10-K

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, 2011

OR

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	17 South Briar Hollow Lane  Ste 100	77027
		Houston, Texas
(State of Incorporation)	(I.R.S. Employer Identification No.)	(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:

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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  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 non-affiliates as of the close of business on June 30, 2011 was $52,992,199 based on the closing price of $25.34 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, 2012.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held May 16, 2012 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, 2011 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 or 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 by the Company with the Securities and Exchange Commission from time to time and the important factors described under “Item 1A. Risk Factors” 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 23,450 square feet of office space located at 17 South Briar Hollow Lane Suite 100, 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, 2011 are set forth in Note 8 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 2011, Gulfmark purchased approximately 81,600 barrels per day of crude oil at the wellhead or lease level. Gulfmark also operates 148 tractor-trailer rigs and maintains over 54 pipeline inventory locations or injection stations.  Gulfmark has the ability to barge oil from three oil storage facilities along the intercoastal waterway of Texas and Louisiana and maintains 180,000 barrels of storage capacity at certain of the dock facilities in order to access waterborne markets for its products.  Gulfmark delivers physical supplies to refiner 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.  During 2011, Gulfmark had sales to four customers that comprised 18.2 percent, 15.4 percent, 13.4 percent, and 11.3 percent, respectively, of total Company wide revenues.  Management believes that a loss of any of these customers would not have a material adverse effect on the Company’s operations.  See also Note 3 of Notes to Consolidated Financial Statements.

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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 2011, ARM purchased approximately 208,000 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, marketed branded and unbranded refined petroleum products such as motor fuels and lubricants.  In February 2012, the Company sold substantially all equipment, inventory and contracts associated with this operation.  The company retained Ada’s former distribution and warehousing facility located on 5.5 Company-owned acres in Houston, Texas.  See Note (10) of Notes to Financial Statements for additional discussion.

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 United States. Department of Transportation (“DOT”).   STC operates 285 truck tractors of which 12 are independent owner-operator units and maintains 447 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 in Texas and the south central region of the United States. AREC’s offices are maintained in Houston and the Company holds an interest in 405 wells of which 41 are Company operated.

Producing Wells--The following table sets forth the Company's gross and net productive wells as of December 31, 2011. 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.

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	Oil Wells				Gas Wells				Total Wells
	Gross		Net		Gross		Net		Gross		Net
Texas		99		9.80		158		12.35		257		22.15
Other		94		4.32		54		5.42		148		9.74
		193		14.12		212		17.77		405		31.89

Acreage--The following table sets forth the Company's gross and net developed and undeveloped acreage as of December 31, 2011.  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.  The Company’s ownership in undeveloped acreage is substantially all in the form of a non-operated minority interest.  As such, the Company relies on the third party operator to manage the lease holdings.

	Developed Acreage				Undeveloped Acreage
	Gross		Net		Gross		Net
Texas		122,884		10,924		217,802		17,849
Kansas		150		15		18,157		1,815
Other		8,202		1,072		1,701		675
		131,236		12,011		237,660		20,339

Drilling Activity--The following table sets forth the Company's drilling activity for each of the three years ended December 31, 2011.  All drilling activity was onshore in Texas, Louisiana, Arkansas and Kansas.

	2011				2010				2009
	Gross		Net		Gross		Net		Gross		Net
Exploratory wells drilled
- Productive		-		-		-		-		2		.10
- Dry		8		.87		12		.67		7		.94
Development wells drilled
- Productive		75		2.10		41		1.77		24		1.35
- Dry		3		.18		-		-		2		.10
		86		3.15		53		2.44		35		2.49

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, 2011, are presented in the table below (in thousands):

	December 31,
	2011		2010		2009
Crude oil (thousands of barrels)		292		267		242
Natural gas (thousands of mcf)		9,661		7,794		7,248
Standardized measure of discounted future
net cash flows from oil and natural gas  reserves	$	20,931	$	16,672	$	9,305

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, 2011, 2010 and 2009 are based on market prices of $95.85, $76.14 and $58.43 per barrel for crude oil and $4.69, $5.26 and $4.05 per mcf for natural gas, respectively.  For 2011 and 2010, such prices were based on the unweighted arithmetic average of the prices in effect on the first day of the month for each month of the respective twelve month periods as required by Security and Exchange Commission (“SEC”) regulations.  For 2009, the price reflects the market price on December 31, 2009.  The price reported for natural gas includes the value of associated natural gas liquids.

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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, the pricing assumptions utilized as well as the skill and judgment of petroleum engineers in interpreting such data.  The process of estimating reserves requires frequent revision of estimates 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, 2011 was as follows:

Years Ended	Crude Oil		Natural
December 31,	(barrels)		Gas (mcf)
2011		61,500		1,895,000
2010		54,000		1,365,000
2009		49,500		1,304,000

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

	Years Ended December 31,
	2011		2010		2009
Average oil and condensate
sales price per barrel	$	93.23	$	77.09	$	58.10
Average natural gas
sales price per mcf	$	4.39	$	5.02	$	4.43
Average production cost, per equivalent
barrel, charged to expense	$	16.79	$	13.99	$	13.25

The Company has had no reports to federal authorities or agencies of estimated 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.

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.

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-   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.

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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 has not owned or operated underground tanks for more than 10 years, historically the Company was 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 operated 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 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 actions 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 actions 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, 2011, the Company is unaware of any unresolved environmental issues for which additional accounting accruals are necessary.

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Employees

At December 31, 2011 the Company employed 780 persons, 15 of whom were employed in the exploration and production of oil and gas, 345 in the marketing of crude oil, natural gas and petroleum products, 399 in transportation operations, and 21 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.

Recent Event

On February 27, 2012, the Company completed the sale of certain assets previously associated with the Company’s refined products marketing segment.  Assets sold included equipment, tanks and trucks, as well as all refined petroleum product inventories and substantially all supplier and customer contracts associated with this business segment.  With the consummation of this transaction, the Company exited the refined petroleum products marketing business.  The Company’s former refined petroleum products operation was active in the distribution and sale of lube oils and motor fuels such as gasoline and diesel.  Sales proceeds totaled $2,000,000 plus the market value of inventories.  The Company will continue to collect any outstanding accounts receivable and satisfy all account payable obligations associated with this business.  See discussion under “Subsequent Event” in Note 10 to the Consolidated Financial Statements.

Available Information

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 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

17 South Briar Hollow Lane, Ste 100

Houston, Texas 77027

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Item 1A. RISK FACTORS

Economic developments could damage operations and materially reduce profitability and cash flows.

Potential disruptions in the credit markets and concerns about global economic growth could have a significant adverse impact on global financial markets and commodity prices.  Such factors could contribute to a decline in the Company’s stock price and corresponding market capitalization.  Should commodity prices experience  a period of rapid decline, future earnings will be reduced.  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 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 are cyclical in nature.  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 strong U.S. dollar exchange rate tends to suppress export demand for petrochemicals which is adverse to the Company’s transportation operation.  Conversely, a weak U. S. dollar exchange rate tends to stimulate export demand for petrochemicals.

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.  Trade credit arrangements are relied upon as a significant source of liquidity for capital requirements not satisfied by operating cash flow.

Should global financial markets and economic conditions disrupt and reduce stability in general and the solvency of creditors specifically, the availability of funding from credit markets would be reduced as many lenders and institutional investors would enact tighter lending standards, refuse to refinance existing debt on terms similar to current debt or in some cases, cease to provide funding to borrowers.  These issues coupled with weak economic conditions would 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 of 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 the Company’s business and operating results

Constraints in the financial markets and other macro-economic challenges that might affect the economy of the United States and other parts of the world could cause the Company’s customers to 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 would 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.

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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.

Escalating diesel fuel prices could have an adverse effect on the Company

As an integral part of the Company’s marketing and transportation businesses, the Company operates a fleet of over 400 truck-tractors and diesel fuel costs are a significant component of operating expense.  Such costs generally fluctuate with increasing and decreasing world crude oil prices. While the Company attempts to recoup rising diesel fuel costs through the pricing of its services, to the extent such costs escalate, operating earnings will generally be adversely affected.

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 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.

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 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.

Transportation of hazardous materials and the oil and gas business involves certain operating hazards such as well blowouts, automobile accidents, 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 and the states frequently review federal or state income tax legislation.  The Company cannot predict whether, when or to what extent new federal or state 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.

10

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.

Several proposals are before the U.S. Congress that, if implemented, would either prohibit the practice of hydraulic fracturing or subject the process to regulation under the Safe Drinking Water Act.   The Company routinely participates in wells where fracturing techniques are utilized to expand the available space for natural gas and oil to migrate toward the well-bore.  It is typically done at substantial depths in very tight formations.  Although it is not possible at this time to predict the final outcome of the legislation regarding hydraulic fracturing, any new federal restrictions could result in increased compliance costs or additional operating restrictions.

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 the Company’s 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 valuations 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 and/or the development costs 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 cancelled 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 prohibitive.

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:

11

·   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 exist relating to drivers, equipment and terminal facilities

The Company transports liquid combustible materials such as gasoline and petrochemicals and such materials may be a target for terrorist attacks.  While the Company employs a variety of security measures to mitigate the risk of such events no assurance can be given that such events will not occur.

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.

     The Company is subject to risks associated with  climate change.

Potential climate change and costs associated with its impact and efforts to regulate “greenhouse gas” (“GHG's”) emissions have the potential to affect the Company’s business including negatively impacting (i) the costs it incurs in providing its products and services, including costs to operate and maintain its facilities, install new emission controls on its facilities, acquire allowances to authorize its GHG emissions, pay any taxes related to GHG emissions, administer and manage a GHG emissions program, pay higher insurance premiums or accept greater risk of loss in areas affected by adverse weather and coastal regions in the event of rising sea levels, (ii) the demand for and consumption of its products and services (due to change in both costs and weather patterns), and (iii) the economic health of the regions in which it operates, all of which could have a material adverse effect on the Company’s business, financial condition, results of operations and cash flows.

The Company is subject to risks related to cybersecurity.

The Company is subject to cybersecurity risks and may incur increasing costs in connection with its efforts to enhance and ensure security and in response to actual or attempted cybersecurity attacks.

Substantial aspects of the Company’s business depend on the secure operation of its computer systems and websites. Security breaches could expose the Company to a risk of loss, misuse or interruption of sensitive and critical information and functions, including its own proprietary information and that of its customers, suppliers and employees and functions that affect the operation of the business.  Such losses could result in operational impacts, reputational harm, competitive disadvantage, litigation, regulatory enforcement actions, and liability. While the Company devotes substantial resources to maintaining adequate levels of cybersecurity, there can be no assurance that it will be able to prevent all of the rapidly evolving types of cyber attacks. Actual or anticipated attacks and risks may cause the Company to incur increasing costs for technology, personnel and services to enhance security or to respond to occurrences.

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If the Company’s security measures are circumvented, proprietary information may be misappropriated, its operations may be disrupted, and its computers or those of its customers or other third parties may be damaged. Compromises of the Company’s security may result in an interruption of operations, violation of applicable privacy and other laws, significant legal and financial exposure, damage to its reputation, and a loss of confidence in its security measures.

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.  MINE SAFETY DISCLOSURES

Not Applicable

13

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, formerly known as the American Stock Exchange, under the ticker symbol “AE”.  The following table sets forth the high and low sales prices of the common stock as reported by the NYSE Amex for each calendar quarter since January 1, 2010.

	American Stock Exchange
	High		Low
2011
First Quarter	$	31.30	$	22.46
Second Quarter		30.50		22.51
Third Quarter		29.07		18.73
Fourth Quarter		29.50		18.90
2010
First Quarter	$	23.39	$	17.40
Second Quarter		19.95		15.25
Third Quarter		21.49		16.00
Fourth Quarter		24.95		17.86

At March 12, 2012 there were approximately 235 shareholders of record of the Company's common stock and the closing stock price was $45.71 per share.  The Company has no securities authorized for issuance under equity compensation plans.  The Company made no repurchases of its stock during 2011 and 2010.

On December 15, 2011, the Company paid an annual cash dividend of $.57 per common share to common stockholders of record on December 1, 2011.  On December 15, 2010, the Company paid an annual cash dividend of $.54 per common share to common stockholders of record on December 1, 2010.  Such dividends totaled $2,404,000 and $2,277,540 for each of 2011 and 2010, respectively.

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Performance Graph

The performance graph shown below was prepared under the applicable rules of the SEC based on data supplied by Research Data Group.  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, 2006 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.

	Dec06	Dec07	Dec08	Dec09	Dec10	Dec11
Adams Resources & Energy, Inc.	100.00	86.99	59.46	78.90	89.03	108.97
S&P 500	100.00	105.49	66.46	84.05	96.71	98.75
S&P Integrated Oil & Gas	100.00	129.85	101.56	100.25	119.14	136.73

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Item 6.  SELECTED FINANCIAL DATA

FIVE YEAR REVIEW OF SELECTED FINANCIAL DATA

	Years Ended December 31,
	2011			2010			2009			2008			2007
	(In thousands, except per share data)
Revenues:
Marketing	$	3,136,838		$	2,144,082		$	1,889,583		$	4,074,677		$	2,558,545
Transportation		63,501			56,867			44,895			67,747			63,894
Oil and natural gas		14,060			11,021			8,650			17,248			13,783
	$	3,214,399		$	2,211,970		$	1,943,128		$	4,159,672		$	2,636,222
Operating earnings (loss):
Marketing	$	50,596		$	16,724		$	17,487		$	(2,704	)	$	20,152
Transportation		8,521			6,623			2,128			4,245			5,504
Oil and gas operations		(16,794	)		(1,757	)		(3,625	)		(3,348	)		(2,853	)
Oil and gas property sale		2,923			-			-			-			12,078
General and administrative		(9,713	)		(9,044	)		(9,589	)		(9,667	)		(10,974	)
		35,533			12,546			6,401			(11,474	)		23,907
Other income (expense):
Interest income		237			191			125			1,103			1,741
Interest expense		(8	)		(36	)		(25	)		(187	)		(134	)
Earnings (loss) from continuing operations
before income taxes		35,762			12,701			6,501			(10,558	)		25,514
Income tax (provision) benefit		(12,831	)		(4,070	)		(2,352	)		4,986			(8,458	)
Net earnings (loss)	$	22,931		$	8,631		$	4,149		$	(5,572	)	$	17,056
Earnings (Loss) Per Share
Basic and diluted earnings (loss) per share	$	5.44		$	2.05		$	.98		$	(1.32	)	$	4.04
Dividends per common share	$	.57		$	.54		$	.50		$	.50		$	.47
Financial Position
Cash	$	37,066		$	29,032		$	16,806		$	18,208		$	23,697
Net working capital		48,871			39,978			38,372			41,559			50,572
Total assets		378,840			301,305			249,401			210,926			357,075
Long-term debt		-			-			-			-			-
Shareholders’ equity		110,682			90,155			83,801			81,761			89,442
Dividends on common shares		2,404			2,277			2,109			2,109			1,982

________________________________

Notes:

-   In 2011 and 2007, certain oil and natural gas producing properties were sold for $6.6 million and $14.9 million producing net gains of $2.9 million and $12.1 million, respectively.

-   The 2011 oil and gas operating loss primarily resulted from property impairments totaling $14.8 million  recorded as a result of declining natural gas prices.

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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):

	2011			2010		2009
Revenues
Crude oil	$	2,961,176		$	2,005,301	$	1,770,600
Natural gas		6,251			10,592		14,232
Refined products		169,411			128,189		104,751
Total	$	3,136,838		$	2,144,082	$	1,889,583
Operating Earnings (loss)
Crude oil	$	49,237		$	13,530	$	15,404
Natural gas		2,147			3,073		2,749
Refined products		(788	)		121		(666	)
Total	$	50,596		$	16,724	$	17,487
Depreciation
Crude oil	$	3,724		$	2,320	$	1,997
Natural gas		3			44		166
Refined products		375			503		533
Total	$	4,102		$	2,867	$	2,696

Supplemental volume and price information is:

	2011		2010		2009
Field Level Purchases per day (1)
Crude Oil – barrels		81,600		69,000		66,100
Natural Gas – mmbtu’s		208,000		258,000		363,000
Average Purchase Price
Crude Oil – per barrel	$	96.77	$	77.20	$	58.32
Natural Gas – per mmbtu	$	3.93	$	4.28	$	3.75

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

Comparison 2011 to 2010

Crude oil revenues grew by 47 percent in 2011 due to both volume and price increases.  Average crude oil prices increased 25 percent and crude oil lease level volumes improved by 18 percent as shown in the table above.  The field level purchase volume growth was a result of new production from expanded drilling activity in the Eagle Ford trend of South Texas.

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Crude oil operating earnings increased significantly in 2011 due to widening unit gross margins.  This result stems from South Texas sourced crude oil selling at a discount to world oil prices due to its relative abundance in relation to the infrastructure available to deliver such oil to market.  In addition, during the second quarter of 2011, the Company completed construction of a barge terminal facility at the Port of Victoria, Texas.  This facility allows the Company to increase margins on its gathered production in the area by barging it to more advantageous markets.

Increasing crude oil prices also boosted operating earnings during 2011.  The average acquisition price of crude oil moved from $88 per barrel at the beginning of the year to $98 per barrel for December 2011, resulting in inventory liquidation gains totaling $3,021,000.  Similarly, during 2010, crude oil prices rose from the $75 per barrel range in January to the $88 per barrel range by December 2010 producing a $2,272,000 inventory liquidation gain.  As of December 31, 2011, the Company held 182,728 barrels of crude oil inventory at an average price of $98.36 per barrel.

Diesel fuel expense which tends to fluctuate in tandem with crude oil prices also has a significant impact on operating earnings.  A relatively low level of diesel fuel costs during 2009, served to improve comparative operating earnings for such year relative to 2010.  Diesel fuel cost were elevated in 2011 due to increased prices and an approximate 50 unit expansion of the truck fleet engaged to handle added volumes.  The impact on crude oil operating earnings from inventory liquidation gains and diesel fuel cost is summarized as follows (in thousands):

	2011			2010			2009
As reported operating earnings	$	49,237		$	13,530		$	15,404
Inventory liquidation (gains)		(3,021	)		(2,272	)		(5,780	)
	$	46,216		$	11,258		$	9,624
Diesel fuel expense	$	9,982		$	6,001		$	4,612

Natural gas sales are reported net of underlying natural gas purchase costs and thus reflect gross margin.  As shown above, gross margins were reduced during 2011 as average field level purchase volumes were off 19 percent for the period. Current volumes declined because the Company’s natural gas suppliers do not operate in the shale areas and therefore curtailed drilling activity due to declining natural gas prices.  The Company’s primary source of natural gas supply is the non-shale areas of Texas, Louisiana and the Gulf of Mexico.  In addition to volume declines, development of the nation’s natural gas infrastructure including more diverse areas of production and expanded pipeline and storage capacity have served to reduce purchase opportunities and per unit margins.

