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 chart er)

Delaware 74-1753147 17 South Briar Hollow Lane Ste 100 77027

Houston, Texas
(State of Incorporation) (I.R.S. Employer Identific ation 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 A mex

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 no t required to file reports pursuant to Section 13 o r Section 15(d) of the Exchange Act. YES ____ NO _X_

Indicate by check mark whether the Registrant (1) h as filed all reports required to be filed by Sectio n 13 or 15(d) of the Securities Exchange Act of 1934 during the precedin g 12 months (or for such shorter period that the re gistrant 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 s ubmitted 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 no t contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information state ments incorporated by reference in Part III of this Form 10-K or any amen dment 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 “larg e accelerated filer” and “accelerated filer and sma ller reporting company” in Rule 12b-2 of the Exchange Act. Large accelerated filer ____ Accelerated filer ___

_

Non-accelerated filer _X_ Smaller reporting compan y _____

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-vo ting 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 re ported 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 Meet ing of Stockholders to be held May 16, 2012 are inc orporated by reference into Part III of this report.

### 2 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 und er Federal securities law and regulations. To the extent such statements are not recitations of historical fact, forward-looking statements involve risks and uncert ainties. In particular, statements under the captions (a) Produ ction and Reserve Information, (b) Regulatory Statu s 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) Concentrat ion of Credit Risk, (h) Price Risk Management Activ ities, and (i) Commitments and Contingencies, among others , contain forward-looking statements. Where the Company expresses an expectation or belief regardin g future results or events, such expression is made in good

faith and believed to have a reasonable basis in fa ct. However, there can be no assurance that such e xpectation or belief will actually result or be achieved.

With the uncertainties of forward looking statement s in mind, the reader should consider the risks discussed elsewhere in this report and other docume nts filed by the Company with the Securities and Ex change Commission from time to time and the important fact ors described under “Item 1A. Risk Factors” that co uld cause actual results to differ materially from thos e expressed in any forward-looking statement made b y or on behalf of the Company.

Business Activities

Adams Resources & Energy, Inc. (“ARE”) and its subs idiaries (collectively, the "Company"), are engaged in the business of marketing crude oil, nat ural gas and petroleum products, tank truck transpo rtation of liquid chemicals, and oil and gas exploration and p roduction. Adams Resources & Energy, Inc. is a Del aware corporation organized in 1973. The Company’s headq uarters are located in 23,450 square feet of office space located at 17 South Briar Hollow Lane Suite 100, Ho uston, Texas 77027 and the telephone number of that address is (713) 881-3600. The revenues, operating results and identifiable assets of each industry segment f or the three years ended December 31, 2011 are set forth in Note 8 of Notes to Consolidated Financial Statements in cluded

elsewhere herein.

Marketing Segment Subsidiaries

Gulfmark Energy, Inc. (“Gulfmark”), a subsidiary o f ARE, purchases crude oil and arranges sales and

deliveries to refiners and other customers. Activit y is concentrated primarily onshore in Texas and Lo uisiana with additional operations in Michigan and New Mexico. D uring 2011, Gulfmark purchased approximately 81,600 barrels per day of crude oil at the wellhead or lea se level. Gulfmark also operates 148 tractor-traile r rigs and maintains over 54 pipeline inventory locations or i njection stations. Gulfmark has the ability to bar ge 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 faciliti es in order to access waterborne markets for its pr oducts. Gulfmark delivers physical supplies to refiner cust omers or enters into exchange transactions with thi rd parties when the cost of the exchange is less than the alte rnate cost incurred in transporting or storing the crude oil. During 2011, Gulfmark had sales to four customers t hat comprised 18.2 percent, 15.4 percent, 13.4 perc ent, and 11.3 percent, respectively, of total Company wide r evenues. 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 No tes to
Consolidated Financial Statements.

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Adams Resources Marketing, Ltd. (“ARM”), a subsidi ary of ARE, operates as a wholesale purchaser, distributor and marketer of natural gas. ARM’s foc us is on the purchase of natural gas at the produce r level. During 2011, ARM purchased approximately 208,000 mi llion british thermal units (“mmbtu’s”) of natural gas per day at the wellhead and pipeline pooling points. Bu siness is concentrated among approximately 60 indep endent producers with the primary production areas being t he 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 carr ier pipelines and handling daily volume balancing requi rements as well as risk management services.

Ada Resources, Inc. (“Ada”), a subsidiary of ARE, m arketed branded and unbranded refined petroleum products such as motor fuels and lubricants. In Fe bruary 2012, the Company sold substantially all equ ipment, inventory and contracts associated with this operat ion. The company retained Ada’s former distributio n and warehousing facility located on 5.5 Company-owned a cres in Houston, Texas. See Note (10) of Notes to

Financial Statements for additional discussion.

Operating results are sensitive to a number of fac tors. Such factors include commodity location, gra des of product, individual customer demand for grades or l ocation of product, localized market price structur es, availability of transportation facilities, actual d elivery 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 Mate rials Certificate of Registration issued by the Uni ted States. Department of Transportation (“DOT”). STC operate s 285 truck tractors of which 12 are independent ow neroperator units and maintains 447 tank trailers. In addition, STC maintains truck terminals in Houston , Corpus Christi, and Nederland, Texas as well as Baton Roug e (St. Gabriel), Louisiana and Mobile (Saraland), A labama. Transportation operations are headquartered at a te rminal facility situated on 22 Company-owned acres in Houston, Texas. This property includes maintenance facilities, an office building, tank wash rack fac ilities and a water treatment system. The St. Gabriel, Louisiana terminal is situated on 11.5 Company-owned acres a nd includes an office building, maintenance bays and t ank cleaning facilities.

STC is compliant with International Organization f or 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 eq uipment maintenance. STC’s quality management proc ess is one of its major assets. The practice of using statist ical process control covering safety, on-time perfo rmance and customer satisfaction aids continuous improvement i n all areas of quality service. In addition to its ISO 9001:2000 practices, the American Chemistry Council recognizes STC as a Responsible Care  Partner. Responsible Care Partners serve the chemical indust ry and implement and monitor the seven Codes of Management Practices. The seven codes address comp liance and continuing improvement in (1) Community Awareness and Emergency Response, (2) Pollution Pre vention, (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 nat ural gas properties primarily in Texas and the sout h central region of the United States. AREC’s offices are mai ntained in Houston and the Company holds an interes t in 405 wells of which 41 are Company operated.

Producing Wells--The following table sets forth th e 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, whi le 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 Compan y's gross and net developed and undeveloped acreage as of December 31, 2011. Gross acreage represents the Company’s direct ownership and net acreage repr esents
the sum of the fractional interests owned. The Com pany’s developed acreage is held by current product ion while undeveloped acreage is held by oil and gas leases w ith various remaining terms from six months to thre e years. The Company’s ownership in undeveloped acreage is s ubstantially all in the form of a non-operated mino rity 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 thr ee 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 discou nted future net cash flows calculated at a 10% disc ount rate for the three years ended December 31, 2011, are pr esented 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 petr oleum engineers. The reserve value estimates provi ded at each of December 31, 2011, 2010 and 2009 are based on market prices of $95.85, $76.14 and $58.43 per b arrel for crude oil and $4.69, $5.26 and $4.05 per mcf fo r natural gas, respectively. For 2011 and 2010, su ch 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 req uired by Security and Exchange Commission (“SEC”) regulations. For 2009, the price reflects the mark et price on December 31, 2009. The price reported for natural gas includes the value of associated natural gas li quids.

### 5

Reserve estimates are based on many subjective fact ors. The accuracy of reserve estimates depends on the quantity and quality of geological data, produc tion performance data, and reservoir engineering da ta, the pricing assumptions utilized as well as the skill a nd judgment of petroleum engineers in interpreting such data. The process of estimating reserves requires frequen t revision of estimates as additional information i s made available through drilling, testing, reservoir stud ies and acquiring historical pressure and productio n 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 realis tic assessment of current value or future performance of such prop erties. Such revenue calculations are based on esti mates as to the timing of oil and natural gas production, and t here is no assurance that the actual timing of prod uction will conform to or approximate such estimates. Also, ce rtain assumptions have been made with respect to pr icing. The estimates assume prices will remain constant fr om 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 ot her factors impact the market price for oil and nat ural gas.

The Company's oil and natural gas production for t he 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 Comp any's oil and natural gas division revenues and ear nings

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 authorit ies or agencies of estimated oil and gas reserves. The Company is not obligated to provide any fixed and d eterminable quantities of oil or gas in the future under existing contracts or agreements associated with it s 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 law s, rules and regulations governing the storage, transp ortation, manufacture, use, discharge, release and disposal of product and contaminants into the environment, or o therwise relating to the protection of the environm ent. Presented below is a non-exclusive listing of the e nvironmental laws that potentially impact the Compa ny’s

activities.

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− The Solid Waste Disposal Act, as amended by the Res ource 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 amende d.

− 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 regu lates, among other things, the drilling and operation of oil and natural gas wells, the operati on of oil and gas pipelines, the disposal of oil an d 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 f or civil and/or criminal penalties and/or injunctive relief for violations of the RRC regulations.

Louisiana Office of Conservation--This agency has p rimary statutory responsibility for regulation and conservation of oil, gas, and other natural resourc es 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 e nergy supplies and distribution and (iii) protect public safety an d the State’s environment from oilfield waste, incl uding regulation of underground injection and disposal pr actices.

State and Local Government Regulation--Many states are authorized by the United States Environmental Protection Agency (“EPA”) to enforce regulations pr omulgated under various federal statutes. In addit ion, there

are numerous other state and local authorities that regulate the environment, some of which impose mor e stringent environmental standards than federal laws and regul ations. The penalties for violations of state law vary, but typically include injunctive relief, recovery of da mages for injury to air, water or property and fine s for noncompliance.

Oil and Gas Operations--The Company's oil and gas drilling and production activities are subject to l aws and regulations relating to environmental quality a nd 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, l ow-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 re gulations and industry standards. Environmental com pliance has become more stringent and the Company, from tim e to time, may be required to remediate past practi ces. Management believes that such required remediation in the future, if any, will not have a material adv erse impact on the Company's financial position or results of o perations.

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 permit s for the drilling of wells and regulate the spacing of wells , the prevention of waste, protection of correlativ e rights, the rate of production, prevention and clean-up of pollution and other matters.

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Marketing Operations--The Company's marketing faci lities are subject to a number of state and federal environmental statutes and regulations, including t he regulation of underground fuel storage tanks. W hile the Company has not owned or operated underground tanks for more than 10 years, historically the Company w as an owner and operator of underground storage tanks. T he EPA's Office of Underground Tanks and applicable state laws establish regulations requiring owners or oper ators of underground fuel tanks to demonstrate evid ence of financial responsibility for the costs of correctiv e action and the compensation of third parties for bodily injury and property damage caused by sudden and non-sudden accidental releases arising from operating undergr ound tanks. In addition, the EPA requires the installat ion of leak detection devices and stringent monitor ing of the ongoing condition of underground tanks. Should lea kage develop in an underground tank, the operator i s obligated for clean up costs. During the period wh en the Company operated underground tanks, it secur ed insurance covering both third party liability and c lean up costs.

Transportation Operations--The Company's tank truc k operations are conducted pursuant to authority of the DOT and various state regulatory authorities. The Company's transportation operations must also b e conducted in accordance with various laws relating to pollution and environmental control. Interstate motor carrier operations are subject to safety requiremen ts prescribed by DOT. Matters such as weight and di mension of equipment are also subject to federal and state reg ulations. DOT regulations also require mandatory d rug testing of drivers and require certain tests for alcohol le vels in drivers and other safety personnel. The tr ucking industry is subject to possible regulatory and legislative c hanges such as increasingly stringent environmental regulations or limits on vehicle weight and size. Regulatory c hange may affect the economics of the industry by r equiring changes in operating practices or by changing the d emand for common or contract carrier services or th e cost of providing truckload services. In addition, the Com pany’s tank wash facilities are subject to increasi ngly stringent local, state and federal environmental regulations.

The Company has implemented security procedures for drivers and terminal facilities. Satellite trackin g 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 loca tion. If necessary, the Company’s terminal personn el will notify local law enforcement agencies. In addition , the Company is able to advise a customer of the s tatus 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 Liab ility--The operations and facilities of the Company are subject to numerous federal, state and local en vironmental laws and regulations including those de scribed above, as well as associated permitting and licensi ng requirements. The Company regards compliance wi th applicable environmental regulations as a critical component of its overall operation, and devotes sig nificant 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 r equired under existing environmental laws and regul ations to operate its current business. Management has repor ted 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 appropr iate, implemented operating procedures at each of i ts facilities designed to assure compliance with envir onmental laws and regulation. However, given the na ture of the Company’s business, the Company is subject to envir onmental risks and the possibility remains that the Company's ownership of its facilities and its opera tions and activities could result in civil or crimi nal enforcement and public as well as private actions against the C ompany, which may necessitate or generate mandatory clean up activities, revocation of required permits or licen ses, denial of application for future permits, and/ or significant fines, penalties or damages, any and all of which c ould have a material adverse effect on the Company. At December 31, 2011, the Company is unaware of any un resolved environmental issues for which additional accounting accruals are necessary.

### 8

Employees

At December 31, 2011 the Company employed 780 pers ons, 15 of whom were employed in the exploration and production of oil and gas, 345 in t he marketing of crude oil, natural gas and petroleu m products, 399 in transportation operations, and 21 in adminis trative capacities. None of the Company's employee s are represented by a union. Management believes its em ployee relations are satisfactory.

Federal and State Taxation

The Company is subject to the provisions of the In ternal Revenue Code of 1986, as amended (the “Code”). In accordance with the Code, the Company c omputes its income tax provision based on a 35 perc ent tax rate. The Company's operations are, in large part, conducted within the State of Texas. Texas operat ions are subject to a one-half percent state tax on its reve nues net of cost of goods sold as defined by the st ate. Oil and gas activities are also subject to state and local inco me, 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 sal e of certain assets previously associated with the Company’s refined products marketing segment. Asse ts sold included equipment, tanks and trucks, as we ll as all refined petroleum product inventories and substanti ally all supplier and customer contracts associated with this business segment. With the consummation of this tr ansaction, 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 totale d $2,000,000 plus the market value of inventories. The Company will continue to collect any outstanding accounts r eceivable and satisfy all account payable obligations associa ted with this business. See discussion under “Subs equent
Event” in Note 10 to the Consolidated Financial Sta tements.

