ended December 31, 1991)

4(b)

Loan Agreement between Adams Resources & Energy, Inc. and NationsBank Texas N.A. dated October 27, 1993 (Incorporated by reference to Exhibit 4(b) of the Annual Report on Form 10-K of the Company for the fiscal year ended December 31, 1993)

10.1	- Change in control/severance agreement dated July 25, 2008 by and between Adams Resources & Energy, Inc. and Richard B. Abshire (Incorporated by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on July 25, 2008).

21*

Subsidiaries of the Registrant

31.1*

Adams Resources & Energy, Inc. Certification Pursuant to 17 CFR 13a-14 (a)/15d-14(a), As adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2*

Adams Resources & Energy, Inc. Certification Pursuant to 17 CFR 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1*

Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2*

Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

______________________________

* - Filed herewith

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.

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, Director	Chairman of the Board and
and Chief Financial Officer)	Chief Executive Officer)

Date: March 20, 2009

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/ Frank T. Webster	By /s/ E. C. Reinauer, Jr.
(Frank T. Webster, Director)	(E. C. Reinauer, Jr., Director)



By /s/ Larry E. Bell	By /s/ E. Jack Webster, Jr.
(Larry E. Bell, Director)	(E. Jack Webster, Jr., Director)

EXHIBIT INDEX

Exhibit

Number Description

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)

3(d)	- Adams Resources & Energy, Inc. and Subsidiaries’ Code of Ethics (Incorporated by reference to Exhibit 3(d) of the Annual Report on Form 10-K of the Company for the fiscal year ended December 31, 2002)

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)

4(b)	- Loan Agreement between Adams Resources & Energy, Inc. and NationsBank Texas N.A. dated October 27, 1993 (Incorporated by reference to Exhibit 4(b) of the Annual Report on Form 10-K of the Company for the fiscal year ended December 31, 1993)

10.1	- Change in control/severance agreement dated July 25, 2008 by and between Adams Resources & Energy, Inc. and Richard B. Abshire (Incorporated by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on July 25, 2008).

21*	- Subsidiaries of the Registrant

31.1*

- Certification Pursuant to 17 CFR 13a-14(a)/15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2*

- Certification Pursuant to 17 CFR 13a-14(a)/15d-14(a), As Adopted Pursuant to Section302 of the Sarbanes-Oxley Act of 2002

32.1*

- Certification Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2*

- Certification Pursuant To 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

______________________________

* - Filed herewith