Operating earnings for the refined products segment continued to underperform following the downturn in the domestic economy which began during the third quarter of 2008.  Due to customer slow payment patterns, refined product operating earnings were additionally impacted in 2011 and 2009 when the bad debt provision was increased by approximately $947,000 and $560,000, respectively.   As a result of its recent market performance, in February 2012 the Company sold substantially all contracts, equipment and inventories associated with its refined products segment and is completing an orderly wind-down of this business.  Cash proceeds from the sale totaled $2 million plus the fair market value of refined product inventories and the Company will record a gain of approximately $1 million during the first quarter of 2012.

Historically, prices received for crude oil and natural gas have been volatile and unpredictable with price volatility expected to continue.  See discussion under Item 1A Risk Factors.

18

-           Transportation

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

	2011					2010					2009
	Amount		Change(1)			Amount		Change(1)			Amount		Change(1)
Revenues	$	63,501		12	%	$	56,867		27	%	$	44,895		(34	)%
Operating earnings	$	8,521		29	%	$	6,623		211	%	$	2,128		(50	)%
Depreciation	$	3,912		(9	)%	$	4,288		8	%	$	3,970		3	%

______________

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

Revenues and operating results improved for the transportation segment in both 2011 and 2010 due to increased customer demand.  The Company also benefitted in 2011 from $1.2 million in gains from the sale of used equipment following the purchase of new truck replacements.  The Company’s customers predominately consist of the domestic petrochemical industry and demand for such products has substantially recovered from the slow down occurring in 2009.  Serving to improve customer demand was a recovering United States economy, relatively low natural gas prices and improved export demand for petrochemicals.  In addition, during the previous economic downturn, the trucking industry reduced capacity by retiring older units without replacement.  With demand improvement, industry capacity has been strained allowing rate increases and improved overall profitability.  As transportation revenues increase or decrease, operating earnings will typically increase or decrease at an accelerated rate.  This trend exists because the fixed cost components of the Company’s operation do not vary with changing revenues.  As currently configured, operating earnings project at break-even levels when annual revenues average approximately $50 million.  Above that level, operating earnings will grow and below that level losses result.

Transportation segment depreciation increased for 2011 and 2010 relative to 2009 as older fully depreciated tractor units were replaced with new model year vehicles with a portion of the 2011increase offset by certain in-service trailers becoming fully depreciated during the periods.   During 2011 the Company replaced 115 older model tractor units and added 10 new units to the fleet.  Tractor replacement for 2010 and 2009 totaled 50 units and 75 units, respectively.  In addition 25 trailers were added to the fleet during 2011.

-           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):

	2011						2010						2009
	Amount			Change(1)			Amount			Change(1)			Amount			Change(1)
Revenues	$	14,060			28	%	$	11,021			27	%	$	8,650			(50	)%
Operating earnings (loss)(2)		(16,794	)		856	%		(1,757	)		51	%		(3,625	)		8	%
Depreciation and depletion		8,246			77	%		4,662			28	%		3,654			(46	)%
Producing property impairments		7,105			651	%		946			(30	)%		1,350			(56	)%

______________

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

(2)   Excludes gains from property sales

19

The revenue improvement for the oil and gas segment during 2011 and 2010 is primarily attributable to crude oil and natural gas volumes increases as shown in the table below.  Volumes improved with the results of recent drilling efforts.  Operating earnings declined due to increased charges for depreciation, depletion and producing property impairments as well as increased exploration and impairment expenses as shown in the second table below.  Depreciation and depletion expense increased in both 2011 and 2010 with increased volumes and as the depreciable property basis grew from capital expenditures.  Producing and non-producing property impairments resulted in 2011 following a significant December 2011 decline in the current and forward price for natural gas.

Comparative volumes and prices were as follows:

	2011			2010			2009
Production Volumes
- Crude Oil		61,500	bbls		54,000	bbls		49,500	bbls
- Natural Gas		1,895,000	mcf		1,365,000	mcf		1,304,000	mcf
Average Price
- Crude Oil	$	93.23	bbls	$	77.09	bbls	$	58.10	bbls
- Natural Gas	$	4.39	mcf	$	5.02	mcf	$	4.43	mcf

Comparative exploration and impairment costs were as follows (in thousands):

	2011		2010		2009
Dry hole expense	$	1,212	$	1,894	$	661
Prospect impairment		7,644		1,277		2,423
Seismic and geological		310		62		734
Total	$	9,166	$	3,233	$	3,818

During 2011, the Company participated in the drilling of 86 wells with 75 successful and 11 dry holes. Additionally, the Company had 40 wells in process on December 31, 2011 with ultimate evaluation anticipated during 2012.    Converting natural gas volumes to equate with crude oil volumes at a ratio of six to one, oil and gas production volumes and proved reserve changes summarized as follows on an equivalent barrel (Eq. Bbls) basis:

	2011			2010			2009
	(Eq. Bbls.)			(Eq. Bbls.)			(Eq. Bbls.)
Proved reserves – beginning of year		1,566,000			1,450,000			1,304,000
Estimated reserve additions		1,209,000			536,000			439,000
Production volumes		(377,000	)		(282,000	)		(267,000	)
Producing properties sold		(385,000	)		-			-
Revisions of previous estimates		(106,000	)		(138,000	)		(26,000	)
Proved reserves - end of year		1,907,000			1,566,000			1,450,000

During 2011 and in total for the three year period ended December 31, 2011, estimated reserve additions represented 320 percent and 235 percent, respectively, of production volumes.

20

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

East Texas Project

In 2005, the Company joined with its partners in acquiring exploration acreage in Nacogdoches and Shelby Counties, Texas.  This was subsequently expanded to include acreage in Angelina County, due south of Nacogdoches County.  This investment holds potential in the Haynesville/Bossier shale formations.   Subsequent drilling determined that a “sweet spot” existed. A total of 86 wells were drilled to date with 66 wells on production and 20 wells currently in the completion stage.   The Company’s interest in this project varies from two percent to five percent with an average 2.7 percent ownership in the properties and wells. Production is dry gas and due to current low prices, only 24 wells are planned for 2012 to secure the Company’s acreage position.  Approximately 64,000 gross acres are now held by production with 11,700 additional acres under option to earn through drilling. In-field development of this property will resume when justified by higher natural gas prices.

West Texas Project

In 2008, the Company participated with an approximate two percent working interest in the acquisition of approximately 49,015 acres located in Irion and Crockett Counties, Texas for the purpose of developing the Wolfcamp shale. An aggressive horizontal drilling program is now underway.  A total of 54 wells have been drilled with 38 wells on production and 15 wells being completed.  Drilling is expected to accelerate in 2012 with 72 wells scheduled to spud.  Production from the Wolfcamp in this area is oil-rich, with large amounts of gas and natural gas liquids.

South Texas Project

This project includes two approved prospects in the Eagle Ford trend of South Texas with approximately 31,000 acres currently under lease.  The goal of this investment is to extend the productive area of the Eagle Ford trend north in Fayette and Lavaca Counties, Texas.  The first core well has been drilled and indications are positive with petrochemical data showing the project is on the gas condensate window.  Drilling plans initially call for the first horizontal test well to spud during the second quarter of 2012.  The Company holds a five percent working interest in this project.

 - Oil and gas property sales

In January 2011, the Company completed the sale of its interest in certain producing oil and gas properties located in the on-shore Gulf Coast region of Texas.  Proceeds from the sale totaled $6.2 million and the pre-tax gain from this transaction totaled $2,708,000.  Total proved reserves sold were approximately 26,000 barrels of crude oil and 2,148,000 mcf of natural gas.  Sales negotiations were conducted by the third party operator of the properties on behalf of all working interest owners and the transaction was completed with a separate third party investment entity.  The Company’s proportionate interest in the transaction was approximately 5 percent and the Company elected to participate in the sale due to attractive pricing.  Also during the first quarter of 2011, the Company sold a portion of its interest in certain non-producing oil and gas properties located in West Texas.  Total proceeds from the sale were $329,000 and the Company recorded a $125,000 gain from this transaction.  Proceeds from the sales were used for general working capital purposes and the Company is continuing with oil and gas exploration operations in the vicinity of the properties sold.  In October 2011, the Company sold an interest in certain non-producing properties for $90,000 in proceeds and gain.

21

-   General and administrative, interest income and income tax

General and administrative expenses were consistent during the three year review period ending December 31, 2011 except during 2011  such costs were elevated due to employee bonuses.  Interest income declined for 2011, 2010 and 2009 as interest rates on overnight deposits declined to near zero following the significant turmoil that occurred in the financial markets during the fall of 2008.  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

The short-term outlook presumes continued volume and margin strength within the crude oil marketing operation.  Industry competitors and Company suppliers are aware of the present opportunity, however, and are actively seeking to capture such advantage and unit margins have begun to shrink.  Over the course of the mid-term time horizon (3 - 6 months from current date) management anticipates crude oil marketing margins will return to their approximate historical levels.  Transportation results slowed in late 2011 but generally look to be stable for 2012.  Within the oil and gas segment, declining natural gas prices will, in all likelihood, offset volume increases from the new wells coming on line in 2012.  However, absent further declines in commodity prices, the recurrence of property impairment charges is unlikely in 2012.  In contrast, should recent escalation in diesel fuel costs continue, 2012 marketing and transportation earnings could be adversely affected to some extent.

The Company has the following major objectives for 2012:

-   Maintain marketing operating earnings at the $28 million level exclusive of inventory valuation gains or losses.

-   Maintain transportation operating earnings at the $6 million level excluding gains from the sale of used equipment.

-   Return oil and gas operating earnings to the $2 million level and replace 2011 production with current reserve additions.

Liquidity and Capital Resources

The Company’s liquidity primarily derives from net cash provided from operating activities, which was $55,815,000, $36,928,000 and $22,285,000 for each of 2011, 2010 and 2009, respectively.  As of December 31, 2011 and 2010, the Company had no bank debt or other forms of debenture obligations.  Cash and cash equivalents totaled $37,066,000 as of December 31, 2011, 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 $48,808,000 as of December 31, 2011.

Capital expenditures during 2011 included $27,802,000 for marketing and transportation equipment additions, primarily consisting of truck-tractors, and $24,580,000 in property additions associated with oil and gas exploration and production activities.  For 2012, the Company anticipates expending an additional approximately $19 million on oil and gas development and exploration projects.  In addition, approximately $17 million will be expended during 2012 for the purchase of 167 truck-tractors for the transportation segment and approximately $5.3 million will be expended for the purchase of 31 truck-tractors and 18 trailers for the marketing segment with funding for such purchase from available cash flow.  These units will serve to replace older units and to increase the marketing fleet.  Funding for these 2012 projects will be from operating cash flow and available working capital.  Within certain constraints, the proposed projects can be delayed or cancelled should funding become unavailable.

22

From time to time, the Company may make cash prepayments to certain suppliers of crude oil and natural gas for the Company’s marketing operations.  Such prepayments totaled $6,521,000 as of December 31, 2011 and such amounts will be recouped and advanced from month to month as the suppliers deliver product to the Company.  The Company also requires certain counterparties to post cash collateral with the Company in order to support their purchase from the Company.  Such cash collateral held by the Company totaled $721,000 as of December 31, 2011.  The Company also maintains a stand-by letter of credit facility with Wells Fargo Bank to provide for the issuance of up to $60 million in stand-by letters of credit to the Company’s suppliers of crude oil and natural gas (see Note 1 to Financial Statements).  The issuance of stand-by letters of credit enables the Company to avoid posting cash collateral when procuring crude oil and natural gas supply.  As of December 31, 2011, letters of credit outstanding totaled $38.9 million.  Management believes current cash balances, together with expected cash generated from future operations, and the ease of financing truck and trailer additions through leasing arrangements (should the need arise) 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 periods in this filing.  The Company does not look to proceeds from property sales to fund its cash flow needs.  Except for an approximate $10.7 million commitment for transportation equipment, operating leases and storage tank terminal arrangements and office lease space, the Company’s future commitments and planned investments can be readily curtailed if operating cash flows contract.

Historically, the Company pays an annual dividend in the fourth quarter of each year, and the Company paid a $.57 per common share dividend or $2,404,000 to shareholders of record as of December 1, 2011.

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).

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.  In addition, the Company has entered into certain lease and terminal access contracts in order to provide tank storage and dock access for its crude oil marketing business.  Such contracts require certain minimum monthly payments for the term of the contracts.   All operating lease commitments qualify for off-balance sheet treatment.  Rental expense for the years ended December 31, 2011, 2010, and 2009 was $7,621,000, $5,870,000 and $6,898,000, respectively.  As of December 31, 2011, rental commitments under long-term non-cancelable operating leases and terminal arrangements for the next five years are payable as follows:  2012 - $3,059,000; 2013 - $2,148,000; 2014 - $1,468,000; 2015 - $1,201,000; 2016 – $1,181,000 and $1,602,000 thereafter.

Contractual Cash Obligations

The Company has no capital lease obligations.  The Company has entered into certain operating lease arrangements and terminal access agreements for tankage, truck-tractors, trailers and office space.    A summary of the payment periods for contractual cash obligations is as follows (in thousands):

	2012		2013		2014		2015		2016		Thereafter		Total
Lease payments	$	3,059	$	2,148	$	1,468	$	1,201	$	1,181	$	1,602	$	10,659

23

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, 2011 are as follows (in thousands):

	January		Remaining
	2012		2012		2013		2014		Thereafter		Total
Crude Oil	$	242,942	$	1,473	$	-	$	-	$	-	$	244,415
Natural Gas		8,622		260		-		-		-		8,882
	$	251,564	$	1,733	$	-	$	-	$	-	$	253,297

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 worker’s compensation, automobile and umbrella coverage for its trucking fleet and medical insurance for employees.  During each of 2011, 2010 and 2009, insurance costs were consistent with activity and totaled $11.2 million, $10 million and $10.5 million, respectively.  Insurance cost may experience renewed rate increases during 2012 subject to market conditions.  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 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 during 2011, 2010 and 2009.

The Company utilizes a market approach to valuing its commodity 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, 2011, all of the Company’s market value measurements were based on either quoted prices in active markets (Level 1 inputs) or from inputs based on observable market data (Level 2 inputs). See discussion under “Fair Value Measurements” in Note 1 to the Consolidated Financial Statements.

24

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.

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 the 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, the pricing assumptions utilized 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.

25

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 appropriate accounting literature guidelines.

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. See discussion under Revenue Recognition policy in Note 1 of the 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 January 2010, the Financial Accounting Standards Board (“FASB”) issued FASB Accounting Standards Update (ASU) No. 2010-03, “Oil and Gas Reserve Estimations and Disclosures” (ASU No. 2010-03).  This update aligns the current oil and gas reserve estimation and disclosure requirements of the Extractive Industries – Oil and Gas topic of the ASC (ASC Topic 932) with the changes required by the SEC final rule, “Modernization of Oil and Gas Reporting,” as discussed above.  ASU No. 2010-03 expands the disclosures required for equity method investments, revises the definition of oil and gas producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or gas, amends the definition of proved oil and gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and gas quantities and provides guidance on geographic area with respect to disclosure of information about significant reserves.  ASU No. 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate.  The Company adopted ASU No. 2010-03 effective December 31, 2009.

In May 2011, the FASB issued ASU 2011-04, which further amends the Fair Value Measurements and Disclosures topic of the Accounting Standards Codification.  Among other provisions, ASU 2011-04 expands and modifies certain principles and requirements for measuring fair value and disclosing fair value measurement information.  ASU 2011-04 is effective for interim and fiscal periods beginning after December 15, 2011.  The adoption of ASU 2011-04 is not expected to have a material impact on the Company’s financial statements, but may result in additional disclosures regarding fair value measurements.

In December 2011, the FASB issued FASB Accounting Standards Update (ASU) 2011-11.  This update requires additional disclosures about an entity’s right of setoff and related arrangements associated with its financial and derivative instruments.  The ASU requires a tabular presentation that reflects the gross, net and setoff amounts associated with such assets and liabilities among other requirements.  The expanded disclosure requirements are effective for the annual reporting periods beginning on January 1, 2013.  The adoption of ASU 2011-11 is not expected to result in significant additional disclosures.

26

Management believes the impact of other recently issued standards and updates, which are not yet effective, will not have a material impact on the Company’s consolidated financial position, results of operations or cash flows upon adoption.

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 had no long-term debt outstanding at December 31, 2011 and 2010.  A hypothetical ten 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, 2011.

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 eighteen-month term with no contracts extending longer than two 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 in the United States. The fair value of such contracts is reflected in 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, 2010 through December 31, 2011 natural gas price realizations ranged from a monthly low of $3.42 per mmbtu to a monthly high of $5.80 per mmbtu.  Crude oil prices ranged from a monthly average low of $70.90 per barrel to a high of $109.94 per barrel during the same period. A hypothetical ten percent adverse change in average natural gas and crude oil prices, assuming no changes in volume levels, would have reduced earnings by approximately $3,252,000 and $2,393,000 for the comparative years ended December 31, 2011 and 2010, respectively.

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ITEM 8.  FINANCIAL STATEMENTS

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS

	Page
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM		29
FINANCIAL STATEMENTS:
Consolidated Balance Sheets as of December 31, 2011 and 2010		30
Consolidated Statements of Operations for the Years Ended
December 31, 2011, 2010 and 2009		31
Consolidated Statements of Shareholders’ Equity for the Years Ended
December 31, 2011, 2010 and 2009		32
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2011, 2010 and 2009		33
Notes to Consolidated Financial Statements		34

28

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, 2011 and 2010, and the related consolidated statements of operations, shareholders’ equity and cash flows for each of the three years in the period ended December 31,2011.  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, 2011 and 2010, and the results of their operations and their cash flows for the each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the Consolidated Financial Statements, the Company changed its method of accounting for oil and natural gas reserves and disclosures on December 31, 2009.