Available Information

The Company is required to file periodic reports as well as other information with the Securities and Exchange Commission (“SEC”) within established dead lines. Any document filed with the SEC may be view ed or copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Additiona l 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 furnishi ng such material with the SEC. Additionally, the Company h as adopted and posted on its website a Code of Busi ness Ethics designed to reflect requirements of the Sarb anes-Oxley Act of 2002, NYSE Amex Exchange rules an d other applicable laws, rules and regulations. The C ode of Business Ethics applies to all of the Compan y’s directors, officers and employees. Any amendment t o the Code of Business Ethics will be posted prompt ly on the Company’s website. The information contained on or accessible from the Company’s website does not con stitute a part of this report and is not incorporated by re ference herein. The Company will provide a printed copy of any of these aforementioned documents free of charge up on request by calling ARE at (713)-881-3600 or by w riting

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 m aterially reduce profitability and cash flows.

Potential disruptions in the credit markets and co ncerns about global economic growth could have a significant adverse impact on global financial mark ets and commodity prices. Such factors could contr ibute to a decline in the Company’s stock price and correspond ing market capitalization. Should commodity prices experience a period of rapid decline, future earni ngs 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 increas ed costs associated with issuing commercial paper and/or oth er debt instruments and this, in turn, could advers ely affect the Company’s ability to secure supply and make pro fitable sales.

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

Customer demand for the Company’s products and serv ices is substantially dependent upon the general

economic conditions for the United States which are cyclical in nature. In particular, demand for liq uid chemical truck transportation services is dependent on activ ity within the petrochemical sector of the U. S. ec onomy. Chemical sector demand typically varies with the ho using and auto markets as well as the relative stre ngth of the U. S. dollar to foreign currencies. A relatively s trong U.S. dollar exchange rate tends to suppress e xport 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 cred it from suppliers and other parties. Trade credit arr angements are relied upon as a significant source o f liquidity for capital requirements not satisfied by operating cas h flow.

Should global financial markets and economic condit ions disrupt and reduce stability in general and th e solvency of creditors specifically, the availabilit y of funding from credit markets would be reduced a s many lenders and institutional investors would enact tig hter lending standards, refuse to refinance existin g 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 fo r the Company and its suppliers and customers to ob tain funding.

If the Company is unable to obtain trade or other f orms of credit on reasonable and competitive terms, its ability to continue its marketing and exploration b usinesses, pursue improvements, and continue future growth

will be limited. There is no assurance that the Co mpany will be able to maintain future credit arrang ements on commercially reasonable terms.

The financial soundness of customers could affect t he Company’s business and operating results

Constraints in the financial markets and other macr o-economic challenges that might affect the economy of the United States and other parts of the world c ould cause the Company’s customers to experience ca sh 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 inabi lity of current and/or potential customers to pay f or services may adversely affect the Company’s financial condit ion and results of operations.

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Counterparty credit default could have an adverse e ffect on the Company.

The Company’s revenues are generated under contract s with various counterparties. Results of operatio ns would be adversely affected as a result of non-perf ormance by any of these counterparties of their con tractual obligations under the various contracts. A counter party’s default or non-performance could be caused by factors beyond the Company’s control. A default could occu r as a result of circumstances relating directly to the counterparty, or due to circumstances caused by oth er market participants having a direct or indirect relationship with such counterparty. The Company seeks to mitig ate the risk of default by evaluating the financial strength of potential counterparties; however, despite mitigati on efforts, defaults by counterparties may occur fr om 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 co sts are a significant component of operating expens e. 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, opera ting earnings will generally be adversely affected.

Fluctuations in oil and gas prices could have an ef fect on the Company

.

The Company’s future financial condition, revenues, results of operations and future rate of growth ar e 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. M oreover, oil and natural gas prices depend on facto rs 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 countri es, including the possibility of insurgency or war in such areas;

• economic conditions in the United States and worldw ide;

• governmental regulations and taxation;

• impact of energy conservation efforts;

• the price and availability of alternative fuel sour ces;

• weather conditions;

• availability of local, interstate and intrastate tr ansportation systems; and

• market uncertainty.

Revenues are generated under contracts that must be renegotiated periodically.

Substantially all of the Company’s revenues are ge nerated under contracts which expire periodically o r 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 fluc tuations in oil and gas prices, counterparty ability to pay for or accept the contracted volumes and, most importa ntly, 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 co mpetitive in the marketplace or that the Company wi ll be successful in renegotiating its contracts.

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Anticipated or scheduled volumes will differ from a ctual or delivered volumes.

The Company’s crude oil and natural gas marketing o peration purchases initial production of crude oil and natural gas at the wellhead under contracts req uiring the Company to accept the actual volume prod uced. The resale of such production is generally under contra cts requiring a fixed volume to be delivered. The Company estimates its anticipated supply and matches such s upply estimate for both volume and pricing formulas with

committed sales volumes. Since actual wellhead vo lumes produced will never equal anticipated supply, the Company’s marketing margins may be adversely impact ed. In many instances, any losses resulting from t he difference between actual supply volumes compared t o committed sales volumes must be absorbed by the Company.

Environmental liabilities and environmental regulat ions 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 propertie s.

Environmental laws and regulations govern many asp ects of the Company’s business, such as drilling an d exploration, production, transportation and waste m anagement. Compliance with environmental laws and regulations can require significant costs or may re quire a decrease in production. Moreover, noncompl iance with these laws and regulations could subject the Compan y to significant administrative, civil and/or crimi nal fines and/or penalties.

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

.

Transportation of hazardous materials and the oil a nd gas business involves certain operating hazards such as well blowouts, automobile accidents, explos ions, fires and pollution. Any of these operating hazards could cause serious injuries, fatalities or propert y damage, which could expose the Company to liabili ty. The payment of any of these liabilities could reduce, o r even eliminate, the funds available for explorati on, development, and acquisition, or could result in a loss of the Company’s properties and may even threa ten 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 b roader coverage for sudden and accidental occurrenc es. Insurance might be inadequate to cover all liabilities. More over, from time to time, obtaining insurance for th e Company’s line of business can become difficult and costly. Typically, when insurance cost escalates, the Compa ny may reduce its level of coverage and more risk may be r etained to offset cost increases. If substantial l iability is incurred and damages are not covered by insurance o r exceed policy limits, the Company’s operation and financial condition could be materially adversely a ffected.

Changes in tax laws or regulations could adversely affect the Company

.

The Internal Revenue Service, the United States Tre asury Department and Congress and the states frequently review federal or state income tax legis lation. The Company cannot predict whether, when o r to what extent new federal or state tax laws, regulations, interpretations or rulings will be adopted. Any su ch legislative action may prospectively or retroactively modify ta x treatment and, therefore, may adversely affect ta xation of the Company.

### 12

The Company’s business is subject to changing gover nment regulations

.

Federal, state or local government agencies may imp ose environmental, labor or other regulations that increase costs and/or terminate or suspend operatio ns. The Company’s business is subject to federal, s tate and local laws and regulations. These regulations rela te to, among other things, the exploration, develop ment, production and transportation of oil and natural ga s. Existing laws and regulations could be changed, and any changes could increase costs of compliance and cost s of operations.

Several proposals are before the U.S. Congress that , if implemented, would either prohibit the practic e of hydraulic fracturing or subject the process to regu lation under the Safe Drinking Water Act. The Com pany routinely participates in wells where fracturing te chniques 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 hyd raulic fracturing, any new federal restrictions could resu lt in increased compliance costs or additional oper ating

restrictions.

Estimating reserves, production and future net cash flow is difficult

.

Estimating oil and natural gas reserves is a comple x process that involves significant interpretations and assumptions. It requires interpretation of technic al data and assumptions relating to economic factor s such as future commodity prices, production costs, severanc e and excise taxes, capital expenditures and remedi al costs, and the assumed effect of governmental regulation. As a result, actual results may differ from the Co mpany’s estimates. Also, the use of a 10 percent discount f actor for reporting purposes, as prescribed by the SEC, may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to w hich the Company’s business is subject. Any significant vari ations from the Company’s valuations could cause th e estimated quantities and net present value of the C ompany’s reserves to differ materially.

The reserve data included in this report is only an estimate. The reader should not assume that the pr esent values referred to in this report represent the cur rent market value of the Company’s estimated oil an d natural gas reserves. The timing of the production and the expe nses from development and production of oil and nat ural gas properties will affect both the timing of actual fu ture net cash flows from the Company’s proved reser ves 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 abi lity to find, develop and acquire additional oil an d natural gas reserves. Without successful acquisiti on or exploration activities, reserves and revenues will decline as a result of current reserves being depleted by p roduction. The successful acquisition, development or exploration of oil and natural gas properties requi res an assessment of recoverable reserves, future o il and natural gas prices and operating costs, potential environme ntal and other liabilities, and other factors. Thes e assessments are necessarily inexact. As a result, the Company m ay not recover the purchase price and/or the develo pment costs of a property from the sale of production fro m the property, or may not recognize an acceptable return from properties acquired. In addition, exploration and d evelopment operations may not result in any increas es in reserves. Exploration or development may be delayed or cancelled as a result of inadequate capital, co mpliance with governmental regulations or price controls or mechanical difficulties. In the future, the cost t o find or acquire additional reserves may become prohibitive.

Revenues are dependent on the ability to successful ly complete drilling activity

.

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

### 13

• 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 expend itures to develop its drilling projects. Such addi tional and unanticipated expenditures could adversely affect t he Company’s financial condition and results of ope rations.

Security issues exist relating to drivers, equipmen t and terminal facilities

The Company transports liquid combustible materials such as gasoline and petrochemicals and such materials may be a target for terrorist attacks. W hile the Company employs a variety of security meas ures to mitigate the risk of such events no assurance can b e 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 admin istrative and civil legal proceedings in the ordina ry course of its business. Moreover, as incidental to operations, the Company sometimes becomes involved in various lawsuits and/or disputes. Lawsuits and oth er 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, th ere 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 op erations could be adversely affected if a judgment, penalty or fine is not fully covered by insurance.

The Company is subject to risks associated with cli mate change.

Potential climate change and costs associated with its impact and efforts to regulate “greenhouse gas” (“GHG’s”) emissions have the potential to affect th e Company’s business including negatively impacting (i) the costs it incurs in providing its products and servi ces, including costs to operate and maintain its fa cilities, install new emission controls on its facilities, acquire al lowances to authorize its GHG emissions, pay any ta xes related to GHG emissions, administer and manage a GHG emiss ions program, pay higher insurance premiums or acce pt greater risk of loss in areas affected by adverse w eather and coastal regions in the event of rising s ea levels, (ii) the demand for and consumption of its products and services (due to change in both costs and weather p atterns), and (iii) the economic health of the regions in whi ch it operates, all of which could have a material adverse effect on the Company’s business, financial condition, res ults of operations and cash flows.

The Company is subject to risks related to cybersec urity.

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

Substantial aspects of the Company’s business depen d on the secure operation of its computer systems and websites. Security breaches could expose the Co mpany to a risk of loss, misuse or interruption of sensitive and critical information and functions, including i ts own proprietary information and that of its cust omers, suppliers and employees and functions that affect t he operation of the business. Such losses could re sult in operational impacts, reputational harm, competitive disadvantage, litigation, regulatory enforcement a ctions, and liability. While the Company devotes substantial re sources to maintaining adequate levels of cybersecu rity, 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, personne l and services to enhance security or to respond to occur rences.

### 14

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 ma y be damaged. Compromises of the Company’s security may result in an interruption of operations, violation of applic able privacy and other laws, significant legal and finan cial 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, t he Company may become involved in various lawsuits and/or disputes. Primarily as an operator of an ex tensive trucking fleet, the Company is a party to m otor vehicle accidents, worker compensation claims and other ite ms of general liability as would be typical for the industry. Management of the Company is presently unaware of a ny claims against the Company that are either outsi de 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

### 15 PART II

Item 5. MARKET FOR THE REGISTRANT'S COMMON STOCK, R ELATED SECURITY HOLDER

MATTERS AND ISSUER REPURCHASE OF EQUITY SECURITIES

The Company's common stock is traded on the NYSE A mex, formerly known as the American Stock Exchange, under the ticker symbol “AE”. The follow ing 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 sha reholders 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 issuan ce under equity compensation plans. The Company made no rep urchases of its stock during 2011 and 2010.

On December 15, 2011, the Company paid an annual c ash dividend of $.57 per common share to common
stockholders of record on December 1, 2011. On Dec ember 15, 2010, the Company paid an annual cash div idend 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.

### 16

Performance Graph

The performance graph shown below was prepared unde r the applicable rules of the SEC based on data supplied by Research Data Group. The purpose of th e graph is to show comparative total stockholder re turns for the Company versus other investment options for a s pecified period of time. The graph was prepared ba sed upon the following assumptions:

1. $100.00 was invested on December 31, 2006 in the Co mpany’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 gra ph below is not necessarily indicative of future pr ice performance.

Dec06 Dec07 Dec08 Dec09 Dec10 Dec11

Adams Resources & Energy, Inc. 100.00 86.99 59.46 7 8.90 89.03 108.97

S&P 500 100.00 105.49 66.46 84.05 96.71 98.75
S&P Integrated Oil & Gas 100.00 129.85 101.56 100.2 5 119.14 136.73 Comparison of Five Year Cumulative Total Return Among Adams Resources & Energy, Inc., S&P 500 Index + S&P 500 Integrated Oil & Gas Index

$0 $100 $200 $300

Dec/06 Dec/07 Dec/08 Dec/09 Dec/10 Dec/11 Adams Resources & En ergy, Inc.

S&P 500

S&P Integrated Oil & Gas

### 17

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 produ cing properties were sold for $6.6 million and $14. 9 million producing net gains of $2.9 million and $12.1 milli on, respectively.

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

### 18

Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FIN ANCIAL CONDITION AND

RESULTS OF OPERATIONS

Results of Operations

- Marketing

Marketing revenues, operating earnings and depreci ation 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 p ooling points.

Comparison 2011 to 2010

Crude oil revenues grew by 47 percent in 2011 due t o both volume and price increases. Average crude o il prices increased 25 percent and crude oil lease lev el volumes improved by 18 percent as shown in the t able 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.