/s/DELOITTE & TOUCHE LLP

Houston, Texas

March 22, 2012

29

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands)

	December 31,
ASSETS	2011			2010
CURRENT ASSETS:
Cash and cash equivalents	$	37,066		$	29,032
Accounts receivable, net of allowance for doubtful accounts of
$2,205 and $1,064, respectively		234,515			190,169
Inventories		20,189			14,591
Fair value contracts		2,064			2,764
Income tax receivable		480			2,316
Prepayments		10,651			8,104
Total current assets		304,965			246,976
PROPERTY AND EQUIPMENT:
Marketing		38,467			25,407
Transportation		54,359			43,131
Oil and gas (successful efforts method)		81,668			73,011
Other		1,553			188
		176,047			141,737
Less – Accumulated depreciation, depletion and amortization		(106,812	)		(94,148	)
		69,235			47,589
OTHER ASSETS:
Oil and gas property held for sale		-			3,389
Deferred income tax asset		473			374
Cash deposits and other		4,167			2,977
	$	378,840		$	301,305
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	248,656		$	200,763
Accounts payable – related party		58			9
Fair value contracts		681			1,478
Accrued and other liabilities		6,194			3,894
Current deferred income taxes		505			854
Total current liabilities		256,094			206,998
LONG-TERM DEBT		-			-
OTHER LIABILITIES:
Asset retirement obligations		1,568			1,390
Deferred taxes and other liabilities		10,496			2,762
		268,158			211,150
COMMITMENTS AND CONTINGENCIES (NOTE 6)
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		98,567			78,040
Total shareholders’ equity		110,682			90,155
	$	378,840		$	301,305

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

30

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	Years Ended December 31,
	2011			2010			2009
REVENUES:
Marketing	$	3,136,838		$	2,144,082		$	1,889,583
Transportation		63,501			56,867			44,895
Oil and natural gas		14,060			11,021			8,650
		3,214,399			2,211,970			1,943,128
COSTS AND EXPENSES:
Marketing		3,082,140			2,124,491			1,869,400
Transportation		51,068			45,956			38,797
Oil and gas operations		22,608			8,116			8,621
Oil and gas property sale (gain)		(2,923	)		-			-
General and administrative		9,713			9,044			9,589
Depreciation, depletion and amortization		16,260			11,817			10,320
		3,178,866			2,199,424			1,936,727
Operating Earnings		35,533			12,546			6,401
Other Income (Expense):
Interest income		237			191			125
Interest expense		(8	)		(36	)		(25	)
Earnings before income taxes		35,762			12,701			6,501
Income Tax (Provision) Benefit:
Current		(5,523	)		(371	)		(1,280	)
Deferred		(7,308	)		(3,699	)		(1,072	)
		(12,831	)		(4,070	)		(2,352	)
Net Earnings	$	22,931		$	8,631		$	4,149
EARNINGS PER SHARE:
Basic and diluted net earnings per share	$	5.44		$	2.05		$	.98

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

31

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, 2009	$	422	$	11,693	$	69,646		$	81,761
Net earnings		-		-		4,149			4,149
Dividends paid on common stock		-		-		(2,109	)		(2,109	)
BALANCE, December 31, 2009	$	422	$	11,693	$	71,686		$	83,801
Net earnings		-		-		8,631			8,631
Dividends paid on common stock		-		-		(2,277	)		(2,277	)
BALANCE, December 31, 2010	$	422	$	11,693	$	78,040		$	90,155
Net earnings		-		-		22,931			22,931
Dividends paid on common stock		-		-		(2,404	)		(2,404	)
BALANCE, December 31, 2011	$	422	$	11,693	$	98,567		$	110,682

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

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Years Ended December 31,
	2011			2010			2009
CASH PROVIDED BY OPERATIONS:
Net earnings	$	22,931		$	8,631		$	4,149
Adjustments to reconcile net earnings to net cash
from operating activities-
Depreciation, depletion and amortization		16,260			11,817			10,320
Property sale (gains) losses		(4,394	)		94			(177	)
Dry hole costs incurred		1,212			1,894			661
Impairment of oil and natural gas properties		14,749			2,224			3,773
Provision for doubtful accounts		1,141			29			430
Deferred income taxes		7,308			3,699			1,072
Net change in fair value contracts		(97	)		(1,036	)		251
Decrease (increase) in accounts receivable		(45,487	)		(34,257	)		(36,515	)
Decrease (increase) in inventories		(5,598	)		669			(1,053	)
Decrease (increase) in income tax receivable		1,836			(145	)		1,458
Decrease (increase) in prepayments		(2,547	)		2,700			(5,580	)
Increase (decrease) in accounts payable		47,662			40,521			43,069
Increase (decrease) in accrued and other liabilities		1,378			(406	)		(58	)
Other changes, net		(539	)		494			485
Net cash provided by operating activities		55,815			36,928			22,285
INVESTING ACTIVITIES:
Property and equipment additions		(53,276	)		(22,421	)		(22,390	)
Insurance and state collateral (deposits) refunds		(495	)		(151	)		(192	)
Proceeds from property sales		8,394			147			1,004
Redemption of short-term investments		11,098			-			-
Investment in short-term investments		(11,098	)		-			-
Net cash (used in) investing activities		(45,377	)		(22,425	)		(21,578	)
FINANCING ACTIVITIES:
Dividend payments		(2,404	)		(2,277	)		(2,109	)
Net cash (used in) financing activities		(2,404	)		(2,277	)		(2,109	)
Increase (decrease) in cash and cash equivalents		8,034			12,226			(1,402	)
Cash and cash equivalents at beginning of year		29,032			16,806			18,208
Cash and cash equivalents at end of year	$	37,066		$	29,032		$	16,806

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

33

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  intercompany accounts and transactions.  The impact on the accompanying financial statements of events occurring after December 31, 2011 has been evaluated through the date of issuance of these financial statements.

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 and Cash Equivalents

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 corporate and municipal bonds, which are classified as investments in marketable securities, may also be made from time to time.  Cash and cash equivalents are maintained with major financial institutions and such deposits may exceed the amount of federally backed insurance provided.  While the Company regularly monitors the financial stability of such institutions, cash and cash equivalents ultimately remain at risk subject to the financial viability of such institutions.

Marketable Securities

From time to time, the Company may invest in marketable securities consisting of investment grade corporate bonds traded in liquid markets.  Such bonds are held for the purpose of investing in liquid funds and are not generally intended to be retained on a long term basis.  Marketable securities are initially recognized at acquisition costs inclusive of transaction costs and are classified as trading securities.  In subsequent periods marketable securities are valued at fair value.  Changes in these fair values are recognized as gains or losses in the accompanying statement of operations under the caption “Costs and Expenses – Marketing”.  Interest on marketable securities is recognized directly in the statement of operations during the period earned.

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 90 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.

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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,
	2011		2010
Crude oil	$	18,464	$	12,909
Petroleum products		1,725		1,682
	$	20,189	$	14,591

Prepayments

The components of prepayments and other are as follows (in thousands):

	December 31,
	2011		2010
Cash collateral deposits for commodity purchases	$	6,521	$	5,150
Insurance premiums		2,033		1,954
Commodity imbalances and futures		1,452		330
Rents, license and other		645		670
	$	10,651	$	8,104

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, 2011, the Company had no unevaluated or suspended exploratory drilling costs.

Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method.  The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves.  For lease and well equipment, development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves.  All other property and equipment is depreciated using the straight-line method over the estimated average useful lives of three to twenty years.

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The Company  reviews its long-lived assets for impairment whenever there is evidence that the carrying value of such assets may not be recoverable.  Any impairment recognized is permanent and may not be restored.  Producing oil and gas properties are reviewed  on a field-by-field basis.  For properties requiring impairment, the fair value is estimated based on an internal discounted cash-flow model.  Cash flows are developed based on estimated future production and prices and then discounted using a market based rate of return consistent with that used by the Company in evaluating cash flows for other assets of a similar nature.  For the years ended December 31, 2011, 2010 and 2009 there were $7,105,000, $946,000 and $1,350,000 impairment provisions on producing oil and gas properties, respectively.

Fair value measurements for producing oil and gas properties that were subject to fair value impairment for the years ended December 31, 2011 and 2010 summarized as follows (in thousands):

	Producing Properties Subject to Fair Value Impairment
	2011			2010
Net book value at January 1	$	8,704		$	2,220
Property additions		16,465			1,802
Depletion taken		(6,633	)		(753	)
Impairment valuation loss		(7,105	)		(946	)
Net book at December 31	$	11,431		$	2,323

Fair value measurements for producing oil and gas properties are based on Level 3 – Significant Unobservable Inputs – (see Fair Value Measurements below).

On a quarterly basis, management also evaluates the carrying value of non-producing oil and gas properties and may deem them impaired  based on remaining lease term, drilling activity in the area and the Company’s plans for the property.  Accordingly, impairment provisions on non-producing properties totaling $7,644,000, $1,277,000 and $2,423,000 were recorded for the years ended December 31, 2011, 2010 and 2009, respectively.  For non-producing properties, impairments are determined based on management’s knowledge of current geological evaluations, drilling results and activity in the area and intent to drill as it relates to the remaining term of the underlying oil and gas leasehold interest.

Cash Deposits and Other Assets

The Company has established certain deposits to support participation in its liability insurance program and remittance of state crude oil severance taxes and other state collateral deposits.  Insurance collateral deposits are invested at the discretion of the Company’s insurance carrier and such investments primarily consist of intermediate term federal government bonds and bonds backed by federal agencies.  Components of cash deposits and other assets are as follows (in thousands):

	December 31,
	2011		2010
Insurance collateral deposits	$	3,331	$	2,291
State collateral deposits		168		166
Materials and supplies		668		520
	$	4,167	$	2,977

Revenue Recognition

Commodity purchase and sale contracts utilized by the Company’s marketing businesses qualify as derivative instruments.  Further, all natural gas, as well as certain specifically identified crude oil purchase and sale contracts, are designated as trading activities.  From the time of contract origination, such trading activity contracts are marked-to-market and recorded on a net revenue basis in the accompanying financial statements.

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Substantially all crude oil and refined products purchase and sale contracts qualify and are designated as non-trading activities and the Company elects the normal purchases and sales exception methodology for such activity.  For normal purchase and sale activities, the Company’s customers are invoiced monthly based upon contractually agreed upon terms with revenue recognized in the month in which the physical product is delivered to the customer.  Such sales are recorded gross in the financial statements because the Company takes title to and has risk of loss for the products, is the primary obligor for the purchase, establishes the sale price independently with a third party and maintains credit risk associated with the sale of the product.

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.  Such buy/sell arrangements are reflected on a net revenue basis in the accompanying financial statements.  Reporting such crude oil contracts on a gross revenue basis would increase the Company’s reported revenues by $1,812,561,000, $1,415,844,000 and $874,386,000 for the years ended December 31, 2011, 2010 and 2009, respectively.

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.

Letter of Credit Facility

The Company maintains a Credit and Security Agreement with Wells Fargo Bank to provide a $60 million stand-by letter of credit facility to support the Company’s crude oil and natural gas purchases within the marketing segment.  This facility is collateralized by the eligible accounts receivable within those operations.  Stand-by letters of credit issued totaled $38.9 million and $23.9 million as of December 31, 2011 and 2010, respectively.  The issued stand-by letters of credit are cancelled as the underlying purchase obligations are satisfied by cash payment when due.  The letter of credit facility places certain restrictions on the Company’s Gulfmark Energy, Inc. and Adams Resources Marketing, Ltd. subsidiaries.  Such restrictions included the maintenance of a combined 1.1 to 1.0 current ratio and the maintenance of positive net earnings excluding inventory valuation changes, as defined, among other restrictions.  Management believes the Company is currently in compliance with all such financial covenants.

Statement of Cash Flows

Interest paid totaled $8,000, $36,000 and $25,000 during the years ended December 31, 2011, 2010 and 2009, respectively.  Income taxes paid during these same periods totaled $5,597,000, $532,000, and $1,152,000, respectively.  State and Federal income tax refunds totaled $2,743,000 and $2,000,000 in 2011 and 2009, respectively.  Non-cash investing activities for property and equipment items included in accounts payable as of period end were $4,070,000 and $2,868,000 as of December 31, 2011 and 2010, respectively.  There were no significant non-cash financing activities in any of the periods reported.

Earnings per Share

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 2011, 2010 and 2009.  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.

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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 oil and gas reserve volumes that form the foundation for (1) calculating depreciation, depletion and amortization and (2) deriving cash flow estimates to assess impairment triggers or estimated values associated with oil and gas property, revenue accruals, the provision for bad debts, insurance related accruals, income taxes, contingencies and valuation of fair value contracts.

Income Taxes

Income taxes are accounted for using the asset and liability method.  Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis (see Note 2).

Use of Derivative Instruments

The Company’s marketing segment is involved in the purchase and sale of crude oil and natural gas.  The Company seeks to make a profit by procuring such commodities as they are produced and then delivering such products to the end users or intermediate use marketplace.  As is typical for the industry, in certain cases such transactions are made pursuant to the terms of forward month commodity purchase and/or sale contracts.  These contracts meet the definition of a derivative instrument and therefore, the Company accounts for such contracts at fair value, unless the normal purchase and sale exception is applicable.  Such underlying contracts are standard for the industry and are the governing document for the Company’s crude oil and natural gas wholesale distribution businesses.  The accounting methodology utilized by the Company for its commodity contracts is further discussed below under the caption “Fair Value Measurements”.

None of the Company’s derivative instruments have been designated as hedging instruments and the estimated fair value of forward month commodity contracts (derivatives) is reflected in the accompanying Consolidated Balance Sheet as of December 31, 2011 as follows (in thousands):

	Balance Sheet Location and Amount
	Current			Other		Current			Other
	Assets			Assets		Liabilities			Liabilities
Asset Derivatives
- Fair Value Commodity
Contracts at Gross Valuation	$	3,500		$	-	$	-		$	-
Liability Derivatives
- Fair Value Commodity
Contracts at Gross Valuation		-			-		2,117			-
Less Counterparty Offsets		(1,436	)		-		(1,436	)		-
As Reported Fair Value Contracts	$	2,064		$	-	$	681		$	-

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Forward month commodity contracts (derivatives) are reflected in the accompanying Consolidated Balance Sheet as of December 31, 2010 as follows (in thousands):

	Balance Sheet Location and Amount
	Current			Other		Current			Other
	Assets			Assets		Liabilities			Liabilities
Asset Derivatives
- Fair Value Commodity
Contracts at Gross Valuation	$	8,094		$	-	$	-		$	-
Liability Derivatives
- Fair Value Commodity
Contracts at Gross Valuation		-			-		6,808			-
Less Counterparty Offsets		(5,330	)		-		(5,330	)		-
As Reported Fair Value Contracts	$	2,764		$	-	$	1,478		$	-

The Company only enters into commodity contracts with creditworthy counterparties or obtains collateral support for such activities.  As of December 31, 2011 and 2010, the Company was not holding nor had it posted any collateral to support its forward month fair value derivative activity. The Company is not subject to any credit-risk related trigger events.

Forward month commodity contracts (derivatives) are reflected in the accompanying Consolidated Statement of Operations for the years ended December 31, 2011,  2010 and 2009 as follows (in thousands):

	Gain (Loss)
Location	2011		2010		2009
Revenues - marketing	$	97	$	1,036	$	(251	)

 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.  Marketable securities are recorded at fair value based on market quotations from actively traded liquid markets.

Fair value contracts consist of derivative financial instruments and are recorded as either an asset or liability measured at  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 during any reporting periods.

Fair value estimates are based on assumptions that market participants would use when pricing an asset or liability and the Company uses 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 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.  For Level 1 valuation of marketable securities, the Company utilizes market quotations provided by its primary financial institution and for the valuations of derivative financial instruments, the Company utilizes the New York Mercantile Exchange “NYMEX” for such valuations.

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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.  Source data for Level 2 inputs include information provided by the NYMEX, the Intercontinental Exchange “ICE”, published price data and indices, third party price survey data and broker provided forward price statistics.

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

As of December 31, 2011, the Company’s fair value assets and liabilities are summarized and categorized as follows (in thousands):

	Market Data Inputs
	Gross Level 1			Gross Level 2			Level 3		Counterparty
	Quoted Prices			Observable			Unobservable		Offsets			Total
Derivatives
- Current assets	$	1,455		$	2,045		$	-	$	(1,436	)	$	2,064
- Current liabilities		(675	)		(1,442	)		-		1,436			(681	)
Net Value	$	780		$	603		$	-	$	-		$	1,383

As of December 31, 2010, the Company’s fair value assets and liabilities are summarized and categorized as follows (in thousands):

	Market Data Inputs
	Gross Level 1			Gross Level 2			Level 3		Counterparty
	Quoted Prices			Observable			Unobservable		Offsets			Total
Derivatives
- Current assets	$	-		$	8,094		$	-	$	(5,330	)	$	2,764
- Current liabilities		(118	)		(6,690	)		-		5,330			(1,478	)
Net Value	$	(118	)	$	1,404		$	-	$	-		$	1,286

The Company’s gross transaction volumes for physically settled energy trading contracts were approximately 75,890,000 mmbtu’s, 93,827,000 mmbtu’s, and 132,488,000 mmbtu’s in 2011, 2010 and 2009, 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, 2011 and 2010, 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.

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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, 2011 (in thousands):

	Level 1			Level 2
	Quoted Prices			Observable			Total
Net Fair Value January 1,	$	(118	)	$	1,404		$	1,286
- Net realized (gains) losses		118			(1,404	)		(1,286	)
- Net unrealized gains (losses)		780			603			1,383
Net Fair Value December 31,	$	780		$	603		$	1,383

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, 2010 (in thousands):

	Level 1			Level 2
	Quoted Prices			Observable			Total
Net Fair Value January 1,	$	224		$	26		$	250
- Net realized (gains) losses		(224	)		(26	)		(250	)
- Net unrealized gains (losses)		(118	)		1,404			1,286
Net Fair Value December 31,	$	(118	)	$	1,404		$	1,286

Asset Retirement Obligations

The Company records a 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 or the units of production associated with 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):

	2011			2010
Balance on January 1,	$	1,390		$	1,315
-Liabilities incurred		164			76
-Accretion of discount		82			75
-Liabilities settled		(68	)		(76	)
-Revisions to estimates		-			-
Balance on December 31,	$	1,568		$	1,390

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.

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Recent Accounts Pronouncement

In January 2010, the Financial Accounting Standards Board (“FASB”) issued FASB Accounting Standards Update (ASU) No. 2010-03, “Oil and Gas Reserve Estimations and Disclosures” (ASU No. 2010-03).  This update aligns the current oil and gas reserve estimation and disclosure requirements of the Extractive Industries – Oil and Gas topic of the ASC (ASC Topic 932) with the changes required by the SEC final rule, “Modernization of Oil and Gas Reporting,” as discussed above.  ASU No. 2010-03 expands the disclosures required for equity method investments, revises the definition of oil and gas producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or gas, amends the definition of proved oil and gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and gas quantities and provides guidance on geographic area with respect to disclosure of information about significant reserves.  ASU No. 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate.  The Company adopted ASU No. 2010-03 effective December 31, 2009.

In May 2011, the FASB issued ASU 2011-04, which further amends the Fair Value Measurements and Disclosures topic of the Accounting Standards Codification.  Among other provisions, ASU 2011-04 expands and modifies certain principles and requirements for measuring fair value and disclosing fair value measurement information.  ASU 2011-04 is effective for interim and fiscal periods beginning after December 15, 2011.  The adoption of ASU 2011-04 is not expected to have a material impact on the Company’s financial statements, but may result in additional disclosures regarding fair value measurements.

In December 2011, the FASB issued FASB Accounting Standards Update (ASU) 2011-11.  This update requires additional disclosures about an entity’s right of setoff and related arrangements associated with its financial and derivative instruments.  The ASU requires a tabular presentation that reflects the gross, net and setoff amounts associated with such assets and liabilities among other requirements.  The expanded disclosure requirements are effective for the annual reporting periods beginning on January 1, 2013.  The adoption of ASU 2011-11 is not expected to result in significant additional disclosures.

Management believes the impact of other recently issued standards and updates, which are not yet effective, will not have a material impact on the Company’s consolidated financial position, results of operations or cash flows upon adoption.

(2)  Income Taxes

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

	Years ended December 31,
	2011			2010			2009
Current:
Federal	$	(4,336	)	$	350		$	(649	)
State		(1,187	)		(721	)		(631	)
		(5,523	)		(371	)		(1,280	)
Deferred:
Federal		(7,407	)		(3,688	)		(1,286	)
State		99			(11	)		214
		(7,308	)		(3,699	)		(1,072	)
	$	(12,831	)	$	(4,070	)	$	(2,352	)

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

	Years ended December 31,
	2011			2010			2009
Statutory federal income tax (provision) benefit	$	(12,517	)	$	(4,445	)	$	(2,275	)
State income tax (provision) benefit		(707	)		(476	)		(270	)
Federal statutory depletion		393			534			186
Foreign investment write-off		-			201			-
Other		-			116			7
	$	(12,831	)	$	(4,070	)	$	(2,352	)

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

	Years Ended December 31,
	2011			2010
Current deferred tax asset (liability)
Allowance for doubtful accounts	$	772		$	372
Prepaid insurance		(793	)		(776	)
Fair value contracts		(484	)		(450	)
Net current deferred liability		(505	)		(854	)
Long-term deferred tax asset (liability)
Property		(10,579	)		(2,885	)
Uniform capitalization		471			396
Other		160			198
Net long-term deferred tax  liability		(9,948	)		(2,291	)
Net deferred tax liability	$	(10,453	)	$	(3,145	)

Financial statement recognition and measurement of positions taken, or expected to be taken, by an entity in its income tax returns must consider the uncertainty and judgment involved in the determination and filing of income taxes.  Tax 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 tax position will be examined by taxing authorities with full knowledge of all relevant information.  As of December 31, 2010, the Company had accrued approximately $27,000 including approximately $8,000 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):

	2011			2010
Balance as of January 1,	$	19		$	72
Additions for tax positions of prior years		-			-
Reductions of prior positions		(19	)		(53	)
Balance as of December 31,	$	-		$	19

The Company has filed all remaining open returns and expects final resolution with all states by year-end 2011.  As the actual tax payments are made, the accrual is reduced.  The Company has no other unrecognized tax benefits.  Interest and penalties associated with income tax liabilities are classified as income tax expense.

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

	Earliest Open
	Tax Year
Federal	2008
Texas	2007
Louisiana	2008
Michigan	2008

(3)  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. Accounts receivable associated with crude oil and natural gas marketing activities comprise approximately 90 percent of the Company’s total receivables and industry practice requires payment for such sales to occur within 25 days of the end of the month following a transaction.  The Company’s customer mix, credit policies and the relatively short duration of receivables mitigate the uncertainty typically associated with receivables management.

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.  Within this group of customers the Company generally derives up to 50 percent of its revenues from two to three large crude oil refining concerns.  While the Company has ongoing established relationships with certain domestic refiners of crude oil, alternative markets are readily available since the Company supplies less than one percent of U. S. domestic refiner demand.  As a fungible commodity delivered to major Gulf Coast supply points, the Company’s crude oil sales can be readily delivered to alternative end markets.  Management believes that a loss of any of those customers where the Company currently derives more than 10 percent of its revenues would not have a material adverse effect on the Company’s operations.

The Company had accounts receivable from two customers that comprised 24.5 percent and 21.5 percent, respectively, of total accounts receivable at December 31, 2011.  Four customers comprised 18.2 percent, 15.4 percent, 13.4 percent, and 11.3 percent, respectively, of total revenues during 2011.  The Company had accounts receivable from four customers that comprised 22.4 percent, 16.2 percent, 13.7 percent and 10.6 percent, respectively, of total accounts receivable at December 31, 2010.  Five customers comprised 35.8 percent, 20.2 percent, 17.9 percent, 13 percent and 11 percent, respectively, of total revenues during 2010.  The Company had accounts receivable from three customers that comprised 17.8 percent, 12.6 percent and 10.8 percent, respectively of total accounts receivables at December 31, 2009.  Three customers comprised 39.4 percent, 17.7 percent and 15.7 percent, respectively, of total revenues during 2009.

An allowance for doubtful accounts is provided where appropriate and accounts receivable presented herein are net of allowances for doubtful accounts of $2,205,000 and $1,064,000 at December 31, 2011 and 2010, respectively.  As reflected in the table below, during 2011 and 2009 the  Company’s provision for bad debt was elevated as a result of deteriorating  collectability  primarily attributable to diesel fuel sales to the construction industry.

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

	2011			2010			2009
Balance, beginning of year	$	1,064		$	1,681		$	1,251
Provisions for bad debts		1,223			29			704
Less:  Write-offs and recoveries		(82	)		(646	)		(274	)
Balance, end of year	$	2,205		$	1,064		$	1,681

(4)  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 $597,000, $565,000 and $578,000 in 2011, 2010 and 2009, respectively. No other pension or retirement plans are maintained by the Company.

(5)  Transactions with Affiliates

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 2011 and 2010, the Company’s investment commitments totaled approximately $24.6 million and $11.7 million, respectively, in those oil and gas projects where a related party was also participating in such investments.  As of December 31, 2011 and 2010, the Company owed a combined net total of $58,000 and $9,000, 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 $145,000, $160,000 and $150,000 for the years ended December 31, 2011, 2010, and 2009, 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 administrative services.  For the years ended December 31, 2011, 2010 and 2009, the affiliated entities charged the Company $42,000, $43,000 and $62,000, respectively, of expense reimbursement and the Company charged the affiliates $118,000, $117,000 and $127,000, respectively, for such expense reimbursements. In January 2012, the company relocated its primary office lease space to a building operated by an affiliated entity.  Estimated annual rental expense, including pro-rata building operating expense are $480,000 per year under a seven year lease term.  The lease rental rate was determined by an independent appraisal.

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(6)  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.  In addition, the Company has entered into certain lease and terminal access contracts in order to provide tank storage and dock access for its crude oil marketing business.  Such contracts require certain minimum monthly payments for the term of the contracts.  Rental expense for the years ended December 31, 2011, 2010, and 2009 was $7,621,000, $5,870,000 and $6,898,000, respectively.  At December 31, 2011, commitments under long-term non-cancelable operating leases and terminal arrangements for the next five years and thereafter are payable as follows:   2012 - $3,059,000; 2013 - $2,148,000; 2014 - $1,468,000; 2015 - $1,201,000; 2016 $1,181,000 and $1,602,000 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.  The Company has appropriately recognized estimated expenses and liabilities related to these policies for losses incurred but not reported to the Company or its insurance carrier of $1,285,000 and $2,125,911 as of December 31, 2011 and 2010, respectively.

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.

(7)  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, 2011 are as follows (in thousands):

	2012		2013		2014		Thereafter		Total
Equipment residual values	$	72	$	216	$	-	$	-	$	288

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, 2011, the maximum amount of such potential obligation is approximately $1,712,000.  Management of the Company believes its customers will adhere to their branding obligations and no such refunds will result.  In addition, effective February 27, 2012 this obligation was assumed by the purchaser of the Company’s refined products contracts.  See also Note (10) of Notes to Financial Statements.

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Presently, neither Adams Resources & Energy, Inc. (“ARE”) nor any of its subsidiaries has any other types of guarantees outstanding that require liability recognition.

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, 2011, parental guaranteed obligations are approximately as follows (in thousands):

	2012		2013		2014		2015		Thereafter		Total
Lease payments	$	56	$	47	$	-		-		-		103
Equipment residual values		72		216		-		-		-		288
Commodity purchases		68,815		-		-		-		-		68,815
Letters of credit		38,925		-		-		-		-		38,925
	$	107,868	$	263	$	-	$	-	$	-	$	108,131

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(8)  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, 2011-
Marketing
- Crude oil	$	2,961,176	$	49,237		$	3,724	$	13,554
- Natural gas		6,251		2,147			3		64
- Refined products		169,411		(788	)		375		66
Marketing Total		3,136,838		50,596			4,102		13,684
Transportation		63,501		8,521			3,912		14,118
Oil and gas		14,060		(13,871	)		8,246		24,580
	$	3,214,399	$	45,246		$	16,260	$	52,382
Year ended December 31, 2010-
Marketing
- Crude oil	$	2,005,301	$	13,530		$	2,320	$	6,051
- Natural gas		10,592		3,073			44		115
- Refined products		128,189		121			503		146
Marketing Total		2,144,082		16,724			2,867		6,312
Transportation		56,867		6,623			4,288		4,410
Oil and gas		11,021		(1,757	)		4,662		11,699
	$	2,211,970	$	21,590		$	11,817	$	22,421
Year ended December 31, 2009-
Marketing
- Crude oil	$	1,770,600	$	15,404		$	1,997	$	1,947
- Natural gas		14,232		2,749			166		-
- Refined products		104,751		(666	)		533		177
Marketing Total		1,889,583		17,487			2,696		2,124
Transportation		44,895		2,128			3,970		7,524
Oil and gas		8,650		(3,625	)		3,654		12,742
	$	1,943,128	$	15,990		$	10,320	$	22,390

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,
	2011			2010			2009
Segment operating earnings	$	45,246		$	21,590		$	15,990
- General and administrative expenses		(9,713	)		(9,044	)		(9,589	)
Operating earnings		35,533			12,546			6,401
- Interest income		237			191			125
- Interest expense		(8	)		(36	)		(25	)
Earnings before income taxes	$	35,762		$	12,701		$	6,501

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

	Years Ended December 31,
	2011		2010
Marketing
- Crude oil	$	253,817	$	184,299
- Natural gas		12,246		19,948
- Refined products		11,700		11,594
Marketing Total		277,763		215,841
Transportation		27,221		17,378
Oil and gas		29,105		32,563
Other		44,751		35,523
	$	378,840	$	301,305

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.

(9)  Quarterly Financial Data (Unaudited) -

Selected quarterly financial data and earnings per share of the Company are presented below for the years ended December 31, 2011 and 2010 (in thousands, except per share data):

						Net Earnings				Dividends
				Operating				Per				Per
		Revenues		Earnings (loss)		Amount		Share		Amount		Share
	2011 -
March 31		$	697,188	$	8,475	$	5,583	$	1.32	$	-	$	-
June 30			824,210		5,807		3,589		.85		-		-
September 30			801,690		13,576		9,026		2.14		-		-
December 31			891,311		7,675		4,733		1.13		2,404		.57
Total		$	3,214,399	$	35,533	$	22,931	$	5.44	$	2,404	$	.57
	2010 -
March 31		$	533,785	$	2,575	$	1,794	$	.43	$	-	$	-
June 30			547,141		2,656		1,685		.39		-		-
September 30			502,455		4,021		2,762		.66		-		-
December 31			628,589		3,294		2,390		.57		2,277		.54
Total		$	2,211,970	$	12,546	$	8,631	$	2.05	$	2,277	$	.54

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.

(10)  Subsequent Event

On February 27, 2012, the Company sold certain equipment, inventory and contracts associated with its refined products marketing segment.  The Company received proceeds of $2 million plus the fair market value of its inventory and transferred title to its inventory, transportation equipment and other miscellaneous net assets.  The current gain is estimated to be approximately $1 million, subject to final post-closing adjustments.

Accounts receivable and accounts payable as of the transaction date that are associated with this segment were retained and will continue to be satisfied in the ordinary course of business.  The Company has discontinued its refined products marketing operation and has agreed to a three year non-compete agreement in connection with this matter. 

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(11)Oil and Gas Producing Activities (Unaudited)

The Company’s oil and gas exploration and production activities are conducted in Texas and the south central region of the United States, primarily along the Gulf Coast of Texas and Louisiana.

Oil and Gas Producing Activities -

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,
	2011		2010		2009
Property acquisition costs
Unproved	$	3,591	$	2,295	$	6,199
Proved		-		-		-
Exploration costs
Expensed		9,166		3,233		3,818
Capitalized		-		-		1,035
Development costs		12,133		6,233		2,341
Total costs incurred	$	24,890	$	11,761	$	13,393

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

	December 31,
	2011			2010
Unproved oil and gas properties	$	7,291		$	12,250
Proved oil and gas properties		74,376			69,011
		81,667			81,261
Accumulated depreciation, depletion
and amortization		(55,061	)		(51,857	)
Net capitalized cost	$	26,606		$	29,404

Estimated Oil and Natural Gas Reserves  -

The following information regarding estimates of the Company's proved oil and gas reserves, all located in Texas and the south central region of 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 changes in commodity pricing assumptions and from more precise engineering calculations based upon additional production histories and price changes.

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

	Years Ended December 31,
	2011						2010						2009
	Natural						Natural						Natural
	Gas			Oil			Gas			Oil			Gas			Oil
	(Mcf’s)			(Bbls.)			(Mcf’s)			(Bbls.)			(Mcf’s)			(Bbls.)
Total proved reserves-
Beginning of year		7,794			267			7,248			242			6,443			230
Revisions of previous estimates		(520	)		(24	)		(832	)		-			(129	)		(4	)
Oil and gas reserves sold		(2,148	)		(26	)		-			-			-			-
Extensions, discoveries and
Other reserve additions		6,430			137			2,743			79			2,238			66
Production		(1,895	)		(62	)		(1,365	)		(54	)		(1,304	)		(50	)
End of year		9,661			292			7,794			267			7,248			242

The components of proved oil and gas reserves for the three years ended December 31, 2011 is presented below.  All reserves are in the United States (in thousands):

	Years Ended December 31,
	2011				2010				2009
	Natural				Natural				Natural
	Gas		Oil		Gas		Oil		Gas		Oil
	(Mcf’s)		(Bbls.)		(Mcf’s)		(Bbls.)		(Mcf’s)		(Bbls.)
Proved developed reserves		9,433		277		7,134		240		6,295		242
Proved undeveloped reserves		228		15		660		27		953		-
Total proved reserves		9,661		292		7,794		267		7,248		242

Proved undeveloped reserves originated in 2009 when active drilling efforts commenced and such period identified and delineated additional reserve acreage.  During 2010 drilling efforts continued identifying additional reserve acreage and converting such undeveloped reserves to the developed category.  Drilling in 2011 continued to develop the reserve acreage.

The Company has developed internal policies and controls for estimating and recording oil and gas reserve data.  The estimation and recording of proved reserves is required to be in compliance with SEC definitions and guidance.  The Company assigns responsibility for compliance in reserve bookings to the office of President of the Company’s AREC subsidiary.  No portion of this individual’s compensation is directly dependent on the quantity of reserves booked.  Reserve estimates are required to be made by qualified reserve estimators, as defined by Society of Petroleum Engineers’ Standards.

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The Company employs third party petroleum consultant, Ryder Scott Company, to prepare its oil and gas reserve data estimates as of December 31, 2011, 2010 and 2009.  The firm of Ryder Scott is well recognized within the industry for more than 50 years.  As prescribed by the SEC, such proved reserves were estimated using 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period, and year-end production and development costs for each of the years presented, all without escalation.

The process of estimating oil and gas reserves is complex and requires significant judgment.  Uncertainties are inherent in estimating quantities of proved reserves, including many factors beyond the estimator’s control.  Reserve engineering is a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and the interpretation thereof.  As a result, estimates by different engineers often vary, sometimes significantly.  In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates.  Accordingly, oil and gas quantities ultimately recovered will vary from reserve estimates.

Standardized Measure of Discounted Future Net Cash Flows from Oil and Gas Operations and Changes Therein  -

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,
	2011			2010			2009
Future gross revenues	$	73,626		$	61,311		$	43,498
Future costs -
Lease operating expenses		(19,788	)		(17,288	)		(15,969	)
Development costs		(2,198	)		(1,596	)		(2,495	)
Future net cash flows before income taxes		51,640			42,427			25,034
Discount at 10% per annum		(19,439	)		(16,777	)		(10,719	)
Discounted future net cash flows
before income taxes		32,201			25,650			14,315
Future income taxes, net of discount at
10% per annum		(11,270	)		(8,978	)		(5,010	)
Standardized measure of discounted
future net cash flows	$	20,931		$	16,672		$	9,305

The reserve estimates provided at December 31, 2011, 2010 and 2009 are based on aggregate prices of $95.85, $76.14 and $58.43 per barrel for crude oil and $4.69, $5.26 and $4.05 per mcf for natural gas, respectively.  Such prices reflect the unweighted arithmetic average of the prices in effect on the first day of the month for each month of the respective twelve month periods as required by Securities & Exchange Commission regulations.  The affect of income taxes and discounting on the standardized measure of discounted future net cash flows is presented as follows (in thousands):

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	Years ended December 31,
	2011			2010			2009
Future net cash flows before income taxes	$	51,640		$	42,427		$	25,034
Future income taxes		(18,074	)		(14,849	)		(8,762	)
Future net cash flows		33,566			27,578			16,272
Discount at 10% per annum		(12,635	)		(10,906	)		(6,967	)
Standardized measure of discounted
future net cash flows	$	20,931		$	16,672		$	9,305

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

	Years Ended December 31,
	2011			2010			2009
Beginning of year	$	16,672		$	9,305		$	11,547
Sale of oil and gas reserves		(7,429	)		-			-
Net change in prices and production costs		791			9,435			(4,890	)
New field discoveries and extensions, net of future
production costs		18,769			9,068			3,471
Sales of oil and gas produced, net of production costs		(7,723	)		(7,084	)		(5,114	)
Net change due to revisions in quantity estimates		(1,739	)		(1,369	)		(347	)
Accretion of discount		1,678			1,072			1,242
Production rate changes and other		2,204			213			2,189
Net change in income taxes		(2,292	)		(3,968	)		1,207
End of year	$	20,931		$	16,672		$	9,305

Results of Operations for Oil and Gas Producing Activities -

The results of oil and gas producing activities, excluding corporate overhead and interest costs, are as follows (in thousands):

	Years Ended December 31,
	2011			2010			2009
Revenues	$	14,060		$	11,021		$	8,650
Costs and expenses -
Production		(6,337	)		(3,937	)		(3,536	)
Producing property impairment		(7,105	)		(946	)		(1,350	)
Exploration		(9,166	)		(3,233	)		(3,735	)
Depreciation, depletion and amortization		(8,246	)		(4,662	)		(3,654	)
Operating income (loss) before income taxes		(16,794	)		(1,757	)		(3,625	)
Income tax (expense) benefit		5,878			615			1,268
Operating income (loss)	$	(10,916	)	$	(1,142	)	$	(2,357	)

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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 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 Securities and Exchange Commission’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 there is a reasonable assurance that the disclosure controls and procedures as of the end of the period covered by this report are effective to ensure that information required to be disclosed in the Company’s Exchange Act filings is recorded, processed, summarized and reported within the periods specified in the Securities and Exchange Commission’s rules and forms.