### 19

Crude oil operating earnings increased significantl y in 2011 due to widening unit gross margins. This

result stems from South Texas sourced crude oil sel ling at a discount to world oil prices due to its r elative

abundance in relation to the infrastructure availab le to deliver such oil to market. In addition, dur ing the second quarter of 2011, the Company completed construction of a barge terminal facility at the Port of Victor ia, Texas. This facility allows the Company to increase margin s 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 pric e of crude oil moved from $88 per barrel at the beginnin g of the year to $98 per barrel for December 2011, resulting in inventory liquidation gains totaling $3,021,000. S imilarly, during 2010, crude oil prices rose from t he $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 Com pany 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 tan dem with crude oil prices also has a significant im pact on operating earnings. A relatively low level of d iesel fuel costs during 2009, served to improve com parative operating earnings for such year relative to 2010. Diesel fuel cost were elevated in 2011 due to incr eased prices and an approximate 50 unit expansion of the truck f leet engaged to handle added volumes. The impact o n crude oil operating earnings from inventory liquidation g ains 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 na tural gas purchase costs and thus reflect gross mar gin. As shown above, gross margins were reduced during 2 011 as average field level purchase volumes were of f 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-sha le areas of Texas, Louisiana and the Gulf of Mexico . In addition to volume declines, development of the nat ion’s natural gas infrastructure including more div erse areas of production and expanded pipeline and storage cap acity 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 thir d quarter of 2008. Due to customer slow payment pa tterns, refined product operating earnings were additionall y impacted in 2011 and 2009 when the bad debt provi sion was increased by approximately $947,000 and $560,000, r espectively. As a result of its recent market per formance, in February 2012 the Company sold substantially all contracts, equipment and inventories associated wi th its refined products segment and is completing an order ly wind-down of this business. Cash proceeds from the sale totaled $2 million plus the fair market value of re fined product inventories and the Company will reco rd a gain of approximately $1 million during the first quarter o f 2012.

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

### 20

- 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 tra nsportation segment in both 2011 and 2010 due to increased customer demand. The Company also benefi tted in 2011 from $1.2 million in gains from the sa le of used equipment following the purchase of new truck replacements. The Company’s customers predominatel y consist of the domestic petrochemical industry and demand for such products has substantially recovere d from the slow down occurring in 2009. Serving to improve cu stomer demand was a recovering United States econom y, relatively low natural gas prices and improved expo rt demand for petrochemicals. In addition, during the previous economic downturn, the trucking industry r educed capacity by retiring older units without rep lacement. With demand improvement, industry capacity has been strained allowing rate increases and improved over all profitability. As transportation revenues increase or decrease, operating earnings will typically inc rease 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 c onfigured, operating earnings project at break-even levels when annual revenues average approximately $50 mill ion. Above that level, operating earnings will gro w and

below that level losses result.

Transportation segment depreciation increased for 2 011 and 2010 relative to 2009 as older fully depreciated tractor units were replaced with new mo del year vehicles with a portion of the 2011increas e offset by certain in-service trailers becoming fully deprecia ted during the periods. During 2011 the Company r eplaced 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 t railers were added to the fleet during 2011.

- Oil and Gas

Oil and gas segment revenues and operating earning s 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

### 21

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 s hown in the table below. Volumes improved with the results of recent drilling efforts. Operating earn ings declined due to increased charges for deprecia tion, depletion and producing property impairments as wel l as increased exploration and impairment expenses as shown in the second table below. Depreciation and depletion expense increased in both 2011 and 2010 w ith increased volumes and as the depreciable property b asis grew from capital expenditures. Producing and nonproducing property impairments resulted in 2011 fol lowing 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 a s 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 drill ing of 86 wells with 75 successful and 11 dry holes

. Additionally, the Company had 40 wells in process o n December 31, 2011 with ultimate evaluation antici pated during 2012. Converting natural gas volumes to e quate with crude oil volumes at a ratio of six to o ne, oil and gas production volumes and proved reserve changes s ummarized as follows on an equivalent barrel (Eq. B bls)

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 addition s represented 320 percent and 235 percent, respective ly, of production volumes.

### 22

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

East Texas Project

In 2005, the Company joined with its partners in ac quiring exploration acreage in Nacogdoches and Shelby Counties, Texas. This was subsequently expanded to include acreage in Angelina County, due south of Nacogdoches County. This inve stment 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 w ith 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 64,0 00 gross acres are now held by production with 11,700 additional acres under option to earn t hrough drilling. In-field development of this property will resume when justified by higher natur al gas prices.

West Texas Project

In 2008, the Company participated with an approxima te two percent working interest in the acquisition of approximately 49,015 acres located i n Irion and Crockett Counties, Texas for the purpose of developing the Wolfcamp shale. An aggres sive horizontal drilling program is now underway. A total of 54 wells have been drilled wi th 38 wells on production and 15 wells being completed. Drilling is expected to accelerate in 2 012 with 72 wells scheduled to spud. Production from the Wolfcamp in this area is oil-ri ch, 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 Fa yette and Lavaca Counties, Texas. The first core well has been drilled and indications are posi tive with petrochemical data showing the project is on the gas condensate window. Drill ing 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 regio n of Texas. Proceeds from the sale totaled $6.2 mi llion and the pre-tax gain from this transaction totaled $2,708,0 00. Total proved reserves sold were approximately 26,000 barrels of crude oil and 2,148,000 mcf of natural g as. 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 Compan y’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 porti on of its interest in certain non-producing oil and gas properties located in West Texas. Total proceeds from the sal e were $329,000 and the Company recorded a $125,000 gain

from this transaction. Proceeds from the sales wer e used for general working capital purposes and the Company is continuing with oil and gas exploration operatio ns in the vicinity of the properties sold. In Octo ber 2011, the Company sold an interest in certain non-producing p roperties for $90,000 in proceeds and gain.

### 23

- General and administrative, interest income and inc ome 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 followi ng 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 variati ons are consistent with taxable income in the respe ctive accounting periods.

- Outlook

The short-term outlook presumes continued volume an d margin strength within the crude oil marketing operation. Industry competitors and Company suppli ers 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 midterm time horizon (3 - 6 months from current date) management anticipates crude oil marketing margins will return to their approximate historical levels. Tra nsportation results slowed in late 2011 but general ly look to be stable for 2012. Within the oil and gas segment, d eclining 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 pr ices, the recurrence of property impairment charges is unlike ly in 2012. In contrast, should recent escalation in diesel fuel costs continue, 2012 marketing and transportation e arnings could be adversely affected to some extent.

The Company has the following major objectives for 2012:

- Maintain marketing operating earnings at the $28 mi llion 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 mil lion 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 o f 2011, 2010 and 2009, respectively. As of Decembe r 31, 2011 and 2010, the Company had no bank debt or othe r 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 liabiliti es, 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 wi th oil and gas exploration and production activities. For 2012, t he Company anticipates expending an additional appr oximately $19 million on oil and gas development and explorat ion projects. In addition, approximately $17 milli on will be expended during 2012 for the purchase of 167 truck- tractors for the transportation segment and approxi mately $5.3 million will be expended for the purchase of 3 1 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 projec ts will be from operating cash flow and available w orking capital. Within certain constraints, the proposed projects can be delayed or cancelled should funding become

unavailable.

### 24

From time to time, the Company may make cash prepay ments to certain suppliers of crude oil and natural gas for the Company’s marketing operations. Such p repayments totaled $6,521,000 as of December 31, 20 11 and such amounts will be recouped and advanced from mon th to month as the suppliers deliver product to the Company. The Company also requires certain counter parties 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 st and-by letter of credit facility with Wells Fargo B ank to provide for the issuance of up to $60 million in st and-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 enab les the Company to avoid posting cash collateral when procu ring crude oil and natural gas supply. As of Decem ber 31, 2011, letters of credit outstanding totaled $38.9 m illion. Management believes current cash balances, together with expected cash generated from future operations , and the ease of financing truck and trailer addit ions through leasing arrangements (should the need arise) will b e sufficient to meet short-term and long-term li qu idity needs.

The Company utilizes cash from operations to make d iscretionary investments in its oil and natural gas exploration, marketing and transportation businesse s, 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 stor age tank terminal arrangements and office lease spa ce, the Company’s future commitments and planned investment s 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 increase s or decreases in liquidity is earnings from operat ions and such earnings are dependent on the success of f uture operations (see Item 1A. Risk Factors in this annual report of Form 10-K).

Off-balance Sheet Arrangements

The Company maintains certain operating lease arra ngements primarily with independent truck owneroperators in order to provide truck-tractor equipme nt 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 orde r to provide tank storage and dock access for its c rude oil marketing business. Such contracts require certain minimum monthly payments for the term of the contr acts. All operating lease commitments qualify for off-bal ance 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 Dece mber 31, 2011, rental commitments under long-term non-ca ncelable 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 therea fter.



### Contractual Cash Obligations

The Company has no capital lease obligations. The Company has entered into certain operating lease arrangements and terminal access agreements for tan kage, truck-tractors, trailers and office space. A summary of the payment periods for contractual cash obligat ions 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

### 25

In addition to its lease financing obligations, the Company is also committed to purchase certain quantities of crude oil and natural gas in connecti on with its marketing activities. Such commodity purchase obligations are the basis for commodity sa les, which generate the cash flow necessary to meet such purchase obligations. Approximate commodity p urchase 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 o f insurance enters into periods of severe cost incr eases. In the past, during such cyclical periods, the Comp any has seen costs escalate to the point where desi red 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 employ ees. During each of 2011, 2010 and 2009, insurance costs were consistent with activity and totaled $11.2 mi llion, $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, a ny increase will need to be absorbed by existing operations.

Competition

In all phases of its operations, the Company encou nters strong competition from a number of entities. Many of these competitors possess financial resourc es substantially in excess of those of the Company. The Company faces competition principally in establishi ng 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 prope rties. The Company's marketing division competes with major oi l companies and other large industrial concerns tha t own or control significant refining and marketing faciliti es. These major oil companies may offer their prod ucts 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 significa nt fluctuations in prices for crude oil and natural gas. As a resul t, 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 acquisiti on costs
and sales realization.

Critical Accounting Policies and Use of Estimates

Fair Value Accounting

The Company enters into certain forward commodity c ontracts 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. Cha nges in fair value are recognized immediately in earnings unless the derivatives qualify for, and the Company elect s, cash flow hedge accounting. The Company had no contract s designated for hedge accounting during 2011, 2010 and

2009.

The Company utilizes a market approach to valuing i ts commodity contracts. On a contract by contract, forward month by forward month basis, the Company o btains observable market data for valuing its contr acts. Such contracts typically have durations that are le ss than 18 months. As of December 31, 2011, all of the Company’s market value measurements were based on e ither quoted prices in active markets (Level 1 inpu ts) or from inputs based on observable market data (Level 2 inputs). See discussion under “Fair Value Measure ments”

in Note 1 to the Consolidated Financial Statements.

### 26

The Company’s fair value contracts give rise to mar ket risk, which represents the potential loss that may result from a change in the market value of a parti cular commitment. The Company monitors and manages its exposure to market risk to ensure compliance with t he Company’s risk management policies. Such polici es are regularly assessed to ensure their appropriateness given management’s objectives, strategies and curre nt market

conditions.

Trade Accounts

Accounts receivable and accounts payable typically represent the most significant assets and liabilit ies of the Company. Particularly within the Company’s ene rgy marketing, oil and gas exploration, and product ion operations, there is a high degree of interdependen ce with and reliance upon third parties (including transaction counterparties) to provide adequate information for the proper recording of amounts receivable or paya ble. Substantially all such third parties are larger fir ms providing the Company with the source documents for recording trade activity. It is commonplace for th ese entities to retroactively adjust or correct suc h documents. This typically requires the Company to absorb, bene fit from, or pass along such corrections to another third party.

Due to the volume of and complexity of transaction s and the high degree of interdependence with third parties, this is a difficult area to control and ma nage. The Company manages this process by particip ating in a monthly settlement process with each of its counter parties. Ongoing account balances are monitored mo nthly and the Company attempts to gain the cooperation of suc h counterparties to reconcile outstanding balances. The Company also places great emphasis on collecting ca sh balances due and paying only bonafide and proper ly supported claims. In addition, the Company maintai ns and monitors its bad debt allowance. Neverthele ss a degree of risk remains due to the custom and practi ces of the industry.

Oil and Gas Reserve Estimate

The value of the capitalized cost of oil and natur al gas exploration and production related assets ar e dependent on underlying oil and natural gas reserve estimates. Reserve estimates are based on many su bjective factors. The accuracy of reserve estimates depends on the quantity and quality of geological data, pr oduction performance data and reservoir engineering data, th e pricing assumptions utilized as well as the skill and judgment of petroleum engineers in interpreting suc h data. The process of estimating reserves require s frequent revision of estimates (usually on an annual basis) as additional information becomes available. Calcul ations of estimated future oil and natural gas revenues are a lso based on estimates of the timing of oil and nat ural gas production, and there are no assurances that the ac tual timing of production will conform to or approx imate such estimates. Also, certain assumptions must be made w ith respect to pricing. The Company’s estimates as sume prices will remain constant from the date of the en gineer’s estimates, except for changes reflected un der natural gas sales contracts. There can be no assurance tha t actual future prices will not vary as industry co nditions, governmental regulation, political conditions, econ omic conditions, weather conditions, market uncerta inty and other factors impact the market price for oil and n atural gas.

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

### 27

Contingencies

From time to time as incident to its operations, t he Company becomes involved in various accidents, lawsuits and/or disputes. Primarily as an operator of an extensive trucking fleet, the Company is a p arty to motor vehicle accidents, worker compensation claims or ot her items of general liability as are typical for t he industry. In addition, the Company has extensive operations that must comply with a wide variety of tax laws, envir onmental laws and labor laws, among others. Should an incid ent occur, management evaluates the claim based on its nature, the facts and circumstances and the applica bility of insurance coverage. To the extent manage ment believes that such event may impact the financial c ondition of the Company, management will estimate t he monetary value of the claim and make appropriate ac cruals or disclosure as provided in the appropriate accounting literature guidelines.

Revenue Recognition

The Company’s crude oil, natural gas and refined p roducts marketing customers are invoiced daily or monthly based on contractually agreed upon terms. Revenue is recognized in the month in which the phy sical product is delivered to the customer. Where requir ed, the Company also recognizes fair value or mark- to-market gains and losses related to its commodity activitie s. 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 Com pany’s interests in producing wells is recognized a s title and physical possession of the oil and natural gas pass es 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 Re serve Estimations and Disclosures” (ASU No. 2010- 03). This update aligns the current oil and gas re serve estimation and disclosure requirements of the Extractive Industries – Oil and Gas topic of the ASC (ASC Topi c 932) with the changes required by the SEC final r ule, “Modernization of Oil and Gas Reporting,” as discus sed 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 int ended to be upgraded into synthetic oil or gas, ame nds the definition of proved oil and gas reserves to requir e 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is use d in estimating proved oil and gas quantities and p rovides guidance on geographic area with respect to disclos ure of information about significant reserves. ASU No. 2010- 03 must be applied prospectively as a change in acc ounting principle that is inseparable from a change in accounting estimate. The Company adopted ASU No. 2 010-03 effective December 31, 2009.