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 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, including the Company’s Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2011.  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, including the Company’s Chief Executive Officer and Chief Financial Officer, concluded that internal control over financial reporting was effective at a reasonable assurance level as of December 31, 2011.

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

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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, 2011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 9B.  OTHER

None.

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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 Wednesday, May 16, 2012, 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 Wednesday, May 16, 2012, 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 Wednesday, May 16, 2012, 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 Wednesday, May 16, 2012, 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 Wednesday, May 16, 2012, 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.

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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, 2011 and 2010

Consolidated Statements of Operations for the Years Ended

December 31, 2011, 2010 and 2009

Consolidated Statements of Shareholders' Equity for the Years Ended

December 31, 2011, 2010 and 2009

Consolidated Statements of Cash Flows for the Years Ended

December 31, 2011, 2010 and 2009

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)

57

4(b) - Credit and Security Agreement between Gulfmark Energy, Inc., Adams Resources Marketing, Ltd and Wells Fargo Bank, National Association dated August 27, 2009 (Incorporated by reference to Exhibit 4(b) of the Quarterly Report on Form 10-Q for the period ended September 30, 2009.

10.1(a)+ -  Employment agreement of Frank T. Webster, President, dated May 4, 2004 by and between Adams Resources & Energy, Inc. and Frank T. Webster (Incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2004)

10.1(b)+ -  Ninth Amendment to Employment Agreement of Frank T. Webster, President, by and between Adams Resources & Energy, Inc. and Frank T. Webster effective December 6, 2011.  Incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on December 6, 2011).

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

10.1(d)+ -  First Amendment to Change in Control/Severance agreement by and between Adams Resources & Energy, Inc. and Richard B. Abshire effective December 6, 2011 (Incorporated by reference to Exhibit 10.2 to the Company’s current report on Form 8-K filed on December 6, 2011).

10.1(e)+ -  Amendment to Change in Control/Severance agreement by and between Adams Resources & Energy, Inc. and Sharon Davis effective December 6, 2011 (Incorporated by reference to Exhibit 10.3 to the Company’s current report on Form 8-K filed on December 6, 2011).

10.1(f)+ - Amendment to Employment Agreement of Frank T. Webster, President, dated December 6, 2010 by and between Adams Resources & Energy, Inc. and Frank T. Webster (Incorporated by reference to Exhibit 10.1(b) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010).

10.1(g)+ -  Non-Employee Director Change in Control Agreement by and between Adams Resources & Energy, Inc. and E. C. Reinauer, Jr., dated effective December 6, 2011 (Incorporated by reference to Exhibit 10.4 to the Company’s Form 8-K filed on December 6, 2011).

10.1(h)+ -  Non-Employee Director Change in Control Agreement by and between Adams Resources & Energy, Inc. and Townes G. Pressler, dated effective December 6, 2011 (Incorporated by reference to Exhibit 10.5 to the Company’s Form 8-K filed on December 6, 2011).

10.1(i)+ -  Non-Employee Director Change in Control Agreement by and between Adams Resources & Energy, Inc. and Larry E. Bell, dated effective December 6, 2011 (Incorporated by reference to Exhibit 10.5 to the Company’s Form 8-K filed on December 6, 2011)

10.1(j)+ -  Standard form Indemnification Agreement between Adams Resources & Energy, Inc. and Officers or Directors (Incorporated by reference to Exhibit 10.1 to the Company’s Quarterly - Report on Form 10-Q for the period ended September 30, 2011).  

10.1(k)*+ -  Change in Control/Severance agreement by and between Adams Resources & Energy, Inc. and Sharon Davis (nee Copeland) effective September 20, 2008.

21* - Subsidiaries of the Registrant

23.1* - Consent of Ryder Scott Company

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

58

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

99.1* - Ryder Scott Company Report

______________________________

*  - Filed herewith

+ -  Management contract or compensation plan or arrangement

 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.

59

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 and Chief Financial Officer	Chairman of the Board and
(Principal Financial Officer)	Chief Executive Officer
	(Principal Executive Officer)

Date:  March 22, 2012

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/ Townes G. Pressler
Larry E. Bell, Director	Townes G. Pressler, Director

60

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)	-  Credit and Security Agreement between Gulfmark Energy, Inc., Adams Resources Marketing, Ltd and Wells Fargo Bank, National Association dated August 27, 2010 (Incorporated by reference to Exhibit 4(b) of the Quarterly Report on Form 10-Q for the period ended September 31, 2010
10.1(a)+ 10.1(b)+ 10.1(c)+ 10.1(d)+ 10.1(e)+ 10.1(f)+ 10.1(g)+ 10.1(h)+ 10.1(i)+ 10.1(j)+ 10.1(k)*+	-  Employment agreement of Frank T. Webster, President, dated May 4, 2004 by and between Adams Resources & Energy, Inc. and Frank T. Webster (Incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2004)      -  Ninth Amendment to Employment Agreement of Frank T. Webster, President, by and between Adams Resources & Energy, Inc. and Frank T. Webster effective December 6, 2011.  (Incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed in December 6, 2011).     -  Change in Control/Severance agreement by and between Adams Resources & Energy, Inc. and Richard B. Abshire effective July 25, 2008. (Incorporated by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on July 25, 2008)     -  First Amendment to Change in Control/Severance agreement by and between Adams Resources & Energy, Inc. and Richard B. Abshire effective December 6, 2011. (Incorporated by reference to Exhibit 10.2 to the Company’s current report on Form 8-K filed on December 6, 2011).     -  Amendment to Change in Control/Severance agreement by and between Adams Resources & Energy, Inc. and Sharon Davis effective December 6, 2011. (Incorporated by reference to Exhibit 10.3 to the Company’s current report on Form 8-K filed on December 6, 2011) -  Amendment to Employment Agreement of Frank T. Webster, President, dated December 6, 2010 by and between Adams Resources & Energy, Inc. and Frank T. Webster (Incorporated by reference to Exhibit 10.1(b) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010).     -   Non-Employee Director Change in Control Agreement by and between Adams Resources & Energy, Inc. and E. C. Reinauer, Jr., dated effective December 6, 2011 (Incorporated by reference to Exhibit 10.4 to the Company’s Form 8-K filed on December 6, 2011).                 -   Non-Employee Director Change in Control Agreement by and between Adams Resources & Energy, Inc. and Townes G. Pressler, dated effective December 6, 2011 (Incorporated by reference to Exhibit 10.5 to the Company’s Form 8-K filed on December 6, 2011). -  Non-Employee Director Change in Control Agreement by and between Adams Resources & Energy, Inc. and Larry E. Bell, dated effective December 6, 2011 (Incorporated by reference to Exhibit 10.5 to the Company’s Form 8-K filed on December 6, 2011) - Standard form Indemnification Agreement between Adams Resources & Energy, Inc. and Officers or Directors (Incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2011). -  Change in Control/Severance agreement by and between Adams Resources & Energy, Inc. and Sharon Davis (nee Copeland) effective September 20, 2008

21*	-      Subsidiaries of the Registrant
23.1*	-      Consent of Ryder Scott Company
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 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
99.1*	-     Ryder Scott Company Report

______________________________

* - Filed herewith

61

EX-10.1

 Exhibit 10.1(k)

CHANGE IN CONTROL/SEVERANCE AGREEMENT

THIS AGREEMENT, dated September 20, 2008, is made by and between Adams Resources & Energy, Inc., a Delaware corporation (the “Company”), and Sharon Copeland (the “Key Employee”).

WHEREAS, the Key Employee currently is employed by the Company or one of its subsidiaries;

WHEREAS, the Board recognizes that, as is the case with many publicly-held corporations, the possibility of a Change in Control exists and that such possibility, and the uncertainty and questions which it may raise among management, may result in the departure or distraction of management personnel to the detriment of the Company and its stockholders; and

WHEREAS, the Board has determined that appropriate steps should be taken to ensure that the Key Employee receive the protections afforded under this Agreement for the one-year period beginning on the date of a Change in Control to reinforce and encourage the continued attention and dedication of members of the Company’s management, including the Key Employee, to their assigned duties without distraction in the face of potentially disturbing circumstances;

NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained, the Company and the Key Employee hereby agree as follows:

1.Defined Terms.  The definitions of capitalized terms used in this Agreement are provided in the last Section hereof.

2.Term of Agreement.  The Term of this Agreement shall commence on September 20, 2008 (the “Effective Date”) and shall continue in effect through the first anniversary following a Change in Control.  In the event a Change in Control has not occurred on or before September 20, 2012, this Agreement shall immediately terminate and be of no further force and effect.

3.Company’s Covenants Summarized.  In order to induce the Key Employee to remain in the employ of the Company, the Company agrees, under the conditions described herein, to pay the Key Employee the Severance Payment described herein.  No Severance Payment shall be payable under this Agreement unless there shall have been a termination of the Key Employee’s employment by the Company without Cause or by the Key Employee with Good Reason following and within twelve (12) months after a Change in Control.  This Agreement shall not be construed as creating an express or implied contract of employment and, except as otherwise agreed in writing between the Key Employee and the Company, the Key Employee shall not have any right to be retained in the employ of the Company.

4.Severance Payment.

4.1If the Key Employee’s employment is terminated following a Change in Control and within twelve (12) months after a Change in Control (provided that such termination of employment constitutes a “separation from service” within the meaning of Section 409A of the Code), in either event other than (A) by the Company for Cause, (B) by reason of death or Disability, or (C) by the Key Employee without Good Reason, then the Company shall pay the Key Employee the amount described in this Section 4.1 (“Severance Payment”).

In lieu of any further salary payments to the Key Employee for periods subsequent to the Date of Termination, the Company shall pay to the Key Employee a lump sum severance payment, in cash, equal to two (2) times the Key Employee’s highest Base Salary (i.e., a Key Employee’s annualized regular earnings excluding any bonus) as in effect during the three-year period ending the last day of the month immediately prior to the month in which the Date of Termination occurs.

4.2The payment provided in Section 4.1 hereof shall be made as soon as practicable (but in any event not later than the 30th day) following the Date of Termination; provided that, to the extent required to satisfy the provisions of Section 409A(a)(2)(B)(i) of the Code, such payments shall be made not earlier than but as soon as practicable on or in any event within thirty (30) days after (with interest at the six-month certificate of deposit rate published in The Wall Street Journal on the Date of Termination (or if not published on that date, on the next following date when published) the date that is six (6) months after the Date of Termination (the “409A Payment Date”)).

5.Termination Procedures and Compensation During Dispute.

5.1Notice of Termination.  After a Change in Control, any purported termination of the Key Employee’s employment shall be communicated by written Notice of Termination from one party hereto to the other party hereto in accordance with Section 7 hereof.  For purposes of this Agreement, a “Notice of Termination” shall mean a notice which shall indicate the specific termination provision in this Agreement relied upon and shall set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of the Key Employee’s employment under the provision so indicated.  For purposes of this Agreement, any purported termination of the Key Employee’s employment after a Change in Control shall be presumed to be other than for Cause unless the Notice of Termination includes a copy of a resolution duly adopted by the affirmative vote of not less a majority of the entire membership of the Board at a meeting of the Board which was called and held for the purpose of considering such termination (after reasonable notice to the Key Employee and an opportunity for the Key Employee, together with the Key Employee’s counsel, to be heard before the Board) finding that, in the good faith opinion of the Board, the Key Employee was guilty of conduct set forth in clause (i) or (ii) of the definition of Cause herein, and specifying the particulars thereof in detail.

5.2Date of Termination.  “Date of Termination,” with respect to any purported termination of the Key Employee’s employment after a Change in Control, shall mean the date specified in the Notice of Termination (which, in the case of a termination by the Company, shall not be less than thirty (30) days (except in the case of a termination for Cause) and, in the case of a termination by the Key Employee, shall not be less than fifteen (15) days nor more than sixty (60) days, respectively, from the date such Notice of Termination is given, provided that, in the case of a termination by the Key Employee, the Company may require a Date of Termination earlier than that specified in the Notice of Termination upon payment to the Key Employee of the full amount of base salary that would have been paid to the Key Employee had the Key Employee continued employment between the actual Date of Termination and the Date of Termination specified in the Notice of Termination).

5.3Dispute Concerning Termination.  If within fifteen (15) days after any Notice of Termination is given, or, if later, prior to the Date of Termination (as determined without regard to this Section 5.3), the party receiving such Notice of Termination notifies the other party that a dispute exists concerning the termination, the Date of Termination shall be extended until the earlier of (i) the date on which the Term ends or (ii) the date on which the dispute is finally resolved, either by mutual written agreement of the parties or by a final judgment, order or decree of an arbitrator or a court of competent jurisdiction (which is not appealable or with respect to which the time for appeal therefrom has expired and no appeal has been perfected); provided, however, that the Date of Termination shall be extended by a notice of dispute given by the Key Employee only if such notice is given in good faith and the Key Employee pursues the resolution of such dispute with reasonable diligence.

5.4Compensation During Dispute.  If a purported termination occurs following a Change in Control and the Date of Termination is extended in accordance with Section 5.3 hereof, the Company shall continue to pay the Key Employee the full compensation in effect when the notice giving rise to the dispute was given (including, but not limited to, salary) and continue the Key Employee as a participant in all compensation, benefit and insurance plans in which the Key Employee was participating when the notice giving rise to the dispute was given, until the Date of Termination, as determined in accordance with Section 5.3 hereof.  Amounts paid under this Section 5.4 are in addition to all other amounts due under this Agreement and shall not be offset against or reduce any other amounts due under this Agreement.

6.Successors; Binding Agreement.

The Company will require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company to be obligated to perform this Agreement (whether by reason of express assumption by the successor or by operation of law) in the same manner and to the same extent that the Company would be required to perform it if no such succession had taken place.

6.1This Agreement shall inure to the benefit of and be enforceable by the Key Employee’s personal or legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees.  If the Key Employee shall die while any amount would still be payable to the Key Employee hereunder if the Key Employee had continued to live, all such amounts, unless otherwise provided herein, shall be paid in accordance with the terms of this Agreement to the executors, personal representatives or administrators of the Key Employee s estate.

7.Notices.  For the purpose of this Agreement, notices and all other communications provided for in the Agreement shall be in writing and shall be deemed to have been duly given when delivered or mailed by United States registered mail, return receipt requested, postage prepaid, addressed, if to the Key Employee, to the address of the Key Employee as maintained from time to time on the payroll system of the Company and, if to the Company, to the address set forth below, or to such other address as either party may have furnished to the other in writing in accordance herewith, except that notice of change of address shall be effective only upon actual receipt:

To the Company:

4400 Post Oak Parkway, Suite 2700

Houston, TX 77027

Attention:  General Counsel

8.Miscellaneous.  No provision of this Agreement may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in writing and signed by the Key Employee and such officer as may be specifically designated by the Board.  No waiver by either party hereto at any time of any breach by the other party hereto of, or of any lack of compliance with, any condition or provision of this Agreement to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time.  This Agreement supersedes any other agreements or representations, oral or otherwise, express or implied, with respect to the subject matter hereof which have been made by the Key Employee or the Company.  The validity, interpretation, construction and performance of this Agreement shall be governed by the laws of the State of Texas without regard to its principles of conflicts of law.  All references to sections of the Code shall be deemed also to refer to any successor provisions to such sections.  Any payments provided for hereunder shall be paid net of any applicable withholding required under federal, state or local law and any additional withholding to which the Key Employee has agreed.

9.Validity.  The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, which shall remain in full force and effect.

10.Counterparts.  This Agreement may be executed in several counterparts, each of which shall be deemed to be an original but all of which together will constitute one and the same instrument.

11.Settlement of Disputes.  All claims by the Key Employee for benefits under this Agreement shall be directed to and determined by the Board and shall be in writing.  Any denial by the Board of a claim for benefits under this Agreement shall be delivered to the Key Employee in writing and shall set forth the specific reasons for the denial and the specific provisions of this Agreement relied upon.  The Board shall afford a reasonable opportunity to the Key Employee for a review of the decision denying a claim and shall further allow the Key Employee to appeal to the Board a decision of the Board within sixty (60) days after notification by the Board that the Key Employee’s claim has been denied.  The Board shall render its final decision within fifteen (15) days from the date on which the Key Employee files an appeal with the Board.

12.Definitions.  For purposes of this Agreement, the following terms shall have the meanings indicated below:

(A)“Base Salary” shall have the meaning set forth in Section 4.1 hereof.

(B)“Board” shall mean the Board of Directors of the Company.

(C)“Cause” for termination by the Company of the Key Employee’s employment shall mean (i) the willful and continued failure by the Key Employee to substantially perform the Key Employee’s duties with the Company (other than any such failure resulting from the Key Employee’s incapacity due to physical or mental illness or any such actual or anticipated failure after the issuance of a Notice of Termination for Good Reason by the Key Employee pursuant to Section 5.1 hereof) after a written demand for substantial performance is delivered to the Key Employee by the Board, which demand specifically identifies the manner in which the Board believes that the Key Employee has not substantially performed the Key Employee’s duties, or (ii) the willful engaging by the Key Employee in conduct which is demonstrably and materially injurious to the Company, monetarily or otherwise.  For purposes of clauses (i) and (ii) of this definition, (x) no act, or failure to act, on the Key Employee’s part shall be deemed “willful” unless done, or omitted to be done, by the Key Employee not in good faith and without reasonable belief that the Key Employee’s act, or failure to act, was in the best interest of the Company and (y) in the event of a dispute concerning the application of this provision, no claim by the Company that Cause exists shall be given effect unless the Company establishes to the Board by clear and convincing evidence that Cause exists.

(D)“Change in Control” shall be deemed to have occurred if the common stock, $.10 par value, of the Company owned by KSA Industries, Inc., K.S. Adams, Jr., Nancy N. Adams, and their children and grandchildren is less in the aggregate than twenty percent (20%) of the then-total issued and outstanding common stock of the Company.

(E)“Code” shall mean the Internal Revenue Code of 1986, as amended from time to time.

(F)“Company” shall mean Adams Resources & Energy, Inc. and shall include any successor to its business and/or assets which assumes and agrees to perform this Agreement by operation of law, or otherwise.

(G)“Date of Termination” shall have the meaning set forth in Section 5.2 hereof.

(H)“Effective Date” shall have the meaning set forth in Section 2 hereof.

(I)“Good Reason” for termination by the Key Employee of the Key Employee’s employment shall mean the occurrence (without the Key Employee’s express written consent), after any Change in Control, of any one of the following acts by the Company or subsidiary (if applicable), or failures by the Company or subsidiary (if applicable) to act, unless such act or failure to act is corrected prior to the Date of Termination specified in the Notice of Termination given in respect thereof:

(I)a material reduction in the Key Employee’s authority, duties or responsibilities, which for purposes of this Agreement shall include only the assignment to the Key Employee of any duties substantially inconsistent with the Key Employee’s status as a senior Key Employee officer of the Company or subsidiary (if applicable) or a material adverse alteration in the nature or status of the Key Employee’s responsibilities from those in effect immediately prior to the Change in Control;

(II)a material diminution in base salary as in effect immediately prior to the Change in Control; or

(III)a material change in the geographic location at which the Key Employee must perform services, which for purposes of this Agreement shall include only the relocation of the Key Employee’s principal place of employment to a location more than fifty (50) miles distant from the Company’s headquarters immediately prior to the Change in Control or the Company’s requiring the Key Employee to be based anywhere other than such principal place of employment (or permitted relocation thereof) except for reasonably required travel on the Company’s business.