In May 2011, the FASB issued ASU 2011-04, which fur ther amends the Fair Value Measurements and Disclosures topic of the Accounting Standards Codif ication. Among other provisions, ASU 2011-04 expan ds and modifies certain principles and requirements for me asuring fair value and disclosing fair value measur ement

information. ASU 2011-04 is effective for interim and fiscal periods beginning after December 15, 201 1. The adoption of ASU 2011-04 is not expected to have a m aterial impact on the Company’s financial statement s, but may result in additional disclosures regarding fair value measurements.

In December 2011, the FASB issued FASB Accounting S tandards Update (ASU) 2011-11. This update requires additional disclosures about an entity’s r ight of setoff and related arrangements associated with its financial and derivative instruments. The ASU requ ires a tabular presentation that reflects the gross , net and

setoff amounts associated with such assets and liab ilities among other requirements. The expanded dis closure requirements are effective for the annual reporting periods beginning on January 1, 2013. The adoptio n of ASU 2011-11 is not expected to result in significant ad ditional disclosures.

### 28

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



### Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Interest Rate Risk

The Company had no long-term debt outstanding at De cember 31, 2011 and 2010. A hypothetical ten percent adverse change in the floating rate would n ot have a material effect on the Company’s results of operations for the fiscal year ended December 31, 2 011.

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 pri marily driven by the prevailing spot prices applica ble to oil and gas. Commodity price risk in the Company’s marketi ng operations represents the potential loss that ma y 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 o f 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 C ompany locks in a separate matching price support c ontract with a third party in order to minimize the risk of these financial instruments. Substantially all fo rward contracts fall within a six-month to eighteen-month term with no contracts extending longer than two years in du ration.

Certain forward contracts are recorded at fair valu e, depending on management’s assessments of numerous accounting standards and positions that co mply 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 discussi on under

“Fair Value Measurements” in Note 1 to the Consolid ated Financial Statements.

Historically, prices received for oil and natural g as sales have been volatile and unpredictable with price volatility expected to continue. From January 1, 2 010 through December 31, 2011 natural gas price rea lizations ranged from a monthly low of $3.42 per mmbtu to a m onthly high of $5.80 per mmbtu. Crude oil prices r anged 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 chang es in volume levels, would have reduced earnings by appro ximately $3,252,000 and $2,393,000 for the comparat ive years ended December 31, 2011 and 2010, respectivel y.

### 29

ITEM 8. FINANCIAL STATEMENTS

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS

Page

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 30

FINANCIAL STATEMENTS:

Consolidated Balance Sheets as of December 31, 2011 and 2010 31

Consolidated Statements of Operations for the Years Ended December 31, 2011, 2010 and 2009 32

Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2011, 2010 and 2009 33

Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009 34

Notes to Consolidated Financial Statements 35

### 30 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 balan ce sheets of Adams Resources & Energy, Inc. and subsidiaries (the “Company”) as of December 31, 201 1 and 2010, and the related consolidated statements of operations, shareholders’ equity and cash flows for each of the three years in the period ended Decemb er 31, 2011. These financial statements are the responsib ility of the Company’s management. Our responsibil ity is to express an opinion on these financial statements ba sed on our audits.

We conducted our audits in accordance with the stan dards of the Public Company Accounting Oversight Board (United States). Those standards require tha t we plan and perform the audit to obtain reasonabl e 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 int ernal control over financial reporting. Our audits included

consideration of internal control over financial re porting as a basis for designing audit procedures t hat are appropriate in the circumstances, but not for the p urpose of expressing an opinion on the effectivenes s of the Company’s internal control over financial reporting . Accordingly, we express no such opinion. An aud it also includes examining, on a test basis, evidence suppo rting the amounts and disclosures in the financial statements, assessing the accounting principles used and signif icant estimates made by management, as well as eval uating the overall financial statement presentation. We belie ve that our audits provide a reasonable basis for o ur opinion.

In our opinion, such consolidated financial stateme nts present fairly, in all material respects, the f inancial position of Adams Resources & Energy, Inc. and subs idiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for the ea ch of the three years in the period ended December 31, 2011, in conformity with accounting principles generally acc epted in the United States of America.

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

/s/DELOITTE & TOUCHE LLP

Houston, Texas March 22, 2012

### 31 ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands) December 31,

ASSETS 2011 2010

CURRENT ASSETS:
Cash and cash equivalents $ 37,06 6 $ 29,032 Accounts receivable, net of allowance for doubtful accounts of $ 2,205 and $1, 064 , respectively 234,51 5 190,169
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 30 4

, 9 65 246,976

PROPERTY AND EQUIPMENT: Marketing 38,467 25,407 Transportation 54,359 43,131 Oil and gas (successful efforts method) 8 1

, 668 73,011
Other 1,55 3 188

17 6

, 047 141,737

Less

– Accumulated depreciation, depletion and amortizatio n (106,812) (94,148)

69

, 235 47,589

OTHER ASSETS: Oil and gas property held for sale

- 3,389
Deferred income tax asset 4 73 374 Cash deposits and other 4

, 167 2,977 $ 378, 840 $ 301,305
LIABILITIES AND SHAREHOLDERS’ EQUITY

CURRENT LIABILITIES: Accounts payable $ 24 8

, 656 $ 200,763 Accounts payable

– related party 58 9
Fair value contracts 681 1,478
Accrued and other liabil ities 6,1 94 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 1 0

, 4 96 2,762

26 8

, 158 211,150 COMMITMENTS AND CONTINGENCIES (NOTE 6)

SHAREHOLDERS’ EQUITY: Preferred stock, $1.00 par value, 960,000 shares au thorized, none outstanding

- - Common stock, $.10 par value, 7,500,000 shares auth orize d, 4,217,596 issued and outstanding 422 422 Contributed capital 11,693 11,693 Retained earnings 9 8

, 567 78,040 Total shareholders’ equity 11 0

, 682 90,155 $ 3 78

, 840 $ 301,305

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

### 32 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 th ese consolidated financial statements.

### 33 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 $ 78,0 40 $ 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 thes e consolidated financial statements.

### 34 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 cashfrom operating activitiesDepreciation, 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 14,7 49 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 (45,48 7) (34,257) (36,515) Decrease (increase) in inventories (5,598) 669 (1,053) Decrease (increase) in income tax receivable 1,83 6 (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 liabilitie s 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 thes e consolidated financial statements.

### 35 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 a ll intercompany accounts and transactions. The impact on the accompanying financial statements of events occurring after December 31, 2011 has been evaluate d through the date of issuance of these financial s tatements.

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 chemica ls and oil and gas exploration and production. Its primary area of operation is within a 1,000 mile radius of Houst on, 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, investm ents 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 m aintained with major financial institutions and suc h deposits may exceed the amount of federally backed insurance provided. While the Company regularly monitors th e 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 market able securities consisting of investment grade corporate bonds traded in liquid markets. Such bon ds are held for the purpose of investing in liquid funds and are not generally intended to be retained on a long ter m basis. Marketable securities are initially recog nized at acquisition costs inclusive of transaction costs an d are classified as trading securities. In subsequ ent periods

marketable securities are valued at fair value. Ch anges in these fair values are recognized as gains or losses in the accompanying statement of operations under the capt ion “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 le vel sales of crude oil and natural gas comprise in excess of 90 percent of accounts receivable and under industr y practices, such items are “settled” and paid in c ash 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 prima rily from sales of refined petroleum products and trucking se rvices. For this component of receivables, the all owance for

doubtful accounts is determined based on a review o f specific accounts combined with a review of the g eneral status of the aging of all accounts.

### 36

Inventories

Crude oil and petroleum product inventories are car ried at the lower of average cost or market. Petrol eum products inventory includes gasoline, lubricating o ils and other petroleum products purchased for resa le. 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 foll ows (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 i ncurred in connection with major capital expenditur es are capitalized and amortized over the lives of the rel ated assets. When properties are retired or sold, t he related cost and accumulated depreciation, depletion and amortiz ation ("DD&A") is removed from the accounts and any gain or loss is reflected in earnings.

Oil and gas exploration and development expenditure s are accounted for in accordance with the successful efforts method of accounting. Direct co sts of acquiring developed or undeveloped leasehold acreage, including lease bonus, brokerage and other fees, ar e capitalized. Exploratory drilling costs are initi ally capitalized until the properties are evaluated and determined t o be either productive or nonproductive. Such eval uations are made on a quarterly basis. If an exploratory well is determined to be nonproductive, the costs of dri lling the well are charged to expense. Costs incurred to drill and complete development wells, including dry holes, a re capitalized. As of December 31, 2011, the Company had no unevaluated or suspended exploratory drillin g costs.

Depreciation, depletion and amortization of the cos t of proved oil and gas properties is calculated us ing the unit-of-production method. The reserve base us ed to calculate depreciation, depletion and amortiz ation for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed r eserves and proved undeveloped reserves. For lease and well eq uipment, development costs and successful explorati on drilling costs, the reserve base includes only prov ed developed reserves. All other property and equi pment is depreciated using the straight-line method over the estimated average useful lives of three to twenty years.

### 37

The Company reviews its long-lived assets for impa irment whenever there is evidence that the carrying value of such assets may not be recoverable. Any i mpairment recognized is permanent and may not be re stored. Producing oil and gas properties are reviewed on a field-by-field basis. For properties requiring im pairment, the

fair value is estimated based on an internal discou nted cash-flow model. Cash flows are developed bas ed on estimated future production and prices and then dis counted using a market based rate of return consist ent with that used by the Company in evaluating cash flows for ot her assets of a similar nature. For the years ende d December 31, 2011, 2010 and 2009 there were $7,105,000, $946 ,000 and $1,350,000 impairment provisions on produc ing oil and gas properties, respectively.

Fair value measurements for producing oil and gas p roperties that were subject to fair value impairmen t for the years ended December 31, 2011 and 2010 summ arized 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 p roperties 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 rem aining lease term, drilling activity in the area an d the Company’s plans for the property. Accordingly, imp airment provisions on non-producing properties tota ling $7,644,000, $1,277,000 and $2,423,000 were recorded for the years ended December 31, 2011, 2010 and 20 09, respectively. For non-producing properties, impair ments are determined based on management’s knowledg e of current geological evaluations, drilling results an d activity in the area and intent to drill as it re lates to the remaining term of the underlying oil and gas leaseh old interest.

Cash Deposits and Other Assets

The Company has established certain deposits to sup port participation in its liability insurance progr am and remittance of state crude oil severance taxes a nd other state collateral deposits. Insurance coll ateral deposits are invested at the discretion of the Company’s ins urance carrier and such investments primarily consi st of intermediate term federal government bonds and bond s backed by federal agencies. Components of cash d eposits

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 t he Company’s marketing businesses qualify as derivative instruments. Further, all natural gas, as well as certain specifically identified crude oi l purchase and sale contracts, are designated as trading activitie s. From the time of contract origination, such tra ding activity

contracts are marked-to-market and recorded on a ne t revenue basis in the accompanying financial state ments.

### 38

Substantially all crude oil and refined products pu rchase and sale contracts qualify and are designate d as non-trading activities and the Company elects the n ormal 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 recogn ized 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 o bligor for the purchase, establishes the sale price independently with a third party and maintains credit risk associ ated with the sale of the product.

Certain crude oil contracts may be with a single co unterparty to provide for similar quantities of cru de oil to be bought and sold at different locations. Thes e contracts are entered into for a variety of reaso ns, including effecting the transportation of the commodity, to m inimize credit exposure, and/or to meet the competi tive demands of the customer. Such buy/sell arrangement s are reflected on a net revenue basis in the accom panying financial statements. Reporting such crude oil con tracts 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 rela ted revenue is recognized, as the service is provid ed. Oil and gas revenue from the Company’s interests in producing wells is recognized as title and physica l possession of the oil and gas passes to the purchas er.

Letter of Credit Facility

The Company maintains a Credit and Security Agreeme nt with Wells Fargo Bank to provide a $60 million stand-by letter of credit facility to suppo rt the Company’s crude oil and natural gas purchase s within the marketing segment. This facility is collateralized by the eligible accounts receivable within those o perations. Stand-by letters of credit issued totaled $38.9 mil lion and $23.9 million as of December 31, 2011 and 2010, respectively. The issued stand-by letters of credi t are cancelled as the underlying purchase obligati ons 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 th e maintenance of a combined 1.1 to 1.0 current ratio and the maintenance of positive net earnings exclud ing inventory valuation changes, as defined, among othe r restrictions. Management believes the Company is currently in compliance with all such financial cov enants.

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 pr operty and equipment items included in accounts pay able as of period end were $4,070,000 and $2,868,000 as of Dec ember 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 averag e number of shares of common stock and potentially dilutive common stock shares outstanding during the period. The weighted average number of shares outs tanding was 4,217,596 for 2011, 2010 and 2009. There were no potentially dilutive securities during those per iods.

Share-Based Payments

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

### 39

Use of Estimates

The preparation of financial statements in conformi ty with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts o f assets

and liabilities at the date of the financial statem ents and the reported amounts of revenues and expen ses during the reporting period. Actual results could differ from those estimates. Examples of significant estimates used in the accompanying consolidated financial statements incl ude the oil and gas reserve volumes that form the f oundation for (1) calculating depreciation, depletion and amo rtization and (2) deriving cash flow estimates to a ssess impairment triggers or estimated values associated with oil and gas property, revenue accruals, the pr ovision for bad debts, insurance related accruals, income taxes , contingencies and valuation of fair value contrac ts.

Income Taxes

Income taxes are accounted for using the asset and liability method. Under this approach, deferred ta x assets and liabilities are recognized based on anti cipated future tax consequences attributable to dif ferences between financial statement carrying amounts of ass ets 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. Th e Company seeks to make a profit by procuring such co mmodities as they are produced and then delivering such products to the end users or intermediate use marke tplace. As is typical for the industry, in certain cases such transactions are made pursuant to the terms of forw ard month commodity purchase and/or sale contracts. These

contracts meet the definition of a derivative instr ument and therefore, the Company accounts for such contracts at fair value, unless the normal purchase and sale exc eption is applicable. Such underlying contracts ar e standard for the industry and are the governing document for the Company’s crude oil and natural gas wholesale dist ribution businesses. The accounting methodology utilized by the Company for its commodity contracts is further discussed below under the caption “Fair Value Measu rements”.

None of the Company’s derivative instruments have b een designated as hedging instruments and the estimated fair value of forward month commodity con tracts (derivatives) is reflected in the accompanyi ng 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 $ -

### 40

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 wi th creditworthy counterparties or obtains collatera l support for such activities. As of December 31, 20 11 and 2010, the Company was not holding nor had it posted any collateral to support its forward month fair va lue 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 Decembe r 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 f or cash and cash equivalents, accounts receivable a nd accounts payable approximates fair value because of the immediate or short-term maturity of these fina ncial

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

Fair value contracts consist of derivative financia l instruments and are recorded as either an asset o r liability measured at fair value. Changes in fair value are recognized immediately in earnings unles s the derivatives qualify for, and the Company elects, ca sh flow hedge accounting. The Company had no contr acts designated for hedge accounting during any reporti ng 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 hierarc hy of three levels that prioritizes the information used to develop those assumptions. Currently, for all item s presented herein, the Company utilizes a market a pproach to valuing its contracts. On a contract by contract, forward month by forward month basis, the Company o btains 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 su mmarized as

follows: Level 1 – quoted prices in active markets for ident ical assets or liabilities that may be accessed at the

measurement date. Active markets are those in whic h 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 securit ies, the Company utilizes market quotations provided by its primary financial instit ution and for the valuations of derivative financial instruments, the Company utilizes the New York Mercantile Exchange

“NYMEX” for such valuations.

### 41

Level 2 – (a) quoted prices for similar assets or l iabilities 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) observab le 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 Intercontine ntal Exchange “ICE”, published price data and indices, third party price survey da ta and broker provided forward price

statistics.

Level 3 – Unobservable market data inputs for asset s or liabilities.

As of December 31, 2011, the Company’s fair value a ssets and liabilities are summarized and categorize d

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 a ssets and liabilities are summarized and categorize d

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 physica lly 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 Compa ny makes credit valuation adjustments to reflect both its own nonperformance risk and its counterpar ty’s nonperformance risk. When adjusting the fair value of derivative contracts for the effect of nonperforman ce risk, the impact of netting and any applicable c redit enhancements, such as collateral postings, threshol ds, and guarantees are considered. Credit valuatio n 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 20 10, credit valuation adjustments were not significa nt to the overall valuation of the Company’s fair value contr acts. As a result, applicable fair value assets an d liabilities in their entirety are classified in Level 2 of the fai r value hierarchy.

### 42

The following table illustrates the factors impacti ng the change in the net value of the Company’s fai r value contracts for the year ended December 31, 201 1 (in thousands):

Level 1 Level 2 Quoted Prices Observable Total Net Fair Value January 1, $ (118) $ 1,404 $ 1,28 6 - 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 impacti ng the change in the net value of the Company’s fai r value contracts for the year ended December 31, 201 0 (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 r etirement costs associated with certain tangible lo nglived assets. The estimated fair value of asset re tirement 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 depreciat ed over the useful life or the units of production associated w ith the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recogni zed. A summary of the Company’s asset retirement o bligations 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 obli gations, the Company maintains $75,000 in escrow ca sh, which is legally restricted for the potential purpo se 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 Re serve Estimations and Disclosures” (ASU No. 2010- 03). This update aligns the current oil and gas re serve estimation and disclosure requirements of the Extractive Industries – Oil and Gas topic of the ASC (ASC Topi c 932) with the changes required by the SEC final r ule, “Modernization of Oil and Gas Reporting,” as discus sed 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 int ended to be upgraded into synthetic oil or gas, ame nds the definition of proved oil and gas reserves to requir e 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is use d in estimating proved oil and gas quantities and p rovides guidance on geographic area with respect to disclos ure of information about significant reserves. ASU No. 2010- 03 must be applied prospectively as a change in acc ounting principle that is inseparable from a change in accounting estimate. The Company adopted ASU No. 2 010-03 effective December 31, 2009.

In May 2011, the FASB issued ASU 2011-04, which fur ther amends the Fair Value Measurements and Disclosures topic of the Accounting Standards Codif ication. Among other provisions, ASU 2011-04 expan ds and modifies certain principles and requirements for me asuring fair value and disclosing fair value measur ement

information. ASU 2011-04 is effective for interim and fiscal periods beginning after December 15, 201 1. The adoption of ASU 2011-04 is not expected to have a m aterial impact on the Company’s financial statement s, but may result in additional disclosures regarding fair value measurements.

In December 2011, the FASB issued FASB Accounting S tandards Update (ASU) 2011-11. This update requires additional disclosures about an entity’s r ight of setoff and related arrangements associated with its financial and derivative instruments. The ASU requ ires a tabular presentation that reflects the gross , net and

setoff amounts associated with such assets and liab ilities among other requirements. The expanded dis closure requirements are effective for the annual reporting periods beginning on January 1, 2013. The adoptio n of ASU 2011-11 is not expected to result in significant ad ditional disclosures.

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

(2) Income Taxes

The following table shows the components of the Com pany'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 (provisio n)

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) (47 6) (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 be tween the financial statement carrying amounts and the underlying income tax basis in such items. The com ponents of the federal deferred tax asset (liabilit y) 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 ent ity

in its income tax returns must consider the uncerta inty 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 statem ents must satisfy a more-likely-than-not recognition threshol d, assuming that the tax position will be examined by taxing authorities with full knowledge of all relevant inf ormation. As of December 31, 2010, the Company had accrued approximately $27,000 including approximately $8,00 0 of potential interest and penalty, respectively, applicable to certain open and unfiled state tax returns. A r econciliation of the unrecognized tax benefits is a s 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 an d expects final resolution with all states by year- end 2011. As the actual tax payments are made, the acc rual is reduced. The Company has no other unrecogn ized tax benefits. Interest and penalties associated with i ncome tax liabilities are classified as income tax expense.

### 45

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

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 Compa ny would absorb if its customers failed to perform pursuant to contractual terms. Management of credi t risk involves a number of considerations, such as the financial profile of the customer, the value of col lateral held, if any, specific terms and duration o f the contractual agreement, and the customer's sensitivity to econom ic developments. The Company has established vario us procedures to manage credit exposure, including ini tial credit approval, credit limits, and rights of offset. Letters of credit and guarantees are also utilized to limit credit risk. Accounts receivable associated with c rude oil and natural gas marketing activities comprise approxima tely 90 percent of the Company’s total receivables and industry practice requires payment for such sales t o occur within 25 days of the end of the month foll owing a transaction. The Company’s customer mix, credit po licies and the relatively short duration of receiva bles mitigate the uncertainty typically associated with receivabl es management.

The Company’s largest customers consist of large mu ltinational integrated oil companies and utilities. In addition, the Company transacts business with indep endent oil producers, major chemical concerns, crud e oil and natural gas trading companies and a variety of comm ercial energy users. Within this group of customer s the Company generally derives up to 50 percent of its r evenues from two to three large crude oil refining concerns. While the Company has ongoing established relations hips with certain domestic refiners of crude oil, a lternative markets are readily available since the Company sup plies less than one percent of U. S. domestic refin er demand. As a fungible commodity delivered to major Gulf Coa st supply points, the Company’s crude oil sales can be readily delivered to alternative end markets. Mana gement believes that a loss of any of those custome rs where the Company currently derives more than 10 percent of i ts revenues would not have a material adverse effec t on the Company’s operations.

The Company had accounts receivable from two custom ers that comprised 24.5 percent and 21.5 percent, respectively, of total accounts receivable at Decem ber 31, 2011. Four customers comprised 18.2 percen t, 15.4 percent, 13.4 percent, and 11.3 percent, respective ly, 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 percen t, respectively, of total accounts receivable at Decem ber 31, 2010. Five customers comprised 35.8 percen t, 20.2 percent, 17.9 percent, 13 percent and 11 percent, r espectively, of total revenues during 2010. The Co mpany had accounts receivable from three customers that compr ised 17.8 percent, 12.6 percent and 10.8 percent, r espectively of total accounts receivables at December 31, 2009. Three customers comprised 39.4 percent, 17.7 perc ent and 15.7 percent, respectively, of total revenues durin g 2009.

An allowance for doubtful accounts is provided wher e 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 a nd 2010, respectively. As reflected in the table below, dur ing 2011 and 2009 the Company’s provision for bad debt was elevated as a result of deteriorating collectabili ty primarily attributable to diesel fuel sales to the construction industry.

### 46

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

2011 2010 2009 Balance, beginning of year $ 1,064 $ 1,681 $ 1,2 51 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 th e 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, respec tively. 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 ow ners with the Company’s subsidiary, Adams Resources Exploration Corporation. Mr. Adams and such affili ates participate on terms similar to those afforded other nonaffiliated 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 commit ment to participate in such transactions is greater than th e 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 exten t there is excess available. In those instances wh ere 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 individu ally reviewed and approved by the Audit Committee c omprised 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 o il and gas projects where a related party was also participati ng in such investments. As of December 31, 2011 an d 2010, the Company owed a combined net total of $58,000 and $9 ,000, respectively, to these related parties. In c onnection with the operation of certain oil and gas propertie s, the Company also charges such related parties fo r administrative overhead primarily as prescribed by the Council of Petroleum Accountants Society Bullet in 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 i n the normal course of business with other affiliat ed entities including direct cost reimbursement for sh ared phone and administrative services. For the ye ars ended December 31, 2011, 2010 and 2009, the affiliated en tities charged the Company $42,000, $43,000 and $62 ,000, respectively, of expense reimbursement and the Comp any charged the affiliates $118,000, $117,000 and $127,000, respectively, for such expense reimbursem ents. In January 2012, the company relocated its pr imary office lease space to a building operated by an aff iliated entity. Estimated annual rental expense, i ncluding prorata building operating expense are $480,000 per ye ar under a seven year lease term. The lease rental rate was determined by an independent appraisal.

### 47

(6) Commitments and Contingencies

Rental expense primarily results from payments to t ruck 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 arra ngements for tractors, trailers, office space, and other equ ipment and facilities. In addition, the Company ha s entered into

certain lease and terminal access contracts in orde r to provide tank storage and dock access for its c rude oil marketing business. Such contracts require certain minimum monthly payments for the term of the contr acts. Rental expense for the years ended December 31, 201 1, 2010, and 2009 was $7,621,000, $5,870,000 and $6,898,000, respectively. At December 31, 2011, co mmitments under long-term non-cancelable operating leases and terminal arrangements for the next five years a nd thereafter are payable as follows: 2012 - $3,0 59,000; 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 worke rs’ compensation insurance policies, the Company can either receive a return of premium paid or be a ssessed for additional premiums up to pre-establish ed limits. Additionally under the policies in certain instance s the risk of insured losses is shared with a group of similarly situated entities. The Company has appropriately r ecognized estimated expenses and liabilities relate d to these policies for losses incurred but not reported to th e Company or its insurance carrier of $1,285,000 an d $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 ex tensive trucking fleet, the Company is a party to m otor vehicle accidents, worker compensation claims and other ite ms of general liability as would be typical for the industry. Management of the Company is presently unaware of a ny claims against the Company that are either outsi de 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 subsi diaries of the Company may guarantee the lessor a minimum r esidual equipment sales value upon the expiration o f a lease and sale of the underlying equipment. The Co mpany believes performance under these guarantees t o be remote. Aggregate guaranteed residual values for t ractors 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 purcha se and resale of branded motor fuels, the Company h as 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 a ssociated with offering branded motor fuels for sale to the g eneral public. Under the terms of the supply contr acts, the Company and its customers are not obligated to retu rn the price discounts, provided the gasoline servi ce station offering such product for sale remains as a branded station for periods ranging from three to ten year s. The Company has a number of customers and stations oper ating under such arrangements, and the Company’s customers are contractually obligated to remain a b randed dealer for the required periods of time. Sh ould the Company’s customers seek to void such contracts, th e Company would be obligated to return a portion of such discounts received to its suppliers. As of Decembe r 31, 2011, the maximum amount of such potential ob ligation is approximately $1,712,000. Management of the Com pany believes its customers will adhere to their br anding obligations and no such refunds will result. In ad dition, 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 Financia l

Statements.

### 48

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

ARE frequently issues parent guarantees of commitme nts resulting from the ongoing activities of its subsidiary companies. The guarantees generally res ult from subsidiary commodity purchase obligations, subsidiary lease commitments and subsidiary banking transactions. The nature of such items is to guar antee the performance of the subsidiary companies in meeting their respective underlying obligations. Except fo r operating lease commitments and letters of credit, all such u nderlying obligations are recorded on the books of the subsidiary companies and are included in the consol idated financial statements included herein. There fore, no such obligation is recorded again on the books of t he parent. The parent would only be called upon to perform under the guarantee in the event of a payment defau lt by the applicable subsidiary company. In satisf ying such obligations, the parent would first look to the ass ets of the defaulting subsidiary company.

As of December 31, 2011, parental guaranteed obliga tions 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

### 49

(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 chemica ls, and oil and gas exploration and production. In formation concerning the Company's various business activitie s 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 $ 13,5 54 - Natural gas 6,251 2,147 3 64 - Refined products 169,411 (788) 375 66 Marketing Total 3,136,838 50,596 4,102 13,6 84 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 $ 6,05 1 - Natural gas 10,592 3,073 44 115 - Refined products 128,189 121 503 146 Marketing Total 2,144,082 16,724 2,867 6,31 2 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 $ 1,94 7 - Natural gas 14,232 2,749 166 - - Refined products 104,751 (666) 533 177 Marketing Total 1,889,583 17,487 2,696 2,12 4 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 co ntinuing 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

### 50

Identifiable assets by industry segment are as foll ows (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 c ash, 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 ye ars 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 managem ent necessary to a fair statement of the results for th e period presented. All such adjustments are of a normal recurring nature.

(10) Subsequent Event

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

Accounts receivable and accounts payable as of the transaction date that are associated with this segm ent
were retained and will continue to be satisfied in the ordinary course of business. The Company has d iscontinued its refined products marketing operation and has ag reed to a three year non-compete agreement in conne ction

with this matter.