The Key Employee’s continued employment shall not constitute consent to, or a waiver of rights with respect to, any act or failure to act constituting Good Reason hereunder, provided that the Key Employee may not assert Good Reason in respect of any act or failure to act otherwise constituting Good Reason hereunder unless asserted in a Notice of Termination given in respect thereof within ninety (90) days following the date of the first occurrence of such act or failure to act.

(J)“Key Employee” shall mean the individual named in the first paragraph of this Agreement.

(K)“Notice of Termination” shall have the meaning set forth in Section 5.1 hereof.

(L)“Separation” shall have the meaning set forth in the recitals hereof.

(M)“Severance Payment” shall have the meaning set forth in Section 4.1 hereof.

IN WITNESS WHEREOF, the parties have duly executed this Agreement to be effective as of the Effective Date.

ADAMS RESOURCES & ENERGY, INC.

By:                                                                           

Name:                                                                           

Title:                                                                           

KEY EMPLOYEE

SHARON COPELAND

EX-21.0

EXHIBIT 21

SUBSIDIARIES OF THE REGISTRANT

The following is a list of all subsidiary corporations of the registrant.  All subsidiaries are wholly-owned by the Company, except that Buckley Mining Corporation and Plastics Universal Corporation are wholly-owned subsidiaries of Ada Mining Corporation.  The Company's consolidated financial statements include the accounts of all subsidiaries.

Subsidiary	Place of Incorporation
Adams Resources Exploration Corporation	Delaware
Kirbyville Marketing Co., Inc.	Texas
Service Transport Company	Texas
Bayou City Pipelines, Inc.	Texas
Ada Crude Oil Company	Texas
Ada Mining Corporation	Texas
Classic Coal Corporation	Delaware
Plastics Universal Corporation	Kentucky
CJC Leasing, Inc.	Kentucky
Buckley Mining Corporation	Kentucky
Gulfmark Energy, Inc.	Texas
Ada Resources, Inc.	Texas
Adams Resources Marketing, Ltd.	Texas
Adams Resources Marketing GP, Inc.	Texas
Adams Resources Marketing II, Inc.	Nevada
Gulfmark Energy Marketing, Inc.	Nevada

EX-23.1

Exhibit 23.1

CONSENT OF RYDER SCOTT COMPANY

The undersigned hereby consents to the references to our firm in the form and context in which they appear in the Annual Report on Form 10-K of Adams Resources & Energy, Inc. for the year ended December 31, 2011 (the “Annual Report”).  We hereby further consent to the inclusion in the Annual Report of our report entitled “Adams Resources Exploration Corporation – Estimated Future Reserves and Income Attributable to Certain Leasehold Interests – SEC Parameters – As of December 31, 2011” and to the inclusion of our report dated January 30, 2012 as an exhibit to the Annual Report.

 /s/ Ryder Scott Company, L.P.

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration  No. F-1580

Houston, Texas

March 22, 2012

EX-31.1

Exhibit 31.1

ADAMS RESOURCES & ENERGY, INC.

CERTIFICATION PURSUANT TO

17 CFR 240.13a-14(a)/15d-14(a)

AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, K. S. Adams, Jr. certify that:

1.   I have reviewed this annual report on Form 10-K of Adams Resources & Energy, Inc. (the “registrant”);

2.   Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.   Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.   The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in exchange act rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

(a)   designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

         (b)  designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

          (c)  evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

         (d)  disclosed in this report any change in the registrant’s internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f), that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5.   The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

(a)   all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)   any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls.

Date:  March 22, 2012

/s/ K. S. Adams, Jr.                                                                

K. S. Adams, Jr.

Chief Executive Officer

EX-31.2

Exhibit 31.2

ADAMS RESOURCES & ENERGY, INC.

CERTIFICATION PURSUANT TO

17 CFR 240.13a-14(a)/15d-14(a)

AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Richard B. Abshire, certify that:

1.   I have reviewed this annual report on Form 10-K of Adams Resources & Energy, Inc. (the “registrant”);

2.   Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.   Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.   The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in exchange act rules 13a-15(f) and 15d-15(f)) for the registrant and we have:, as for the registrant and we have:

(a)   designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

         (b)  designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

         (c)  evaluated the effectiveness of the registrant's disclosure and procedures controls and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

         (d)  disclosed in this report any change in the registrant’s internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f), that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5.   The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

(a)   all significant deficiencies in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)   any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls.

Date:  March 22, 2012

/s/ Richard B. Abshire                                                                           

Richard B. Abshire

Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Adams Resources & Energy, Inc. (the “Company”) on Form 10-K for the year ended December 31, 2011 (the “Report”), I, K. S. Adams, Jr., Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1)   The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)   The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ K. S. Adams, Jr.                                

K. S. Adams, Jr.

Chief Executive Officer

March 22, 2012

This Certification is being furnished solely to accompany the Report pursuant to 18 U.S.C.§1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and shall not be incorporated by reference into any filing of the Company under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, whether made before or after the date of this Report, irrespective of any general incorporation language contained in such filing.

A signed original of this written statement required by Section 906, or other documents authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Adams Resources & Energy, Inc. (the “Company”) on Form 10-K for the year ended December 31, 2011 (the “Report”), I, Richard B. Abshire, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1)   The Report fully complies with the requirements of Section 13(a) of 15(d) of the Securities Exchange Act of 1934; and

(2)   The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Richard B. Abshire                                           

Richard B. Abshire

Chief Financial Officer

March 22, 2012

This Certification is being furnished solely to accompany the Report pursuant to 18 U.S.C.§1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and shall not be incorporated by reference into any filing of the Company under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, whether made before or after the date of this Report, irrespective of any general incorporation language contained in such filing.

A signed original of this written statement required by Section 906, or other documents authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.1

Exhibit 99.1

ADAMS RESOURCES EXPLORATION CORPORATION

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold and Royalty Interests

SEC Parameters

As of

December 31, 2011

\s\ Fred W. Ziehe

Fred W. Ziehe, P.E.

TBPE License No. 63630

Managing Senior Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

TBPE REGISTERED ENGINEERING FIRM F-1580                                                                                                                         FAX (713) 651-0849

1100 LOUISIANA    SUITE 3800HOUSTON, TEXAS 77002-5235                                                                                               TELEPHONE (713) 651-9191

                                                              January 30, 2012

Adams Resources Exploration Corporation

17 S. Briar Hollow Lane, Suite 100

Houston, TX  77027

Gentlemen:

At your request, Ryder Scott Company (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold and royalty interests of Adams Resources Exploration Corporation (Adams) as of December 31, 2011.  The subject properties are located in the states of Alabama, Arkansas, Kansas, Louisiana, Montana, Oklahoma and Texas and in the federal waters offshore Louisiana.  The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations).  Our third party study, completed on January 25, 2012 and presented herein, was prepared for public disclosure by Adams in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.  The properties reviewed by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon and gas reserves of Adams.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2011, are related to hydrocarbon prices.  The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations.  Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report.  The results of this study are summarized below.

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold and Royalty Interests of

Adams Resources Exploration Corporation

As of December 31, 2011

	Proved
	Developed
	Producing		Non-Producing		Undeveloped		Total Proved
Net Remaining Reserves
Oil/Condensate – MBbls		240.4		36.8		15.0		292.2
Plant Products – MBlls		0.6		3.9		0.0		4.5
Gas – MMCF		6,901.0		2,532.0		228.0		9,661.0
MBOE		1,391.2		462.7		53.0		1,906.9
Income Data – M$
Future Gross Revenue	$	51,874.1	$	15,516.6	$	2,347.9	$	69,738.6
Deductions		13,737.9		3,512.8		848.3		18,099.0
Future Net Income (FNI)	$	38,136.2	$	12,003.8	$	1,499.6	$	51,639.6
Discontinued FNI @ 10%	$	26,168.5	$	5,187.2	$	845.3	$	32,201.0

Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (MBbls).  All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.  The net remaining reserves are also shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent.  MBOE means thousands of barrels of oil equivalent.  In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package AriesTM System Petroleum Economic Evaluation Software, a copyrighted program of Halliburton.  The program was used at the request of Adams.  Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized.  Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding.  The rounding differences are not material.

The future gross revenue is after the deduction of production taxes.  The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net of salvage.  The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income.  Gas reserves account for approximately 62 percent and liquid hydrocarbon reserves account for the remaining 38 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly.  Future net income was discounted at four other discount rates which were also compounded monthly.  These results are shown in summary form as follows.

		Discounted Future Net Income – M$
		As of December 31, 2011
Discount Rate		Total
Percent		Proved
	2.5	$	43,842.8
	5.0	$	38,741.8
	15.0	$	28,009.9
	20.0	$	25,020.3

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a).  An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report.  The proved developed non-producing reserves included herein consist of the behind pipe category.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist.  The proved gas volumes included herein do not attribute gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.”  All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made.  The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.  The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.  Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.  At Adams’ request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward”.  The proved reserves included herein were estimated using deterministic methods.  If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.  For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.”  Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks.  Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Adams’ operations may be subject to various levels of governmental controls and regulations.  These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time.  Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Adams owns an interest; however, we have not made any field examination of the properties.  No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations.  The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a).  The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures.  These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy.  These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves.  Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator.  When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves.  If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator.  Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported.  For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.”  The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.”  The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.”  All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available.  Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods, the volumetric method, analogy, or a combination of methods.  Almost all of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods.  These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of historical monthly production and pressure data generally available through October 2011, and in some instances with test data available through November 2011, in those cases where such data were considered to be definitive.  The data utilized in this analysis were furnished to Ryder Scott by Adams or obtained from public data sources and were considered sufficient for the purpose thereof.  The remaining small portion of the proved producing reserves were estimated by analogy where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

All of the proved developed non-producing and undeveloped reserves included herein were estimated by the volumetric method, analogy, or a combination of methods.  The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by Adams or which we have obtained from public data sources that were available through December 2011.  The data utilized from the analogues as well as well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof.

It should be noted that the proved reserve volumes described herein consist of primary recovery, including both pressure depletion and natural water drive mechanisms.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates.  Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined.  While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Adams has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation.  In preparing our forecast of future proved production and income, we have relied upon data furnished by Adams with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, including the terms of certain severance tax exemptions, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements.  Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Adams.  We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein.  The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.”  In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data.  If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated.  An estimated rate of decline was then applied to depletion of the reserves.  If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing.  For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Adams.  Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production.  Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements.  For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract.  Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

Adams furnished us with the above mentioned average prices in effect on December 31, 2011.  These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold.  These benchmark prices are prior to the adjustments for differentials as described herein.  The table below summarizes the “benchmark prices” and “price reference” used for the geographic areas included in the report.  In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.  In cases where there are numerous contracts or price references within the same geographic area, the benchmark price is represented by the unweighted arithmetic average of the initial 12-month average first-day-of-the-month benchmark prices used.

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.”  The differentials used in the preparation of this report were furnished to us by Adams, accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Adams to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.”  The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
	Oil/Condensate	Various1	$     90.88 / Bbl	$     95.85 / Bbl
Total U.S. Domestic	Plant Products	% WTI2	$     57.71 / Bbl	$     57.71 / Bbl
	Gas	Various3	$       4.01 / MMBTU	$       4.69 / MCF

1 Oil/Cond Benchmarks include Postings for:  LOTT Arkansas Sweet, Kansas Common, North Dakota – Williston Sweet, Chevron Heavy Louisiana Sweet, N Louisiana, So Louisiana Light, Mississippi Light Sour, OK Sweet Central, OK Sweet, Gulfmark Contract_Lt Sweet_NYMEX, East Tx Field, Giddings, Tx Upper Gulf Coast, So Tx Light, W Central Tx and W Tx Intermediate – Area 1

2 Plant Product Benchmark assumes:   60% of WTI Cushing

3 Gas Benchmarks include:  Carthage Hub, CIG, El Paso-Permian, Henry Hub, Houston Ship Channel, NGPL_MC, NGPL_STX, NGPL_TexOk Zone, Southern Natural Gas, Texas Eastern, Transco Zone 4, Transwestern Permian Basin, and Trunkline ELA

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were provided by Adams and include only those costs directly applicable to the leases or wells.  The operating costs include a portion of general and administrative costs allocated directly to the leases and wells.  For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs.  The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements.  The operating costs furnished to us were accepted as factual data and were used without independent verification.  No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by Adams and are based on authorizations for expenditure for the proposed work or actual costs for similar projects.  The development costs furnished to us were accepted as factual data and were used without independent verification.  The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant.  The estimates of the net abandonment costs furnished by Adams were accepted without independent verification.  Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for Adams’ estimate.

The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with Adams’ plans to develop these reserves as of December 31, 2011.  The implementation of Adams’ development plans as presented to us and incorporated herein is subject to the approval process adopted by Adams’ management.  As the result of our inquiries during the course of preparing this report, Adams has informed us that the development activities included herein have been subjected to and received the internal approvals required by Adams’ management at the appropriate local, regional and/or corporate level.  In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Adams.  Additionally, Adams has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by Adams were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years.  Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada.  We have over eighty engineers and geoscientists on our permanent staff.  By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue.  We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients.  This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations.  Many of our staff have authored or co-authored technical papers on the subject of reserves related topics.  We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Adams.  Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties that were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott.  The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Adams.

We have provided Adams with a digital version of the original signed copy of this report letter.  In the event there are any differences between the digital version included in filings made by Adams and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices.  Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

\s\ Fred W. Ziehe

Fred W. Ziehe, P.E.

TBPE License No. 63630

Managing Senior Vice President

           [SEAL]

FWZ/pl

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P.  Mr. Fred W. Ziehe was the primary technical person responsible for overseeing the estimate of the reserves, future production and income prepared by Ryder Scott presented herein.

Mr. Ziehe, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1976, is a Managing Sr. Vice President and also serves as an Engineering Group Coordinator responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide.  Before joining Ryder Scott, Mr. Ziehe served as a Reservoir Engineer with Exxon Company U.S.A.  For more information regarding Mr. Ziehe’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mr. Ziehe earned a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1974, with Magna Cum Laude honors and is a registered Professional Engineer in the State of Texas.  He is also a member of the Society of Petroleum Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Ziehe fulfills.  As part of his 2011 continuing education hours, Mr. Ziehe attended 8 hours of formalized training including the 2011 Ryder Scott Reserves Conference and various professional society presentations specifically relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission (SEC) Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register and topical discussions on the future of natural gas, shale gas, the SPEE Monograph 3 (“Guidelines for the Practical Evaluation of Undeveloped Reserves in Resource Plays”), and Reserve Management Systems.  Mr. Ziehe participated as a co-presenter in 9 hours of lectures made to undergraduate and graduate Petroleum Engineering students at Texas A & M University and internally to Ryder Scott personnel concerning the “SEC Comment Letter Process”.  Mr. Ziehe attended an additional 5.5 hours of formalized in-house training during  2011 covering certain oil and gas related software programs and 2 hours of ethics training.  In addition to this training, Mr. Ziehe, during 2010, also attended 14 hours of formalized training covering such topics as various oil and gas producing basins in the United States, the SPEE Monograph 3, and the use of certain petroleum economics evaluation software.

Based on his educational background, professional training and more than 37 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Ziehe has attained the professional qualifications as a Reserves Estimator and Reserves Auditor as set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA).  The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K.  The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”.  The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010.  Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made.  The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.  The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.  Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.  Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC.  The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods.  Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery.  Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids.  Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations.  Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale.  Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits.  These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves.  Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible.  Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results).  Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves.  Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs.  Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1)           completion intervals which are open at the time of the estimate, but which have not  started producing;

(2)           wells which were shut-in for market conditions or pipeline connections; or

(3)           wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

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Concentration of Credit Risk

12 Months Ended

Dec. 31, 2011

Concentration of Credit Risk [Abstract]

Concentration of Credit Risk

(3)  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. Accounts receivable associated with crude oil and natural gas marketing activities comprise approximately 90 percent of the Company's total receivables and industry practice requires payment for such sales to occur within 25 days of the end of the month following a transaction.  The Company's customer mix, credit policies and the relatively short duration of receivables mitigate the uncertainty typically associated with receivables management.

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.  Within this group of customers the Company generally derives up to 50 percent of its revenues from two to three large crude oil refining concerns.  While the Company has ongoing established relationships with certain domestic refiners of crude oil, alternative markets are readily available since the Company supplies less than one percent of U. S. domestic refiner demand.  As a fungible commodity delivered to major Gulf Coast supply points, the Company's crude oil sales can be readily delivered to alternative end markets.  Management believes that a loss of any of those customers where the Company currently derives more than 10 percent of its revenues would not have a material adverse effect on the Company's operations.

The Company had accounts receivable from two customers that comprised 24.5 percent and 21.5 percent, respectively, of total accounts receivable at December 31, 2011.  Four customers comprised 18.2 percent, 15.4 percent, 13.4 percent, and 11.3 percent, respectively, of total revenues during 2011.  The Company had accounts receivable from four customers that comprised 22.4 percent, 16.2 percent, 13.7 percent and 10.6 percent, respectively, of total accounts receivable at December 31, 2010.  Five customers comprised 35.8 percent, 20.2 percent, 17.9 percent, 13 percent and 11 percent, respectively, of total revenues during 2010.  The Company had accounts receivable from three customers that comprised 17.8 percent, 12.6 percent and 10.8 percent, respectively of total accounts receivables at December 31, 2009.  Three customers comprised 39.4 percent, 17.7 percent and 15.7 percent, respectively, of total revenues during 2009.

An allowance for doubtful accounts is provided where appropriate and accounts receivable presented herein are net of allowances for doubtful accounts of $2,205,000 and $1,064,000 at December 31, 2011 and 2010, respectively.  As reflected in the table below, during 2011 and 2009 the  Company's provision for bad debt was elevated as a result of deteriorating  collectability  primarily attributable to diesel fuel sales to the construction industry.