### 51

(11) Oil and Gas Producing Activities (Unaudited)

The Company’s oil and gas exploration and productio n activities are conducted in Texas and the south central region of the United States, primarily alon g 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 Un ited 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 t he Company's proved oil and gas reserves, all locat ed 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 engineerin g data, they are generally less precise than estima tes made in conjunction with financial disclosures. The revisio ns of previous estimates as reflected in the table below result from changes in commodity pricing assumptions and f rom more precise engineering calculations based upo n additional production histories and price changes.

### 52

Proved developed and undeveloped reserves are pres ented 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 reservesBeginning of year 7,794 267 7,248 242 6,4 43 230 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 t he 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 acreag e. During 2010 drilling efforts continued identify ing additional reserve acreage and converting such undeveloped res erves to the developed category. Drilling in 2011 continued to develop the reserve acreage.

The Company has developed internal policies and con trols for estimating and recording oil and gas reserve data. The estimation and recording of prov ed reserves is required to be in compliance with SE C definitions and guidance. The Company assigns responsibility f or 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 estimator s, as defined by Society of Petroleum Engineers’ Standards.

### 53

The Company employs third party petroleum consultan t, Ryder Scott Company, to prepare its oil and gas reserve data estimates as of December 31, 2011, 201 0 and 2009. The firm of Ryder Scott is well recogn ized within the industry for more than 50 years. As pre scribed by the SEC, such proved reserves were estim ated using 12-month average oil and gas prices, based on the f irst-day-of-the-month price for each month in the p eriod, 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 c omplex 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 subj ective process of estimating subsurface accumulatio ns 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 th ereof. As a result, estimates by different enginee rs often vary, sometimes significantly. In addition, physical fac tors such as the results of drilling, testing and p roduction subsequent to the date of an estimate, as well as e conomic factors such as changes in product prices, may justify revision of such estimates. Accordingly, oil and g as quantities ultimately recovered will vary from r eserve 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 presen ted, except in those instances where fixed and dete rminable gas price escalations are included in contracts. The d isclosures 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 acco unt, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in pri ces and costs, a discount factor more representative of the time v alue of money and risks inherent in reserve estimat es. 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) (1 5,969) 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 a rithmetic average of the prices in effect on the fi rst day of the month for each month of the respective twelve month periods as required by Securities & Exchange Commi ssion regulations. The affect of income taxes and discou nting on the standardized measure of discounted fut ure net cash flows is presented as follows (in thousands):

### 54 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 standardize d 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 co sts (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 Act ivities -

The results of oil and gas producing activities, ex cluding 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 (16,7 94) (1,757) (3,625) Income tax (expense) benefit 5,878 615 1,268 Operating income (loss) $ (10,916) $ (1,142) $ (2,357)

### 55

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTAN TS ON ACCOUNTING AND

FINANCIAL DISCLOSURE

None.

Item 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

The Company maintains “disclosure controls and proc edures” (as defined in Rule 13a-15(e) and 15d15(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 re ports that the Company files or submits under the E xchange Act are recorded, processed, summarized and reported wi thin the time periods specified in the Securities a nd Exchange Commission’s rules and forms and is accumu lated and communicated to management, including the Company’s Chief Executive Officer and Chief Financi al Officer, as appropriate, to allow timely discuss ions regarding required disclosure. As of the end of th e period covered by this annual report, an evaluati on was carried out under the supervision and with the participatio n of the Company’s management, including the Compan y’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 r easonable assurance that the disclosure controls an d procedures as of the end of the period covered by this report are effective to ensure that information required t o be disclosed in the Company’s Exchange Act filings is recorded, processed, summarized and reported within the perio ds specified in the Securities and Exchange Commission ’s rules and forms.

Management’s Report on Internal Control Over Financ ial Reporting

Management is responsible for establishing and main taining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Ex change Act. The Company’s internal control over fi nancial reporting is a process designed under the supervisi on of the Company’s Chief Executive Officer and the Chief Financial Officer to provide reasonable assurance r egarding the reliability of financial reporting and the preparation of financial statements for external pu rposes in accordance with accounting principles gen erally accepted in the United States.

Because of its inherent limitations, internal contr ol over financial reporting may not prevent or dete ct misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes i n 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 ove r 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 Treadw ay Commission (COSO). Based on this assessment, management, including the Company’s Chief Executive Officer and Chief Financial Officer, concluded tha t internal control over financial reporting was effec tive 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 publ ic accounting firm regarding internal control over fin ancial reporting. This management’s report was not subject to attestation by an independent registered public acc ounting firm pursuant to the rules of the Securitie s and Exchange Commission that permit the Company to prov ide only management’s report in this annual report.

### 56

This Management’s Report on Internal Control over F inancial Reporting shall not be deemed “filed” for purposes of Section 18 of the Exchange Act or incor porated by reference in any filing under the Securi ties Act of 1933, as amended, or the Exchange Act, except as sh all be expressly set forth by specific reference in such a filing.

Changes in Internal Control over Financial Reportin g.

There have not been any changes in the Company’s in ternal control over financial reporting during the fiscal quarter ended December 31, 2011 that have ma terially affected, or are reasonably likely to mate rially affect, the Company’s internal control over financial repor ting.

Item 9B. OTHER

None.

### 57 PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORAT E GOVERNANCE

The information concerning directors, corporate go vernance and executive officers of the Company is incorporated by reference from the Company’s defini tive Proxy Statement for the Annual Meeting of Shareholders to be held Wednesday, May 16, 2012, un der the heading “Election of Directors” and “Execut ive Officers”, respectively, to be filed with the Commi ssion 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 incorporate d 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 Commi ssion 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 O WNERS AND MANAGEMENT AND

RELATED STOCKHOLDER MATTERS

The information required by Item 12 is incorporate d 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” t o be filed with the Commission not later than 120 d ays after the end of the fiscal year covered by this Form 10- K.

Item 13. CERTAIN RELATIONSHIPS, RELATED PARTY TRANS ACTIONS AND DIRECTOR

INDEPENDENCE

The information required by Item 13 is incorporate d 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 s “Transactions with Related Parties” and “Director I ndependence” to be filed with the Commission not la ter than 120 days after the end of the fiscal year covered b y this Form 10-K.

Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by Item 14 is incorporate d 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 file d with the Commission not later than 120 days after the end of the fiscal year covered by this Form 10-K.

### 58 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 Account ing Firm

Consolidated Balance Sheets as of December 31, 2011 and 2010

Consolidated Statements of Operations for the Y ears 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 Y ears Ended December 31, 2011, 2010 and 2009

Notes to Consolidated Financial Statements

2. All financial schedules have been omitted because t hey 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 (-Fi le No. 1-7908) of the Company for the fiscal year ended December 31, 1987)

3(b) - Bylaws of the Company, as amended (Incorpora ted by reference to Exhibits 3.2 and 3.2.1 of

Amendment No. 1 to the Registration Statement on Fo rm 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 ad d an Article VII, Section 8. Indemnification of

Directors, Officers, Employees and Agents (Incorpor ated by reference to Exhibit 3(c) of the Annual Report on Form 10-K (-File No. 1-7908) of the Compa ny for the fiscal year ended December 31, 1986)

3(d) - Adams Resources & Energy, Inc. and Subsidiar ies’ Code of Ethics (Incorporated by reference to

Exhibit 3(d) of the Annual Report on Form 10-K (-Fi le No. 1-7908) of the Company for the fiscal year ended December 31, 2002)

4(a) - Specimen common stock Certificate (Incorpora ted by reference to Exhibit 4(a) of the Annual

Report on Form 10-K of the Company (-File No. 1-790 8) for the fiscal year ended December 31, 1991)

### 59

4(b) - Credit and Security Agreement between Gulfma rk Energy, Inc., Adams Resources Marketing,

Ltd and Wells Fargo Bank, National Association date d 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. Webste r, 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 b y and between Adams Resources & Energy, Inc. and

Richard B. Abshire effective July 25, 2008 (Incorpo rated 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/Se verance agreement by and between Adams Resources &

Energy, Inc. and Richard B. Abshire effective Decem ber 6, 2011 (Incorporated by reference to Exhibit 10.2 to the Company’s current report on For m 8-K filed on December 6, 2011).

10.1(e)+ - Amendment to Change in Control/Severanc e 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 fi led on December 6, 2011).

10.1(f)+ - Amendment to Employment Agreement of Fra nk T. Webster, President, dated December 6, 2010

by and between Adams Resources & Energy, Inc. and F rank T. Webster (Incorporated by reference to Exhibit 10.1(b) to the Company’s Annual Report o n 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 effecti ve December 6, 2011 (Incorporated by reference to Exhibit 10.4 to the Company’s Form 8-K filed on Dec ember 6, 2011).

10.1(h)+ - Non-Employee Director Change in Contro l Agreement by and between Adams Resources &

Energy, Inc. and Townes G. Pressler, dated effectiv e 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 Dec ember 6, 2011 (Incorporated by reference to Exhibit 10.5 to the Company’s Form 8-K filed on Dec ember 6, 2011)

10.1(j)+ - Standard form Indemnification Agreement between Adams Resources & Energy, Inc. and Officer s

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. Certificatio n Pursuant to 17 CFR 13a-14 (a)/15d-14(a), As

adopted pursuant to Section 302 of the Sarbanes-Oxl ey Act of 2002

### 60

31.2* - Adams Resources & Energy, Inc. Certificatio n Pursuant to 17 CFR 13a-14(a)/15d-14(a), as

adopted pursuant to Section 302 of the Sarbanes-Oxl ey 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 ar rangement

Copies of all agreements defining the rights of ho lders of long-term debt of the Company and its subsidiaries, which agreements authorize amounts no t in excess of 10% of the total consolidated assets of the Company, are not filed herewith but will be furnish ed to the Commission upon request.

### 61 SIGNATURES

Pursuant to the requirements of Section 13 or 15(d ) of the Securities Exchange Act of 1934, the regis trant has duly caused this report to be signed on its beh alf 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 Chairma n of the Board and (Principal Financial Officer) Chief Executive Offic er (Principal Executive Officer)

Date: March 22, 2012

Pursuant to the requirements of the Securities Exch ange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant a nd 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., Dir ector

By /s/ Larry E. Bell By /s/ Townes G. Pressler Larry E. Bell, Director Townes G. Pressler, Directo r

### 62 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 1 0-K of the Company for the fiscal year ended December 31, 1987)

3(b) - Bylaws of the Company, as amended (Incorpora ted 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 ad d an Article VII, Section 8.

Indemnification of Directors, Officers, Employees a nd Agents (Incorporated by reference to Exhibit 3(c) of the Annual Report on Form 10-K of t he Company for the fiscal year ended December 31, 1986)

3(d) - Adams Resources & Energy, Inc. and Subsidiar ies’ Code of Ethics (Incorporated by

reference to Exhibit 3(d) of the Annual Report on F orm 10-K of the Company for the fiscal year ended December 31, 2002)

4(a) - Specimen common stock Certificate (Incorpora ted by reference to Exhibit 4(a) of the

Annual Report on Form 10-K of the Company for the f iscal year ended December 31, 1991)

4(b) - Credit and Security Agreement between Gulfma rk Energy, Inc., Adams Resources

Marketing, Ltd and Wells Fargo Bank, National Assoc iation dated August 27, 2010 (Incorporated by reference to Exhibit 4(b) of the Q uarterly 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)+ 

### - Employment agreement of Frank T. Webster, Presid ent, 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 Quarterl y 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 Fran k T. Webster effective December 6, 2011. (Incorporated by reference to Ex hibit 10.1 to the Company’s Form 8-K filed in December 6, 2011).

- Change in Control/Severance agreement by and bet ween 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 a greement by and between Adams Resources & Energy, Inc. and Richard B. Abshire eff ective December 6, 2011. (Incorporated by reference to Exhibit 10.2 to the C ompany’s current report on Form 8- K filed on December 6, 2011).

- Amendment to Change in Control/Severance agreeme nt 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 curre nt report on Form 8-K filed on December 6, 2011)

### 63

10.1(f)+

10.1(g)+

10.1(h)+

10.1(i)+

10.1(j)+

10.1(k)*+ 

### - Amendment to Employment Agreement of Frank T. W ebster, President, dated

December 6, 2010 by and between Adams Resources & E nergy, 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 Agreeme nt by and between Adams Resources & Energy, Inc. and E. C. Reinauer, Jr., d ated effective December 6, 2011 (Incorporated by reference to Exhibit 10.4 to the C ompany’s Form 8-K filed on December 6, 2011).

- Non-Employee Director Change in Control Agree ment by and between Adams Resources & Energy, Inc. and Townes G. Pressl er, 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 Agreemen t by and between Adams Resources & Energy, Inc. and Larry E. Bell, d ated effective December 6, 2011 (Incorporated by reference to Exhibit 10.5 to the C ompany’s Form 8-K filed on December 6, 2011)

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

- Change in Control/Severance agreement by and betw een Adams Resources & Energy, Inc. and Sharon Davis (nee Copeland) effect ive 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

### 64 Exhibit 10.1(k)

CHANGE IN CONTROL/SEVERANCE AGREEMENT

THIS AGREEMENT, dated September 20, 2008, is made b y 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 s tockholders; 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 o f members of the Company’s management, including the Key Employee, to their assigned duties without distraction in the face of potentially disturbing c ircumstances;

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

Defined Terms. The definitions of capitalized term s used in this Agreement are provided in the

last Section hereof.

Term of Agreement. The Term of this Agreement shal l commence on September 20, 2008 (the “Effective Date”) and shall continue in effect thro ugh 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.

Company’s Covenants Summarized. In order to induce the Key Employee to remain in the employ of the Company, the Company agrees, under th e conditions described herein, to pay the Key Employee the Severance Payment described herein. N o Severance Payment shall be payable under this Agreement unless there shall have been a terminatio n of the Key Employee’s employment by the Company without Cause or by the Key Employee with G ood Reason following and within twelve (12) months after a Change in Control. This Agreement s hall not be construed as creating an express or implied contract of employment and, except as other wise agreed in writing between the Key Employee and the Company, the Key Employee shall not have an y right to be retained in the employ of the Company.

Severance Payment.

If the Key Employee’s employment is terminated foll owing a Change in Control and within twelve (12) months after a Change in Control (provi ded that such termination of employment constitutes a “separation from service” within the meaning of S ection 409A of the Code), in either event other tha n (A) by the Company for Cause, (B) by reason of deat h 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”).

### 65 In lieu of any further salary payments to the Key E mployee for periods subsequent to the Date of Termination, the Company shall pay to the K ey Employee a lump sum severance payment, in cash, equal to two (2) times the Key Em ployee’s highest Base Salary ( i.e., a Key Employee’s annualized regular earnings excluding an y 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.

The 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 Da te 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 mad e not earlier than but as soon as practicable on or i n any event within thirty (30) days after (with int erest 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 foll owing date when published) the date that is six (6) months after the Date of Termination (the “409A Pay ment Date”)).

Termination Procedures and Compensation During Disp ute.

Notice of Termination. After a Change in Control, any purported termination of the Key Employee’s employment shall be communicated by writ ten Notice of Termination from one party hereto to the other party hereto in accordance with Sectio n 7 hereof. For purposes of this Agreement, a “Not ice

of Termination” shall mean a notice which shall ind icate the specific termination provision in this Agreement relied upon and shall set forth in reason able 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 termi nation of the Key Employee’s employment after a Change in Control shall be presumed to be other tha n 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 ent ire membership of the Board at a meeting of the Board w hich was called and held for the purpose of considering such termination (after reasonable noti ce to the Key Employee and an opportunity for the Key Employee, together with the Key Employee’s coun sel, to be heard before the Board) finding that, in the good faith opinion of the Board, the Key Employ ee was guilty of conduct set forth in clause (i) or (ii) of the definition of Cause herein, and specify ing the particulars thereof in detail.

Date of Termination. “Date of Termination,” with r espect 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) da ys (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 t han sixty (60) days, respectively, from the date su ch Notice of Termination is given, provided that, in t he case of a termination by the Key Employee, the Company may require a Date of Termination earlier t han 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 employm ent between the actual Date of Termination and the Date of Termination specified in the Notice of Termination).

### 66

Dispute Concerning Termination. If within fifteen (15) days after any Notice of Termination is given, or, if later, prior to the Date of Terminati on (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 t he termination, the Date of Termination shall be exten ded until the earlier of (i) the date on which the Term ends or (ii) the date on which the dispute is final ly 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 t he 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 wit h reasonable diligence.

Compensation During Dispute. If a purported termin ation occurs following a Change in Control

and the Date of Termination is extended in accordan ce with Section 5.3 hereof, the Company shall continue to pay the Key Employee the full compensat ion in effect when the notice giving rise to the dispute was given (including, but not limited to, s alary) and continue the Key Employee as a participa nt 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 accordanc e with Section 5.3 hereof. Amounts paid under this S ection 5.4 are in addition to all other amounts due under this Agreement and shall not be offset agains t or reduce any other amounts due under this Agreement.

Successors; Binding Agreement.

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

This 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 leg atees. If the Key Employee shall die while any amount woul d still be payable to the Key Employee hereunder if the Key Employee had continued to live, all such amounts, unless otherwise provided herein, shall b e paid in accordance with the terms of this Agreement to the executors, personal representatives or administrators of the Key Employee s estate.

Notices. For the purpose of this Agreement, notice s and all other communications provided for in the Agreement shall be in writing and shall be d eemed to have been duly given when delivered or mailed by United States registered mail, return rec eipt requested, postage prepaid, addressed, if to t he 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 th e 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 actu al receipt:

To the Company :

4400 Post Oak Parkway, Suite 2700 Houston, TX 77027

Attention: General Counsel

### 67

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 Bo ard. 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 prio r or subsequent time. This Agreement supersedes an y other agreements or representations, oral or otherw ise, express or implied, with respect to the subjec t matter hereof which have been made by the Key Emplo yee or the Company. The validity, interpretation, construction and performance of thi s 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 th e Code shall be deemed also to refer to any successor prov isions to such sections. Any payments provided for hereunder shall be paid net of any applicable withh olding required under federal, state or local law a nd any additional withholding to which the Key Employe e has agreed.

Validity. The invalidity or unenforceability of an y provision of this Agreement shall not affect the validity or enforceability of any other provisi on of this Agreement, which shall remain in full fo rce and effect.

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

Settlement of Disputes. All claims by the Key Empl oyee for benefits under this Agreement shall be directed to and determined by the Board and shal l be in writing. Any denial by the Board of a clai m for benefits under this Agreement shall be delivere d to the Key Employee in writing and shall set fort h the specific reasons for the denial and the specifi c provisions of this Agreement relied upon. The Bo ard shall afford a reasonable opportunity to the Key Em ployee 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.

Definitions. For purposes of this Agreement, the f ollowing terms shall have the meanings

indicated below:

“Base Salary” shall have the meaning set forth in S ection 4.1 hereof.

“Board” shall mean the Board of Directors of the Co mpany.

### 68 “Cause” for termination by the Company of the Key E mployee’s employment shall mean (i) the willful and continued failure by the Key Em ployee 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 ill ness or any such actual or anticipated failure

after the issuance of a Notice of Termination for G ood Reason by the Key Employee pursuant to Section 5.1 hereof) after a written demand for subs tantial performance is delivered to the Key Employee by the Board, which demand specifically id entifies the manner in which the Board believes that the Key Employee has not substantiall y performed the Key Employee’s duties, or (ii) the willful engaging by the Key Employee in co nduct 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 K ey Employee’s part shall be deemed “willful” unless done, or omitted to be done, by the Key Empl oyee not in good faith and without reasonable belief that the Key Employee’s act, or f ailure to act, was in the best interest of the Company and (y) in the event of a dispute concernin g the application of this provision, no claim by the Company that Cause exists shall be given eff ect unless the Company establishes to the Board by clear and convincing evidence that Cause e xists.

“Change in Control” shall be deemed to have occurre d 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 agg regate than twenty percent (20%) of the thentotal issued and outstanding common stock of the Co mpany.

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

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

“Date of Termination” shall have the meaning set fo rth in Section 5.2 hereof.

“Effective Date” shall have the meaning set forth i n Section 2 hereof.

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

a material reduction in the Key Employee’s authorit y, 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 fr om those in effect immediately prior to the Change in Control;

a material diminution in base salary as in effect i mmediately prior to the Change in Control; or

### 69 a material change in the geographic location at whi ch the Key Employee must perform services, which for purposes of this Agreem ent shall include only the relocation of the Key Employee’s principal place of employment to a l ocation more than fifty (50) miles distant from the Company’s headquarters immediately prior t o the Change in Control or the Company’s requiring the Key Employee to be based anywhere oth er 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 c onstitute consent to, or a waiver of rights with respect to, any act or failure to ac t 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 followin g the date of the first occurrence of such act or

failure to act.

“Key Employee” shall mean the individual named in t he first paragraph of this Agreement.

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

“Separation” shall have the meaning set forth in th e recitals hereof.

“Severance Payment” shall have the meaning set fort h 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

### 70 EXHIBIT 21

SUBSIDIARIES OF THE REGISTRANT

The following is a list of all subsidiary corporat ions of the registrant. All subsidiaries are wholl y-owned by the Company, except that Buckley Mining Corporat ion and Plastics Universal Corporation are wholly-o wned subsidiaries of Ada Mining Corporation. The Compan y's consolidated financial statements include the a ccounts
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

### 71 Exhibit 23.1

CONSENT OF RYDER SCOTT COMPANY

The undersigned hereby consents to the references t o our firm in the form and context in which they appear in the Annual Report on Form 10-K of Adams R esources & Energy, Inc. for the year ended December 31, 2011 (the “Annual Report”). We hereby further cons ent to the inclusion in the Annual Report of our re port entitled “Adams Resources Exploration Corporation – Estimated Future Reserves and Income Attributable to
Certain Leasehold Interests – SEC Parameters – As o f December 31, 2011” and to the inclusion of our re port 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

### 72 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 st atements were made, not misleading with respect to the period cov ered by this annual report;

3. Based on my knowledge, the financial statements, an d other financial information included in this annu al report, fairly present in all material respects the financial cond ition, 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 discl osure controls and procedures (as defined in Exchange Act Rules 13a-15 (e) and 15d-15(e)) and internal control over financ ial 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, o r caused such disclosure controls and procedures to be designed under our supervision, to ensure that mate rial information relating to the registrant, includ ing its consolidated subsidiaries, is made known to us by o thers within those entities, particularly during th e period in which this annual report is being prepare d;

(b) designed such internal control over financial r eporting, or caused such internal control over fina ncial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliabil ity of financial reporting and the preparation of financia l statements for external purposes in accordance wi th generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented i n this report

our conclusions about the effectiveness of the disc losure controls and procedures, as of the end of th e period covered by this report based on such evaluat ion; and

(d) disclosed in this report any change in the regi strant’s internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f), that oc curred during the registrant’s most recent fiscal q uarter (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 registr ant’s internal control over financial reporting.

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

(a) all significant deficiencies and material weaknesse s in the design or operation of internal control ov er 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 m anagement or other employees who have a significant role in the registrant's internal contr ols.

Date: March 22, 2012

/s/ K. S. Adams, Jr. K. S. Adams, Jr.

Chief Executive Officer

### 73 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 st atements were made, not misleading with respect to the period cov ered by this annual report;

3. Based on my knowledge, the financial statements, an d other financial information included in this annu al report, fairly present in all material respects the financial cond ition, 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 discl osure controls and procedures (as defined in Exchange Act Rules 13a-15 (e) and 15d-15(e)) and internal control over financ ial 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, o r caused such disclosure controls and procedures to be designed under our supervision, to ensure that mate rial information relating to the registrant, includ ing its consolidated subsidiaries, is made known to us by o thers within those entities, particularly during th e period in which this annual report is being prepare d;

(b) designed such internal control over financial reporting, or caused such internal control over fin ancial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliabil ity of financial reporting and the preparation of financia l statements for external purposes in accordance wi th 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 disc losure controls and procedures, as of the end of th e period covered by this report based on such evaluation; an d

(d) disclosed in this report any change in the reg istrant’s internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f), that oc curred during the registrant’s most recent fiscal q uarter (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 registr ant’s internal control over financial reporting.

5. The registrant's other certifying officer and I hav e 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 fun ctions):

(a) all significant deficiencies in the design or opera tion of internal controls over financial reporting which are reasonably likely to adversely affect the registran t’s ability to record, process, summarize and repor t financial information; and

(b) any fraud, whether or not material, that involves m anagement 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

### 74 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 Resou rces & Energy, Inc. (the “Company”) on Form 10-K fo r the year ended December 31, 2011 (the “Report”), I, K. S. Adams, Jr., Chief Executive Officer of the C ompany, certify, pursuant to 18 U.S.C. 1350, as adopted pur suant to 906 of the Sarbanes-Oxley Act of 2002, tha t 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 pres ents, 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 acc ompany the Report pursuant to 18 U.S.C.§1350, as ad opted pursuant to Section 906 of the Sarbanes-Oxley Act o f 2002, and shall not be deemed “filed” by the Comp any for purposes of Section 18 of the Securities Exchange A ct of 1934, as amended, and shall not be incorporat ed by reference into any filing of the Company under the Securities Act of 1933, as amended, or the Securiti es Exchange Act of 1934, as amended, whether made befo re or after the date of this Report, irrespective o f any general incorporation language contained in such fi ling.

A signed original of this written statement require d by Section 906, or other documents authenticating

, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic ve rsion 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 Exchang e Commission or its staff upon request.

### 75 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 Resou rces & Energy, Inc. (the “Company”) on Form 10-K fo r 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 pur suant to 906 of the Sarbanes-Oxley Act of 2002, tha t 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 pres ents, 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 acc ompany the Report pursuant to 18 U.S.C.§1350, as ad opted pursuant to Section 906 of the Sarbanes-Oxley Act o f 2002, and shall not be deemed “filed” by the Comp any for purposes of Section 18 of the Securities Exchange A ct of 1934, as amended, and shall not be incorporat ed by reference into any filing of the Company under the Securities Act of 1933, as amended, or the Securiti es Exchange Act of 1934, as amended, whether made befo re or after the date of this Report, irrespective o f any general incorporation language contained in such fi ling.

A signed original of this written statement require d by Section 906, or other documents authenticating

, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic ve rsion 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 Exchang e Commission or its staff upon request.

### 76 

## 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 [SE AL]

RYDER SCOTT COMPANY, L.P. TBPE Firm Registration No. F-1580

### 77 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

### 78

TBPE REGISTERED ENGINEERING FIRM F-1580 FAX (713) 651-0849 1100 LOUISIANA SUITE 3800 HOUSTON, 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 certa in leasehold and royalty interests of Adams Resourc es Exploration Corporation (Adams) as of December 31, 2011. The subject properties are located in the states of Alabama, Arkansas, Kansas, Louisiana, Mon tana, 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 Securiti es and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernizatio n of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regul ations). 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 requ irements set forth in the SEC regulations. The properties reviewed by Ryder Scott represent 100 pe rcent of the total net proved liquid hydrocarbon an d gas reserves of Adams.

The estimated reserves and future net income amount s presented in this report, as of December 31, 2011, are related to hydrocarbon prices. The hydro carbon prices used in the preparation of this repor t 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 unweighte d arithmetic averages of the prices in effect on th e first-day-of-the-month for each month within such p eriod, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from th e prices required by SEC regulations; therefore, volu mes of reserves actually recovered and the amounts of income actually received may differ significantl y from the estimated quantities presented in this report. The results of this study are summarized b elow.

SEC PARAMETERS

Estimated Net Reserves and Income Data Certain Leasehold and Royalty Interests of Adams Resources Exploration Corporation As of December 31, 2011

### 79 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 $ 2,3 47.9 $ 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 $ 84 5.3 $ 32,201.0

Liquid hydrocarbons are expressed in thousands of s tandard 42 gallon barrels (MBbls). All gas volumes are reported on an “as sold basis” expressed in mil lions of cubic feet (MMCF) at the official temperat ure and pressure bases of the areas in which the gas re serves are located. The net remaining reserves are also shown herein on an equivalent unit basis where in natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one b arrel of oil equivalent. MBOE means thousands of barrels of oil equivalent. In this report, the rev enues, deductions, and income data are expressed as thousands of U.S. dollars (M$).

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

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valo rem taxes, recompletion costs, development costs, a nd certain abandonment costs net of salvage. The futu re net income is before the deduction of state and federal income taxes and general administrative ove rhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjus tment for cash on hand or undistributed income. Ga s reserves account for approximately 62 percent and l iquid hydrocarbon reserves account for the remaining 38 percent of total future gross revenue from proved reserves.

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

### 80 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 info rmation 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 Re serves Definitions” is included as an attachment to this report.