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

	2011			2010			2009
Balance, beginning of year	$	1,064		$	1,681		$	1,251
Provisions for bad debts		1,223			29			704
Less:  Write-offs and recoveries		(82	)		(646	)		(274	)
Balance, end of year	$	2,205		$	1,064		$	1,681

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Income Taxes

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

Income Taxes

(2)  Income Taxes

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

	Years ended December 31,
	2011			2010			2009
Current:
Federal	$	(4,336	)	$	350		$	(649	)
State		(1,187	)		(721	)		(631	)
		(5,523	)		(371	)		(1,280	)
Deferred:
Federal		(7,407	)		(3,688	)		(1,286	)
State		99			(11	)		214
		(7,308	)		(3,699	)		(1,072	)
	$	(12,831	)	$	(4,070	)	$	(2,352	)

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

	Years ended December 31,
	2011			2010			2009
Statutory federal income tax (provision) benefit	$	(12,517	)	$	(4,445	)	$	(2,275	)
State income tax (provision) benefit		(707	)		(476	)		(270	)
Federal statutory depletion		393			534			186
Foreign investment write-off		-			201			-
Other		-			116			7
	$	(12,831	)	$	(4,070	)	$	(2,352	)

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

	Years Ended December 31,
	2011			2010
Current deferred tax asset (liability)
Allowance for doubtful accounts	$	772		$	372
Prepaid insurance		(793	)		(776	)
Fair value contracts		(484	)		(450	)
Net current deferred liability		(505	)		(854	)
Long-term deferred tax asset (liability)
Property		(10,579	)		(2,885	)
Uniform capitalization		471			396
Other		160			198
Net long-term deferred tax  liability		(9,948	)		(2,291	)
Net deferred tax liability	$	(10,453	)	$	(3,145	)

Financial statement recognition and measurement of positions taken, or expected to be taken, by an entity in its income tax returns must consider the uncertainty and judgment involved in the determination and filing of income taxes.  Tax 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 tax position will be examined by taxing authorities with full knowledge of all relevant information.  As of December 31, 2010, the Company had accrued approximately $27,000 including approximately $8,000 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):

	2011			2010
Balance as of January 1,	$	19		$	72
Additions for tax positions of prior years		-			-
Reductions of prior positions		(19	)		(53	)
Balance as of December 31,	$	-		$	19

The Company has filed all remaining open returns and expects final resolution with all states by year-end 2011.  As the actual tax payments are made, the accrual is reduced.  The Company has no other unrecognized tax benefits.  Interest and penalties associated with income tax liabilities are classified as income tax expense.

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

	Earliest Open
	Tax Year
Federal	2008
Texas	2007
Louisiana	2008
Michigan	2008

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CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
CURRENT ASSETS:
Cash and cash equivalents	$ 37,066	$ 29,032
Accounts receivable, net of allowance for doubtful accounts of $2,205 and $1,064, respectively	234,515	190,169
Inventories	20,189	14,591
Fair value contracts	2,064	2,764
Income tax receivable	480	2,316
Prepayments	10,651	8,104
Total current assets	304,965	246,976
PROPERTY AND EQUIPMENT:
Marketing	38,467	25,407
Transportation	54,359	43,131
Oil and gas (successful efforts method)	81,668	73,011
Other	1,553	188
Property and Equipment	176,047	141,737
Less - Accumulated depreciation, depletion and amortization	(106,812)	(94,148)
Net property and equipment	69,235	47,589
OTHER ASSETS:
Oil and gas property held for sale	0	3,389
Deferred income tax asset	473	374
Cash deposits and other	4,167	2,977
Total Assets	378,840	301,305
CURRENT LIABILITIES:
Accounts payable	248,656	200,763
Accounts payable - related party	58	9
Fair value contracts	681	1,478
Accrued and other liabilities	6,194	3,894
Current deferred income taxes	505	854
Total current liabilities	256,094	206,998
LONG-TERM DEBT	0	0
OTHER LIABILITIES:
Asset retirement obligations	1,568	1,390
Deferred taxes and other liabilities	10,496	2,762
Total Liabilites	268,158	211,150
COMMITMENTS AND CONTINGENCIES (NOTE 6)
SHAREHOLDERS' EQUITY:
Preferred stock, $1.00 par value, 960,000 shares authorized, none outstanding	0	0
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	98,567	78,040
Total shareholders' equity	110,682	90,155
Liabilities and stockholders equity	$ 378,840	$ 301,305

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
CASH PROVIDED BY OPERATIONS:
Net earnings	$ 22,931	$ 8,631	$ 4,149
Adjustments to reconcile net earnings to net cash from operating activities-
Depreciation, depletion and amortization	16,260	11,817	10,320
Property sale (gains) losses	(4,394)	94	(177)
Dry hole costs incurred	1,212	1,894	661
Impairment of oil and natural gas properties	14,749	2,224	3,773
Provision for doubtful accounts	1,141	29	430
Deferred income taxes	7,308	3,699	1,072
Net change in fair value contracts	(97)	(1,036)	251
Decrease (increase) in accounts receivable	(45,487)	(34,257)	(36,515)
Decrease (increase) in inventories	(5,598)	669	(1,053)
Decrease (increase) in income tax receivable	1,836	(145)	1,458
Decrease (increase) in prepayments	(2,547)	2,700	(5,580)
Increase (decrease) in accounts payable	47,662	40,521	43,069
Increase (decrease) in accrued and other liabilities	1,378	(406)	(58)
Other changes, net	(539)	494	485
Net cash provided by operating activities	55,815	36,928	22,285
INVESTING ACTIVITIES:
Property and equipment additions	(53,276)	(22,421)	(22,390)
Insurance and state collateral (deposits) refunds	(495)	(151)	(192)
Proceeds from property sales	8,394	147	1,004
Redemption of short-term investments	11,098	0	0
Investment in short-term investments	(11,098)	0	0
Net cash (used in) investing activities	(45,377)	(22,425)	(21,578)
FINANCING ACTIVITIES:
Dividend payments	(2,404)	(2,277)	(2,109)
Net cash (used in) financing activities	(2,404)	(2,277)	(2,109)
Increase (decrease) in cash and cash equivalents	8,034	12,226	(1,402)
Cash and cash equivalents at beginning of year	29,032	16,806	18,208
Cash and cash equivalents at end of year	$ 37,066	$ 29,032	$ 16,806

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

(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  intercompany accounts and transactions.  The impact on the accompanying financial statements of events occurring after December 31, 2011 has been evaluated through the date of issuance of these financial statements.

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 and Cash Equivalents

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 corporate and municipal bonds, which are classified as investments in marketable securities, may also be made from time to time.  Cash and cash equivalents are maintained with major financial institutions and such deposits may exceed the amount of federally backed insurance provided.  While the Company regularly monitors the financial stability of such institutions, cash and cash equivalents ultimately remain at risk subject to the financial viability of such institutions.

Marketable Securities

From time to time, the Company may invest in marketable securities consisting of investment grade corporate bonds traded in liquid markets.  Such bonds are held for the purpose of investing in liquid funds and are not generally intended to be retained on a long term basis.  Marketable securities are initially recognized at acquisition costs inclusive of transaction costs and are classified as trading securities.  In subsequent periods marketable securities are valued at fair value.  Changes in these fair values are recognized as gains or losses in the accompanying statement of operations under the caption “Costs and Expenses – Marketing”.  Interest on marketable securities is recognized directly in the statement of operations during the period earned.

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 90 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,
	2011		2010
Crude oil	$	18,464	$	12,909
Petroleum products		1,725		1,682
	$	20,189	$	14,591

Prepayments

The components of prepayments and other are as follows (in thousands):

	December 31,
	2011		2010
Cash collateral deposits for commodity purchases	$	6,521	$	5,150
Insurance premiums		2,033		1,954
Commodity imbalances and futures		1,452		330
Rents, license and other		645		670
	$	10,651	$	8,104

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, 2011, the Company had no unevaluated or suspended exploratory drilling costs.

Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method.  The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves.  For lease and well equipment, development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves.  All other property and equipment is depreciated using the straight-line method over the estimated average useful lives of three to twenty years.

The Company  reviews its long-lived assets for impairment whenever there is evidence that the carrying value of such assets may not be recoverable.  Any impairment recognized is permanent and may not be restored.  Producing oil and gas properties are reviewed  on a field-by-field basis.  For properties requiring impairment, the fair value is estimated based on an internal discounted cash-flow model.  Cash flows are developed based on estimated future production and prices and then discounted using a market based rate of return consistent with that used by the Company in evaluating cash flows for other assets of a similar nature.  For the years ended December 31, 2011, 2010 and 2009 there were $7,105,000, $946,000 and $1,350,000 impairment provisions on producing oil and gas properties, respectively.

Fair value measurements for producing oil and gas properties that were subject to fair value impairment for the years ended December 31, 2011 and 2010 summarized as follows (in thousands):

	Producing Properties Subject to Fair Value Impairment
	2011			2010
Net book value at January 1	$	8,704		$	2,220
Property additions		16,465			1,802
Depletion taken		(6,633	)		(753	)
Impairment valuation loss		(7,105	)		(946	)
Net book at December 31	$	11,431		$	2,323

Fair value measurements for producing oil and gas properties are based on Level 3 – Significant Unobservable Inputs – (see Fair Value Measurements below).

On a quarterly basis, management also evaluates the carrying value of non-producing oil and gas properties and may deem them impaired  based on remaining lease term, drilling activity in the area and the Company's plans for the property.  Accordingly, impairment provisions on non-producing properties totaling $7,644,000, $1,277,000 and $2,423,000 were recorded for the years ended December 31, 2011, 2010 and 2009, respectively.  For non-producing properties, impairments are determined based on management's knowledge of current geological evaluations, drilling results and activity in the area and intent to drill as it relates to the remaining term of the underlying oil and gas leasehold interest.

Cash Deposits and Other Assets

The Company has established certain deposits to support participation in its liability insurance program and remittance of state crude oil severance taxes and other state collateral deposits.  Insurance collateral deposits are invested at the discretion of the Company's insurance carrier and such investments primarily consist of intermediate term federal government bonds and bonds backed by federal agencies.  Components of cash deposits and other assets are as follows (in thousands):

	December 31,
	2011		2010
Insurance collateral deposits	$	3,331	$	2,291
State collateral deposits		168		166
Materials and supplies		668		520
	$	4,167	$	2,977

Revenue Recognition

Commodity purchase and sale contracts utilized by the Company's marketing businesses qualify as derivative instruments.  Further, all natural gas, as well as certain specifically identified crude oil purchase and sale contracts, are designated as trading activities.  From the time of contract origination, such trading activity contracts are marked-to-market and recorded on a net revenue basis in the accompanying financial statements.

Substantially all crude oil and refined products purchase and sale contracts qualify and are designated as non-trading activities and the Company elects the normal purchases and sales exception methodology for such activity.  For normal purchase and sale activities, the Company's customers are invoiced monthly based upon contractually agreed upon terms with revenue recognized in the month in which the physical product is delivered to the customer.  Such sales are recorded gross in the financial statements because the Company takes title to and has risk of loss for the products, is the primary obligor for the purchase, establishes the sale price independently with a third party and maintains credit risk associated with the sale of the product.

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.  Such buy/sell arrangements are reflected on a net revenue basis in the accompanying financial statements.  Reporting such crude oil contracts on a gross revenue basis would increase the Company's reported revenues by $1,812,561,000, $1,415,844,000 and $874,386,000 for the years ended December 31, 2011, 2010 and 2009, respectively.

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.

Letter of Credit Facility

The Company maintains a Credit and Security Agreement with Wells Fargo Bank to provide a $60 million stand-by letter of credit facility to support the Company's crude oil and natural gas purchases within the marketing segment.  This facility is collateralized by the eligible accounts receivable within those operations.  Stand-by letters of credit issued totaled $38.9 million and $23.9 million as of December 31, 2011 and 2010, respectively.  The issued stand-by letters of credit are cancelled as the underlying purchase obligations are satisfied by cash payment when due.  The letter of credit facility places certain restrictions on the Company's Gulfmark Energy, Inc. and Adams Resources Marketing, Ltd. subsidiaries.  Such restrictions included the maintenance of a combined 1.1 to 1.0 current ratio and the maintenance of positive net earnings excluding inventory valuation changes, as defined, among other restrictions.  Management believes the Company is currently in compliance with all such financial covenants.

Statement of Cash Flows

Interest paid totaled $8,000, $36,000 and $25,000 during the years ended December 31, 2011, 2010 and 2009, respectively.  Income taxes paid during these same periods totaled $5,597,000, $532,000, and $1,152,000, respectively.  State and Federal income tax refunds totaled $2,743,000 and $2,000,000 in 2011 and 2009, respectively.  Non-cash investing activities for property and equipment items included in accounts payable as of period end were $4,070,000 and $2,868,000 as of December 31, 2011 and 2010, respectively.  There were no significant non-cash financing activities in any of the periods reported.

Earnings per Share

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 2011, 2010 and 2009.  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 oil and gas reserve volumes that form the foundation for (1) calculating depreciation, depletion and amortization and (2) deriving cash flow estimates to assess impairment triggers or estimated values associated with oil and gas property, revenue accruals, the provision for bad debts, insurance related accruals, income taxes, contingencies and valuation of fair value contracts.

Income Taxes

Income taxes are accounted for using the asset and liability method.  Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis (see Note 2).

Use of Derivative Instruments

The Company's marketing segment is involved in the purchase and sale of crude oil and natural gas.  The Company seeks to make a profit by procuring such commodities as they are produced and then delivering such products to the end users or intermediate use marketplace.  As is typical for the industry, in certain cases such transactions are made pursuant to the terms of forward month commodity purchase and/or sale contracts.  These contracts meet the definition of a derivative instrument and therefore, the Company accounts for such contracts at fair value, unless the normal purchase and sale exception is applicable.  Such underlying contracts are standard for the industry and are the governing document for the Company's crude oil and natural gas wholesale distribution businesses.  The accounting methodology utilized by the Company for its commodity contracts is further discussed below under the caption “Fair Value Measurements”.

None of the Company's derivative instruments have been designated as hedging instruments and the estimated fair value of forward month commodity contracts (derivatives) is reflected in the accompanying Consolidated Balance Sheet as of December 31, 2011 as follows (in thousands):

	Balance Sheet Location and Amount
	Current			Other		Current			Other
	Assets			Assets		Liabilities			Liabilities
Asset Derivatives
- Fair Value Commodity
Contracts at Gross Valuation	$	3,500		$	-	$	-		$	-
Liability Derivatives
- Fair Value Commodity
Contracts at Gross Valuation		-			-		2,117			-
Less Counterparty Offsets		(1,436	)		-		(1,436	)		-
As Reported Fair Value Contracts	$	2,064		$	-	$	681		$	-

Forward month commodity contracts (derivatives) are reflected in the accompanying Consolidated Balance Sheet as of December 31, 2010 as follows (in thousands):

	Balance Sheet Location and Amount
	Current			Other		Current			Other
	Assets			Assets		Liabilities			Liabilities
Asset Derivatives
- Fair Value Commodity
Contracts at Gross Valuation	$	8,094		$	-	$	-		$	-
Liability Derivatives
- Fair Value Commodity
Contracts at Gross Valuation		-			-		6,808			-
Less Counterparty Offsets		(5,330	)		-		(5,330	)		-
As Reported Fair Value Contracts	$	2,764		$	-	$	1,478		$	-

The Company only enters into commodity contracts with creditworthy counterparties or obtains collateral support for such activities.  As of December 31, 2011 and 2010, the Company was not holding nor had it posted any collateral to support its forward month fair value derivative activity. The Company is not subject to any credit-risk related trigger events.

Forward month commodity contracts (derivatives) are reflected in the accompanying Consolidated Statement of Operations for the years ended December 31, 2011,  2010 and 2009 as follows (in thousands):

	Gain (Loss)
Location	2011		2010		2009
Revenues - marketing	$	97	$	1,036	$	(251	)

 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.  Marketable securities are recorded at fair value based on market quotations from actively traded liquid markets.

Fair value contracts consist of derivative financial instruments and are recorded as either an asset or liability measured at  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 during any reporting periods.

Fair value estimates are based on assumptions that market participants would use when pricing an asset or liability and the Company uses 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 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.  For Level 1 valuation of marketable securities, the Company utilizes market quotations provided by its primary financial institution and for the valuations of derivative financial instruments, the Company utilizes the New York Mercantile Exchange “NYMEX” for such 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.  Source data for Level 2 inputs include information provided by the NYMEX, the Intercontinental Exchange “ICE”, published price data and indices, third party price survey data and broker provided forward price statistics.

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

As of December 31, 2011, the Company's fair value assets and liabilities are summarized and categorized as follows (in thousands):

	Market Data Inputs
	Gross Level 1			Gross Level 2			Level 3		Counterparty
	Quoted Prices			Observable			Unobservable		Offsets			Total
Derivatives
- Current assets	$	1,455		$	2,045		$	-	$	(1,436	)	$	2,064
- Current liabilities		(675	)		(1,442	)		-		1,436			(681	)
Net Value	$	780		$	603		$	-	$	-		$	1,383

As of December 31, 2010, the Company's fair value assets and liabilities are summarized and categorized as follows (in thousands):

	Market Data Inputs
	Gross Level 1			Gross Level 2			Level 3		Counterparty
	Quoted Prices			Observable			Unobservable		Offsets			Total
Derivatives
- Current assets	$	-		$	8,094		$	-	$	(5,330	)	$	2,764
- Current liabilities		(118	)		(6,690	)		-		5,330			(1,478	)
Net Value	$	(118	)	$	1,404		$	-	$	-		$	1,286

The Company's gross transaction volumes for physically settled energy trading contracts were approximately 75,890,000 mmbtu's, 93,827,000 mmbtu's, and 132,488,000 mmbtu's in 2011, 2010 and 2009, 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, 2011 and 2010, 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, 2011 (in thousands):

	Level 1			Level 2
	Quoted Prices			Observable			Total
Net Fair Value January 1,	$	(118	)	$	1,404		$	1,286
- Net realized (gains) losses		118			(1,404	)		(1,286	)
- Net unrealized gains (losses)		780			603			1,383
Net Fair Value December 31,	$	780		$	603		$	1,383

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, 2010 (in thousands):

	Level 1			Level 2
	Quoted Prices			Observable			Total
Net Fair Value January 1,	$	224		$	26		$	250
- Net realized (gains) losses		(224	)		(26	)		(250	)
- Net unrealized gains (losses)		(118	)		1,404			1,286
Net Fair Value December 31,	$	(118	)	$	1,404		$	1,286

Asset Retirement Obligations

The Company records a 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 or the units of production associated with 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):

	2011			2010
Balance on January 1,	$	1,390		$	1,315
-Liabilities incurred		164			76
-Accretion of discount		82			75
-Liabilities settled		(68	)		(76	)
-Revisions to estimates		-			-
Balance on December 31,	$	1,568		$	1,390

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.

Recent Accounts Pronouncement

In January 2010, the Financial Accounting Standards Board (“FASB”) issued FASB Accounting Standards Update (ASU) No. 2010-03, “Oil and Gas Reserve Estimations and Disclosures” (ASU No. 2010-03).  This update aligns the current oil and gas reserve estimation and disclosure requirements of the Extractive Industries – Oil and Gas topic of the ASC (ASC Topic 932) with the changes required by the SEC final rule, “Modernization of Oil and Gas Reporting,” as discussed above.  ASU No. 2010-03 expands the disclosures required for equity method investments, revises the definition of oil and gas producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or gas, amends the definition of proved oil and gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and gas quantities and provides guidance on geographic area with respect to disclosure of information about significant reserves.  ASU No. 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate.  The Company adopted ASU No. 2010-03 effective December 31, 2009.