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

No attempt was made to quantify or otherwise accoun t for any accumulated gas production imbalances that may exist. The proved gas volumes included he rein 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 app lication of development projects to known

accumulations.” All reserve estimates involve an a ssessment of the uncertainty relating the likelihoo d that the actual remaining quantities recovered will be greater or less than the estimated quantities

determined as of the date the estimate is made. Th e 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 co nveyed by placing reserves into one of two principa l classifications, either proved or unproved. Unprov ed 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 recov erability. At Adams’ request, this report addresse s only the proved reserves attributable to the proper ties evaluated herein.

Proved oil and gas reserves are “those quantities o f oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a give n 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 “hig h degree of confidence that the quantities will be re covered.”

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 esti mated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to incre ase or remain constant than to decrease.”

### 81

Moreover, estimates of proved reserves may be revis ed 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 shou ld not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual c osts related thereto, could be more or less than th e estimated amounts.

Adams’ operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not b e 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, royalti es, various taxes and levies including income tax a nd are subject to change from time to time. Such chan ges 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 w ere based upon a detailed study of the properties i n 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 opera ting practices.

Estimates of Reserves

The estimation of reserves involves two distinct de terminations. The first determination results in t he 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 Exchang e 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 an alytical procedures fall into three broad categorie s or methods: (1) performance-based methods; (2) volumet ric-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 mus t 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 e stimate, the established or anticipated performance characteristics of the reservoir being evaluated an d the stage of development or producing maturity of the property.

In many cases, the analysis of the available geosci ence 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 evaluat or must determine the uncertainty associated with the incremental quantities of the reserves. If the res erve quantities are estimated using the deterministic in cremental approach, the uncertainty for each discre te incremental quantity of the reserves is addressed b y the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quan tities as proved, probable and/or possible that add resses the inherent uncertainty in the estimated quantitie s reported. For proved reserves, uncertainty is de fined by the SEC as reasonable certainty wherein the “qua ntities actually recovered are much more likely tha n not to be achieved.” The SEC states that “probable reserves are those additional reserves that are le ss certain to be recovered than proved reserves but wh ich, together with proved reserves, are as likely a s not to be recovered.” The SEC states that “possibl e reserves are those additional reserves that are l ess 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 quantit ies of reserves within the same reserve category must m eet the SEC definitions as noted above.

### 82

Estimates of reserves quantities and their associat ed reserve categories may be revised in the future as additional geoscience or engineering data become av ailable. 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 o perations, effects of regulation by governmental agencies or geopolitical or economic risks as previ ously noted herein.

The proved reserves for the properties included her ein were estimated by performance methods, the volumetric method, analogy, or a combination of met hods. Almost all of the proved producing reserves attributable to producing wells and/or reservoirs w ere 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 availabl e through November 2011, in those cases where such

data were considered to be definitive. The data ut ilized in this analysis were furnished to Ryder Sco tt by Adams or obtained from public data sources and were considered sufficient for the purpose thereof. Th e remaining small portion of the proved producing res erves 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 estimat es was considered to be inappropriate.

All of the proved developed non-producing and undev eloped 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 Dec ember 2011. The data utilized from the analogues a s 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, bu t not limited to, the use of reservoir parameters derived from geological, geophysical and engineerin g data that cannot be measured directly, economic criteria based on current costs and SEC pricing req uirements, and forecasts of future production rates

. Under the SEC regulations 210.4-10(a)(22)(v) and (2 6), proved reserves must be anticipated to be economically producible from a given date forward b ased on existing economic conditions including the prices and costs at which economic producibility fr om a reservoir is to be determined. While it may reasonably be anticipated that the future prices re ceived for the sale of production and the operating costs and other costs relating to such production m ay increase or decrease from those under existing economic conditions, such changes were, in accordan ce with rules adopted by the SEC, omitted from consideration in making this evaluation.

Adams has informed us that they have furnished us a ll of the material accounts, records, geological an d engineering data, and reports and other data requir ed for this investigation. In preparing our foreca st 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 a nd production taxes, including the terms of certain se verance tax exemptions, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geo logical structural and isochore maps, well logs, co re analyses, and pressure measurements. Ryder Scott r eviewed such factual data for its reasonableness; however, we have not conducted an independent verif ication of the data furnished by Adams. We consider the factual data used in this report appro priate and sufficient for the purpose of preparing the

estimates of reserves and future net revenues herei n.

### 83

In summary, we consider the assumptions, data, meth ods and analytical procedures used in this report appropriate for the purpose hereof, and we have use d 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 Unit ed 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 wit h 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 h as been established, future production rates were h eld constant, or adjusted for the effects of curtailmen t 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 de cline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used t o estimate the anticipated initial production rates for those wells or locations that are not currently pro ducing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnis hed 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 t o initiate production. Such factors may include delays due to weather, the availability of rigs, th e sequence of drilling, completing and/or recomplet ing 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 estima ted because of changes including, but not limited t o, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, prod ucing 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 eff ect on the first-day-of-the-month for each month within such period, unless prices were defined by c ontractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration o f the contract. Upon contract expiration, the pric es 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 usin g 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 d ifferentials as described herein. The table below summarizes the “benchmark prices” and “price refere nce” used for the geographic areas included in the report. In certain geographic areas, the price ref erence 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 repres ented by the unweighted arithmetic average of the initial 12-month average first-day-of-the-month ben chmark prices used.

### 84

The product prices that were actually used to deter mine the future gross revenue for each property reflect adjustments to the benchmark prices for gra vity, quality, local conditions, and/or distance fr om market, referred to herein as “differentials.” The differentials used in the preparation of this repo rt were furnished to us by Adams, accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verif ication of the data used by Adams to determine

these differentials.

In addition, the table below summarizes the net vol ume weighted benchmark prices adjusted for differentials and referred to herein as the “averag e realized prices.” The average realized prices sh own in the table below were determined from the total f uture gross revenue before production taxes and the total net reserves for the geographic area and pres ented in accordance with SEC disclosure requirement s for each of the geographic areas included in the re port.

Geographic Area Product Price

Reference Average

Benchmark Prices Average

Realized Prices

Oil/Condensate Various 1 

### $ 90.88 / Bbl $ 95.85 / Bbl

Total U.S. Domestic Plant Products % WTI 2 

### $ 57.71 / Bbl $ 57.71 / Bbl

Gas Various 3 

### $ 4.01 / MMBTU $ 4.69 / MCF

1 Oil/Cond Benchmarks include Postings for: LOTT A rkansas 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 Cus hing

3 Gas Benchmarks include: Carthage Hub, CIG, El Pa so-Permian, Henry Hub, Houston Ship Channel, NGPL_MC, NGPL_STX, NGPL_TexOk Zone, Southern Natura l 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 re port were provided by Adams and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general an d administrative costs allocated directly to the leas es and wells. For operated properties, the operati ng costs include an appropriate level of corporate gen eral administrative and overhead costs. The operat ing costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreement s. The operating costs furnished to us were accepted as factual data and were used without inde pendent 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.

### 85

Development costs were furnished to us by Adams and are based on authorizations for expenditure for the proposed work or actual costs for similar proje cts. The development costs furnished to us were accepted as factual data and were used without inde pendent verification. The estimated net cost of abandonment after salvage was included for properti es 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 perf ormed 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 t hese reserves as of December 31, 2011. The implementation of Adams’ development plans as prese nted 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 tha t the development activities included herein have been subjected to and received the internal approva ls required by Adams’ management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, c ertain development activities may still be subject to spec ific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrativ e approvals external to Adams. Additionally, Adams has informed us that they are not aware of an y legal, regulatory, political or economic obstacle s that would significantly alter their plans.

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

Standards of Independence and Professional Qualific ation

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over s eventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colora do; 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-trade d oil and gas company and are separate and independen t from the operating and investment decisionmaking process of our clients. This allows us to b ring the highest level of independence and objectiv ity to each engagement for our services.

Ryder Scott actively participates in industry-relat ed professional societies and organizes an annual public forum focused on the subject of reserves eva luations and SEC regulations. Many of our staff have authored or co-authored technical papers on th e subject of reserves related topics. We encourage our staff to maintain and enhance their professiona l skills by actively participating in ongoing conti nuing

education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientis ts have received professional accreditation in the for m of a registered or certified professional enginee r’s license or a registered or certified professional g eoscientist’s license, or the equivalent thereof, f rom 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 nei ther the employment to do this work nor the compensation is contingent on our estimates of rese rves for the properties that were reviewed.

### 86

The results of this study, presented herein, are ba sed 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 overseei ng, 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 wit h the disclosure requirements set forth in the SEC re gulations 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 th e original signed copy of this report letter. In t he 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 digit al

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

### 87 Professional Qualifications of Primary Technical Pe rson

The conclusions presented in this report are the re sult of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Compan y, L.P. Mr. Fred W. Ziehe was the primary technical person responsible for overseeing the est imate 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 C oordinator responsible for coordinating and supervising staff and consulting engineers of the c ompany in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Ziehe s erved as a Reservoir Engineer with Exxon Company U.S.A. For more information regarding Mr. Ziehe’s geographic and job specific experience, please refe r to the Ryder Scott Company website at www.ryderscot t.com/Experience/Employees.

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

In addition to gaining experience and competency th rough prior work experience, the Texas Board of Professional Engineers requires a minimum of fiftee n hours of continuing education annually, including at least one hour in the area of professional ethic s, which Mr. Ziehe fulfills. As part of his 2011 continuing education hours, Mr. Ziehe attended 8 ho urs 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 Regulati ons, 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 (“Guid elines for the Practical Evaluation of Undeveloped Reserves in Resource Plays”), and Reserve Managemen t Systems. Mr. Ziehe participated as a copresenter in 9 hours of lectures made to undergradu ate and graduate Petroleum Engineering students at Texas A & M University and internally to Ryder Scot t personnel concerning the “SEC Comment Letter

Process”. Mr. Ziehe attended an additional 5.5 hou rs of formalized in-house training during 2011 covering certain oil and gas related software progr ams 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 a s various oil and gas producing basins in the United States, the SPEE Monograph 3, and the use of certai n petroleum economics evaluation software.

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

### 88 PETROLEUM RESERVES DEFINITIONS

As Adapted From: RULE 4-10(a) of REGULATION S-X PART 210 UNITED STATES SECURITIES AND EXCHANGE COMMISSION (S EC)

PREAMBLE

On January 14, 2009, the United States Securities a nd 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 i n Rule 4-10 of Regulation S-X, revisions and additi ons to the oil and gas reporting requirements in Regula tion S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and G as Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be refe rred to herein collectively as the “SEC regulations ”. The SEC regulations take effect for all filings mad e with the United States Securities and Exchange Commission as of December 31, 2009, or after Januar y 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, R egulation 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 app lication of development projects to known

accumulations. All reserve estimates involve an as sessment 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. Th e 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 co nveyed by placing reserves into one of two principa l classifications, either proved or unproved. Unprov ed reserves are less certain to be recovered than proved reserves and may be further sub-classified a s probable and possible reserves to denote progressively increasing uncertainty in their recov erability. Under the SEC regulations as of Decembe r 31, 2009, or after January 1, 2010, a company may o ptionally disclose estimated quantities of probable or possible oil and gas reserves in documents publi cly 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 fore ign or state law as noted in §229.1202 Instruction to
Item 1202.

Reserves estimates will generally be revised only a s 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 natur al energy or altering natural forces in the reservo ir to increase ultimate recovery. Examples of such me thods are pressure maintenance, natural gas cycling

, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery metho ds may be developed in the future as petroleum technology continues to evolve.

### 89

Reserves may be attributed to either conventional o r unconventional petroleum accumulations.

Petroleum accumulations are considered as either co nventional or unconventional based on the nature of their in-place characteristics, extraction method a pplied, or degree of processing prior to sale. Exa mples of unconventional petroleum accumulations include c oalbed or coalseam methane (CBM/CSM), basincentered gas, shale gas, gas hydrates, natural bitu men and oil shale deposits. These unconventional accumulations may require specialized extraction te chnology and/or significant processing prior to sal e.

Reserves do not include quantities of petroleum bei ng 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 o il 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 t here must be a reasonable expectation that there wi ll exist, the legal right to produce or a revenue inte rest in the production, installed means of deliveri ng oil and gas or related substances to market, and all pe rmits and financing required to implement the proje ct.

Note to paragraph (a)(26): Reserves should not be a ssigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically produc ible. Reserves should not be assigned to areas that are c learly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoi r, structurally low reservoir, or negative test res ults). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovere d 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 governm ent regulations—prior to the time at which contracts providing the right to operate expire, un less evidence indicates that renewal is reasonably certain, regardless of whether deterministic or pro babilistic methods are used for the estimation. The project to extract the hydrocarbons must have comme nced or the operator must be reasonably certain that it will commence the project within a reasonab le 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 th at can, with reasonable certainty, be judged to be continuous with it and to contain econ omically producible oil or gas on the basis of available geoscience and engineering d ata.

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PROVED RESERVES (SEC DEFINITIONS) CONTINUED

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

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

(iv) Reserves which can be produced economically th rough application of improved recovery techniques (including, but not limited to, fluid in jection) are included in the proved classification

when: (A) Successful testing by a pilot project in an are a of the reservoir with properties no more favorable than in the reservoir as a whole, th e operation of an installed program in the reservoir or an analogous reservoir, or other e vidence using reliable technology establishes the reasonable certainty of the enginee ring analysis on which the project or program was based; and

(B) The project has been approved for development b y 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 t he report, determined as an unweighted arithmetic average of the first-day-of-the-month pr ice for each month within such period, unless prices are defined by contractual arrangements, exc luding escalations based upon future

conditions.

### 91 RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From: RULE 4-10(a) of REGULATION S-X PART 210 UNITED STATES SECURITIES AND EXCHANGE COMMISSION (S EC)

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 a nd producing status of wells and reservoirs. Reference should be made to Title 17, Code of Feder al Regulations, Regulation S-X Part 210, Rule 4- 10(a) and the SPE-PRMS as the following reserves st atus 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 inf rastructure 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 SE C regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or NonProducing.

Developed Producing Reserves Developed Producing Reserves are expected to be rec overed 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.

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Developed Non-Producing Developed Non-Producing Reserves include shut-in an d 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 f rom zones in existing wells, which will require additional completion work or future re-com pletion prior to start of production.

In all cases, production can be initiated or restor ed 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 an y category that are expected to be recovered from new wells on undrilled acreage, or from existing we lls where a relatively major expenditure is require d for recompletion.

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

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

(iii) Under no circumstances shall estimates for un developed 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 prov ed 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 rea sonable certainty.