In May 2011, the FASB issued ASU 2011-04, which further amends the Fair Value Measurements and Disclosures topic of the Accounting Standards Codification.  Among other provisions, ASU 2011-04 expands and modifies certain principles and requirements for measuring fair value and disclosing fair value measurement information.  ASU 2011-04 is effective for interim and fiscal periods beginning after December 15, 2011.  The adoption of ASU 2011-04 is not expected to have a material impact on the Company's financial statements, but may result in additional disclosures regarding fair value measurements.

In December 2011, the FASB issued FASB Accounting Standards Update (ASU) 2011-11.  This update requires additional disclosures about an entity's right of setoff and related arrangements associated with its financial and derivative instruments.  The ASU requires a tabular presentation that reflects the gross, net and setoff amounts associated with such assets and liabilities among other requirements.  The expanded disclosure requirements are effective for the annual reporting periods beginning on January 1, 2013.  The adoption of ASU 2011-11 is not expected to result in significant additional disclosures.

Management believes the impact of other recently issued standards and updates, which are not yet effective, will not have a material impact on the Company's consolidated financial position, results of operations or cash flows upon adoption.

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
CURRENT ASSETS:
Accounts receivable, allowance for doubtful accounts	$ 2,205	$ 1,064
SHAREHOLDERS' EQUITY:
Preferred stock, par value (in dollars per share)	$ 1.00	$ 1.00
Preferred stock, shares authorized (in shares)	960,000	960,000
Preferred stock, shares outstanding (in shares)	0	0
Common stock, par value (in dollars per share)	$ 0.10	$ 0.10
Common stock, shares authorized (in shares)	7,500,000	7,500,000
Common stock, shares Issued (in shares)	4,217,596	4,217,596
Common stock, shares Outstanding (in shares)	4,217,596	4,217,596

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Oil and Gas Producing Activities (Unaudited)

12 Months Ended

Dec. 31, 2011

Oil and Gas Producing Activities (Unaudited) [Abstract]

Oil and Gas Producing Activities (Unaudited)

(11)Oil and Gas Producing Activities (Unaudited)

The Company's oil and gas exploration and production activities are conducted in Texas and the south central region of the United States, primarily along the Gulf Coast of Texas and Louisiana.

Oil and Gas Producing Activities -

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,
	2011		2010		2009
Property acquisition costs
Unproved	$	3,591	$	2,295	$	6,199
Proved		-		-		-
Exploration costs
Expensed		9,166		3,233		3,818
Capitalized		-		-		1,035
Development costs		12,133		6,233		2,341
Total costs incurred	$	24,890	$	11,761	$	13,393

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

	December 31,
	2011			2010
Unproved oil and gas properties	$	7,291		$	12,250
Proved oil and gas properties		74,376			69,011
		81,667			81,261
Accumulated depreciation, depletion
and amortization		(55,061	)		(51,857	)
Net capitalized cost	$	26,606		$	29,404

Estimated Oil and Natural Gas Reserves  -

The following information regarding estimates of the Company's proved oil and gas reserves, all located in Texas and the south central region of 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 changes in commodity pricing assumptions and 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,
	2011						2010						2009
	Natural						Natural						Natural
	Gas			Oil			Gas			Oil			Gas			Oil
	(Mcf's)			(Bbls.)			(Mcf's)			(Bbls.)			(Mcf's)			(Bbls.)
Total proved reserves-
Beginning of year		7,794			267			7,248			242			6,443			230
Revisions of previous estimates		(520	)		(24	)		(832	)		-			(129	)		(4	)
Oil and gas reserves sold		(2,148	)		(26	)		-			-			-			-
Extensions, discoveries and
Other reserve additions		6,430			137			2,743			79			2,238			66
Production		(1,895	)		(62	)		(1,365	)		(54	)		(1,304	)		(50	)
End of year		9,661			292			7,794			267			7,248			242

The components of proved oil and gas reserves for the three years ended December 31, 2011 is presented below.  All reserves are in the United States (in thousands):

	Years Ended December 31,
	2011				2010				2009
	Natural				Natural				Natural
	Gas		Oil		Gas		Oil		Gas		Oil
	(Mcf's)		(Bbls.)		(Mcf's)		(Bbls.)		(Mcf's)		(Bbls.)
Proved developed reserves		9,433		277		7,134		240		6,295		242
Proved undeveloped reserves		228		15		660		27		953		-
Total proved reserves		9,661		292		7,794		267		7,248		242

Proved undeveloped reserves originated in 2009 when active drilling efforts commenced and such period identified and delineated additional reserve acreage.  During 2010 drilling efforts continued identifying additional reserve acreage and converting such undeveloped reserves to the developed category.  Drilling in 2011 continued to develop the reserve acreage.

The Company has developed internal policies and controls for estimating and recording oil and gas reserve data.  The estimation and recording of proved reserves is required to be in compliance with SEC definitions and guidance.  The Company assigns responsibility for compliance in reserve bookings to the office of President of the Company's AREC subsidiary.  No portion of this individual's compensation is directly dependent on the quantity of reserves booked.  Reserve estimates are required to be made by qualified reserve estimators, as defined by Society of Petroleum Engineers' Standards.

The Company employs third party petroleum consultant, Ryder Scott Company, to prepare its oil and gas reserve data estimates as of December 31, 2011, 2010 and 2009.  The firm of Ryder Scott is well recognized within the industry for more than 50 years.  As prescribed by the SEC, such proved reserves were estimated using 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period, and year-end production and development costs for each of the years presented, all without escalation.

The process of estimating oil and gas reserves is complex and requires significant judgment.  Uncertainties are inherent in estimating quantities of proved reserves, including many factors beyond the estimator's control.  Reserve engineering is a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and the interpretation thereof.  As a result, estimates by different engineers often vary, sometimes significantly.  In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates.  Accordingly, oil and gas quantities ultimately recovered will vary from reserve estimates.

Standardized Measure of Discounted Future Net Cash Flows from Oil and Gas Operations and Changes Therein  -

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,
	2011			2010			2009
Future gross revenues	$	73,626		$	61,311		$	43,498
Future costs -
Lease operating expenses		(19,788	)		(17,288	)		(15,969	)
Development costs		(2,198	)		(1,596	)		(2,495	)
Future net cash flows before income taxes		51,640			42,427			25,034
Discount at 10% per annum		(19,439	)		(16,777	)		(10,719	)
Discounted future net cash flows
before income taxes		32,201			25,650			14,315
Future income taxes, net of discount at
10% per annum		(11,270	)		(8,978	)		(5,010	)
Standardized measure of discounted
future net cash flows	$	20,931		$	16,672		$	9,305

The reserve estimates provided at December 31, 2011, 2010 and 2009 are based on aggregate prices of $95.85, $76.14 and $58.43 per barrel for crude oil and $4.69, $5.26 and $4.05 per mcf for natural gas, respectively.  Such prices reflect the unweighted arithmetic average of the prices in effect on the first day of the month for each month of the respective twelve month periods as required by Securities & Exchange Commission regulations.  The affect of income taxes and discounting on the standardized measure of discounted future net cash flows is presented as follows (in thousands):

	Years ended December 31,
	2011			2010			2009
Future net cash flows before income taxes	$	51,640		$	42,427		$	25,034
Future income taxes		(18,074	)		(14,849	)		(8,762	)
Future net cash flows		33,566			27,578			16,272
Discount at 10% per annum		(12,635	)		(10,906	)		(6,967	)
Standardized measure of discounted
future net cash flows	$	20,931		$	16,672		$	9,305

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

	Years Ended December 31,
	2011			2010			2009
Beginning of year	$	16,672		$	9,305		$	11,547
Sale of oil and gas reserves		(7,429	)		-			-
Net change in prices and production costs		791			9,435			(4,890	)
New field discoveries and extensions, net of future
production costs		18,769			9,068			3,471
Sales of oil and gas produced, net of production costs		(7,723	)		(7,084	)		(5,114	)
Net change due to revisions in quantity estimates		(1,739	)		(1,369	)		(347	)
Accretion of discount		1,678			1,072			1,242
Production rate changes and other		2,204			213			2,189
Net change in income taxes		(2,292	)		(3,968	)		1,207
End of year	$	20,931		$	16,672		$	9,305

Results of Operations for Oil and Gas Producing Activities -

The results of oil and gas producing activities, excluding corporate overhead and interest costs, are as follows (in thousands):

	Years Ended December 31,
	2011			2010			2009
Revenues	$	14,060		$	11,021		$	8,650
Costs and expenses -
Production		(6,337	)		(3,937	)		(3,536	)
Producing property impairment		(7,105	)		(946	)		(1,350	)
Exploration		(9,166	)		(3,233	)		(3,735	)
Depreciation, depletion and amortization		(8,246	)		(4,662	)		(3,654	)
Operating income (loss) before income taxes		(16,794	)		(1,757	)		(3,625	)
Income tax (expense) benefit		5,878			615			1,268
Operating income (loss)	$	(10,916	)	$	(1,142	)	$	(2,357	)

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Document And Entity Information (USD $)	12 Months Ended
	Dec. 31, 2011	Mar. 10, 2012	Jun. 30, 2011
Entity Registrant Name	ADAMS RESOURCES & ENERGY, INC.
Entity Central Index Key	0000002178
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float			$ 52,992,199
Entity Common Stock, Shares Outstanding		4,217,596
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2011

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CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
REVENUES:
Marketing	$ 3,136,838	$ 2,144,082	$ 1,889,583
Transportation	63,501	56,867	44,895
Oil and natural gas	14,060	11,021	8,650
Total Revenues	3,214,399	2,211,970	1,943,128
COSTS AND EXPENSES:
Marketing	3,082,140	2,124,491	1,869,400
Transportation	51,068	45,956	38,797
Oil and gas operations	22,608	8,116	8,621
Oil and gas property sale (gain)	(2,923)	0	0
General and administrative	9,713	9,044	9,589
Depreciation, depletion and amortization	16,260	11,817	10,320
Total costs expense	3,178,866	2,199,424	1,936,727
Operating Earnings	35,533	12,546	6,401
Other Income (Expense):
Interest income	237	191	125
Interest expense	(8)	(36)	(25)
Earnings before income taxes	35,762	12,701	6,501
Income Tax (Provision) Benefit:
Current	(5,523)	(371)	(1,280)
Deferred	(7,308)	(3,699)	(1,072)
Income Tax (Provision) benefit	(12,831)	(4,070)	(2,352)
Net Earnings	$ 22,931	$ 8,631	$ 4,149
EARNINGS PER SHARE:
Basic and diluted net earnings per share (in dollars per share)	$ 5.44	$ 2.05	$ 0.98

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies [Abstract]

Commitments and Contingencies

(6)  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.  In addition, the Company has entered into certain lease and terminal access contracts in order to provide tank storage and dock access for its crude oil marketing business.  Such contracts require certain minimum monthly payments for the term of the contracts.  Rental expense for the years ended December 31, 2011, 2010, and 2009 was $7,621,000, $5,870,000 and $6,898,000, respectively.  At December 31, 2011, commitments under long-term non-cancelable operating leases and terminal arrangements for the next five years and thereafter are payable as follows:   2012 - $3,059,000; 2013 - $2,148,000; 2014 - $1,468,000; 2015 - $1,201,000; 2016 $1,181,000 and $1,602,000 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.  The Company has appropriately recognized estimated expenses and liabilities related to these policies for losses incurred but not reported to the Company or its insurance carrier of $1,285,000 and $2,125,911 as of December 31, 2011 and 2010, respectively.

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.

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Transactions with Affiliates

12 Months Ended

Dec. 31, 2011

Transactions with Affiliates [Abstract]

Transactions with Affiliates

(5)  Transactions with Affiliates

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 2011 and 2010, the Company's investment commitments totaled approximately $24.6 million and $11.7 million, respectively, in those oil and gas projects where a related party was also participating in such investments.  As of December 31, 2011 and 2010, the Company owed a combined net total of $58,000 and $9,000, 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 $145,000, $160,000 and $150,000 for the years ended December 31, 2011, 2010, and 2009, 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 administrative services.  For the years ended December 31, 2011, 2010 and 2009, the affiliated entities charged the Company $42,000, $43,000 and $62,000, respectively, of expense reimbursement and the Company charged the affiliates $118,000, $117,000 and $127,000, respectively, for such expense reimbursements. In January 2012, the company relocated its primary office lease space to a building operated by an affiliated entity.  Estimated annual rental expense, including pro-rata building operating expense are $480,000 per year under a seven year lease term.  The lease rental rate was determined by an independent appraisal.

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Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2011

Quarterly Financial Data (Unaudited) [Abstract]

Quarterly Financial Data (Unaudited)

(9)  Quarterly Financial Data (Unaudited) -

Selected quarterly financial data and earnings per share of the Company are presented below for the years ended December 31, 2011 and 2010 (in thousands, except per share data):

						Net Earnings				Dividends
				Operating				Per				Per
		Revenues		Earnings (loss)		Amount		Share		Amount		Share
	2011 -
March 31		$	697,188	$	8,475	$	5,583	$	1.32	$	-	$	-
June 30			824,210		5,807		3,589		.85		-		-
September 30			801,690		13,576		9,026		2.14		-		-
December 31			891,311		7,675		4,733		1.13		2,404		.57
Total		$	3,214,399	$	35,533	$	22,931	$	5.44	$	2,404	$	.57
	2010 -
March 31		$	533,785	$	2,575	$	1,794	$	.43	$	-	$	-
June 30			547,141		2,656		1,685		.39		-		-
September 30			502,455		4,021		2,762		.66		-		-
December 31			628,589		3,294		2,390		.57		2,277		.54
Total		$	2,211,970	$	12,546	$	8,631	$	2.05	$	2,277	$	.54

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.

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Guarantees

12 Months Ended

Dec. 31, 2011

Guarantees [Abstract]

Guarantees

(7)  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, 2011 are as follows (in thousands):

	2012		2013		2014		Thereafter		Total
Equipment residual values	$	72	$	216	$	-	$	-	$	288

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, 2011, the maximum amount of such potential obligation is approximately $1,712,000.  Management of the Company believes its customers will adhere to their branding obligations and no such refunds will result.  In addition, effective February 27, 2012 this obligation was assumed by the purchaser of the Company's refined products contracts.  See also Note (10) of Notes to Financial Statements.

Presently, neither Adams Resources & Energy, Inc. (“ARE”) nor any of its subsidiaries has any other types of guarantees outstanding that require liability recognition.

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, 2011, parental guaranteed obligations are approximately as follows (in thousands):

	2012		2013		2014		2015		Thereafter		Total
Lease payments	$	56	$	47	$	-		-		-		103
Equipment residual values		72		216		-		-		-		288
Commodity purchases		68,815		-		-		-		-		68,815
Letters of credit		38,925		-		-		-		-		38,925
	$	107,868	$	263	$	-	$	-	$	-	$	108,131

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Segment Reporting

12 Months Ended

Dec. 31, 2011

Segment Reporting [Abstract]

Segment Reporting

(8)  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, 2011-
Marketing
- Crude oil	$	2,961,176	$	49,237		$	3,724	$	13,554
- Natural gas		6,251		2,147			3		64
- Refined products		169,411		(788	)		375		66
Marketing Total		3,136,838		50,596			4,102		13,684
Transportation		63,501		8,521			3,912		14,118
Oil and gas		14,060		(13,871	)		8,246		24,580
	$	3,214,399	$	45,246		$	16,260	$	52,382
Year ended December 31, 2010-
Marketing
- Crude oil	$	2,005,301	$	13,530		$	2,320	$	6,051
- Natural gas		10,592		3,073			44		115
- Refined products		128,189		121			503		146
Marketing Total		2,144,082		16,724			2,867		6,312
Transportation		56,867		6,623			4,288		4,410
Oil and gas		11,021		(1,757	)		4,662		11,699
	$	2,211,970	$	21,590		$	11,817	$	22,421
Year ended December 31, 2009-
Marketing
- Crude oil	$	1,770,600	$	15,404		$	1,997	$	1,947
- Natural gas		14,232		2,749			166		-
- Refined products		104,751		(666	)		533		177
Marketing Total		1,889,583		17,487			2,696		2,124
Transportation		44,895		2,128			3,970		7,524
Oil and gas		8,650		(3,625	)		3,654		12,742
	$	1,943,128	$	15,990		$	10,320	$	22,390

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,
	2011			2010			2009
Segment operating earnings	$	45,246		$	21,590		$	15,990
- General and administrative expenses		(9,713	)		(9,044	)		(9,589	)
Operating earnings		35,533			12,546			6,401
- Interest income		237			191			125
- Interest expense		(8	)		(36	)		(25	)
Earnings before income taxes	$	35,762		$	12,701		$	6,501

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

	Years Ended December 31,
	2011		2010
Marketing
- Crude oil	$	253,817	$	184,299
- Natural gas		12,246		19,948
- Refined products		11,700		11,594
Marketing Total		277,763		215,841
Transportation		27,221		17,378
Oil and gas		29,105		32,563
Other		44,751		35,523
	$	378,840	$	301,305

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.

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Subsequent Event

12 Months Ended

Dec. 31, 2011

Subsequent Event [Abstract]

Subsequent Event

(10)  Subsequent Event

On February 27, 2012, the Company sold certain equipment, inventory and contracts associated with its refined products marketing segment.  The Company received proceeds of $2 million plus the fair market value of its inventory and transferred title to its inventory, transportation equipment and other miscellaneous net assets.  The current gain is estimated to be approximately $1 million, subject to final post-closing adjustments.

Accounts receivable and accounts payable as of the transaction date that are associated with this segment were retained and will continue to be satisfied in the ordinary course of business.  The Company has discontinued its refined products marketing operation and has agreed to a three year non-compete agreement in connection with this matter. 

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CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (USD $) In Thousands, unless otherwise specified	Common Stock [Member]	Contributed Capital [Member]	Retained Earnings [Member]	Total
BALANCE at Dec. 31, 2008	$ 422	$ 11,693	$ 69,646	$ 81,761
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net earnings	0	0	4,149	4,149
Dividends paid on common stock	0	0	(2,109)	(2,109)
BALANCE at Dec. 31, 2009	422	11,693	71,686	83,801
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net earnings	0	0	8,631	8,631
Dividends paid on common stock	0	0	(2,277)	(2,277)
BALANCE at Dec. 31, 2010	422	11,693	78,040	90,155
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net earnings	0	0	22,931	22,931
Dividends paid on common stock	0	0	(2,404)	(2,404)
BALANCE at Dec. 31, 2011	$ 422	$ 11,693	$ 98,567	$ 110,682

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Employee Benefits

12 Months Ended

Dec. 31, 2011

Employee Benefits [Abstract]

Employee Benefits

(4)  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 $597,000, $565,000 and $578,000 in 2011, 2010 and 2009, respectively. No other pension or retirement plans are maintained by the Company.