Washington, D.C.  20549
(Mark One)
For the Fiscal Year ended December 31, 2011
Commission File Number 1-7908
(Exact name of registrant as specified in its charter)
17 South Briar Hollow Lane  Ste 100
Houston, Texas
(State of Incorporation)
(I.R.S. Employer Identification No.)
(Address of Principal executive offices)
(Zip Code)

Registrant's telephone number, including area code:  (713) 881-3600
Securities registered pursuant to Section 12(b) of the Act:

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

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  YES_X_ NO ___

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

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

Non-accelerated filer _X_                                                      Smaller reporting company _____

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates as of the close of business on June 30, 2011 was $52,992,199 based on the closing price of $25.34 per one share of common stock as reported on the NYSE AMEX Exchange for such date.  A total of 4,217,596 shares of Common Stock were outstanding at March 10, 2012.

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held May 16, 2012 are incorporated by reference into Part III of this report.




Forward-Looking Statements –Safe Harbor Provisions

This annual report on Form 10-K for the year ended December 31, 2011 contains certain forward-looking statements covered by the safe harbors provided under Federal securities law and regulations.  To the extent such statements are not recitations of historical fact, forward-looking statements involve risks and uncertainties.  In particular, statements under the captions (a) Production and Reserve Information, (b) Regulatory Status and Potential Environmental Liability, (c) Management’s Discussion and Analysis of Financial Condition and Results of Operations, (d) Critical Accounting Policies and Use of Estimates, (e) Quantitative and Qualitative Disclosures about Market Risk, (f) Income Taxes, (g) Concentration of Credit Risk, (h) Price Risk Management Activities, and (i) Commitments and Contingencies, among others, contain forward-looking statements.  Where the Company expresses an expectation or belief regarding future results or events, such expression is made in good faith and believed to have a reasonable basis in fact.  However, there can be no assurance that such expectation or belief will actually result or be achieved.

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

Business Activities

Adams Resources & Energy, Inc. (“ARE”) and its subsidiaries (collectively, the "Company"), are engaged in the business of marketing crude oil, natural gas and petroleum products, tank truck transportation of liquid chemicals, and oil and gas exploration and production.  Adams Resources & Energy, Inc. is a Delaware corporation organized in 1973.  The Company’s headquarters are located in 23,450 square feet of office space located at 17 South Briar Hollow Lane Suite 100, Houston, Texas 77027 and the telephone number of that address is (713) 881-3600.  The revenues, operating results and identifiable assets of each industry segment for the three years ended December 31, 2011 are set forth in Note 8 of Notes to Consolidated Financial Statements included elsewhere herein.

Marketing Segment Subsidiaries

Gulfmark Energy, Inc. (“Gulfmark”), a subsidiary of ARE, purchases crude oil and arranges sales and deliveries to refiners and other customers. Activity is concentrated primarily onshore in Texas and Louisiana with additional operations in Michigan and New Mexico. During 2011, Gulfmark purchased approximately 81,600 barrels per day of crude oil at the wellhead or lease level. Gulfmark also operates 148 tractor-trailer rigs and maintains over 54 pipeline inventory locations or injection stations.  Gulfmark has the ability to barge oil from three oil storage facilities along the intercoastal waterway of Texas and Louisiana and maintains 180,000 barrels of storage capacity at certain of the dock facilities in order to access waterborne markets for its products.  Gulfmark delivers physical supplies to refiner customers or enters into exchange transactions with third parties when the cost of the exchange is less than the alternate cost incurred in transporting or storing the crude oil.  During 2011, Gulfmark had sales to four customers that comprised 18.2 percent, 15.4 percent, 13.4 percent, and 11.3 percent, respectively, of total Company wide revenues.  Management believes that a loss of any of these customers would not have a material adverse effect on the Company’s operations.  See also Note 3 of Notes to Consolidated Financial Statements.



Adams Resources Marketing, Ltd. (“ARM”), a subsidiary of ARE, operates as a wholesale purchaser, distributor and marketer of natural gas.  ARM’s focus is on the purchase of natural gas at the producer level. During 2011, ARM purchased approximately 208,000 million british thermal units (“mmbtu’s”) of natural gas per day at the wellhead and pipeline pooling points. Business is concentrated among approximately 60 independent producers with the primary production areas being the Louisiana and Texas Gulf Coast and the offshore Gulf of Mexico region.   ARM provides value added services to its customers by providing access to common carrier pipelines and handling daily volume balancing requirements as well as risk management services.

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

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

Transportation Segment Subsidiary

Service Transport Company (“STC”), a subsidiary of ARE, transports liquid chemicals on a "for hire" basis throughout the continental United States and Canada. Transportation service is provided to over 400 customers under multiple load contracts in addition to loads covered under STC’s standard price list.  Pursuant to regulatory requirements, STC holds a Hazardous Materials Certificate of Registration issued by the United States. Department of Transportation (“DOT”).   STC operates 285 truck tractors of which 12 are independent owner-operator units and maintains 447 tank trailers.  In addition, STC maintains truck terminals in Houston, Corpus Christi, and Nederland, Texas as well as Baton Rouge (St. Gabriel), Louisiana and Mobile (Saraland), Alabama. Transportation operations are headquartered at a terminal facility situated on 22 Company-owned acres in Houston, Texas.  This property includes maintenance facilities, an office building, tank wash rack facilities and a water treatment system.  The St. Gabriel, Louisiana terminal is situated on 11.5 Company-owned acres and includes an office building, maintenance bays and tank cleaning facilities.

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

Oil and Gas Segment Subsidiary

Adams Resources Exploration Corporation (“AREC”), a subsidiary of ARE, is actively engaged in the exploration and development of domestic oil and natural gas properties primarily in Texas and the south central region of the United States. AREC’s offices are maintained in Houston and the Company holds an interest in 405 wells of which 41 are Company operated.

Producing Wells--The following table sets forth the Company's gross and net productive wells as of December 31, 2011. Gross wells are the total number of wells in which the Company has an interest, while net wells are the sum of the fractional interests owned.



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

Acreage--The following table sets forth the Company's gross and net developed and undeveloped acreage as of December 31, 2011.  Gross acreage represents the Company’s direct ownership and net acreage represents the sum of the fractional interests owned.  The Company’s developed acreage is held by current production while undeveloped acreage is held by oil and gas leases with various remaining terms from six months to three years.  The Company’s ownership in undeveloped acreage is substantially all in the form of a non-operated minority interest.  As such, the Company relies on the third party operator to manage the lease holdings.

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

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

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

Production and Reserve Information--The Company's estimated net quantities of proved oil and natural gas reserves and the standardized measure of discounted future net cash flows calculated at a 10% discount rate for the three years ended December 31, 2011, are presented in the table below (in thousands):
December 31,
Crude oil (thousands of barrels)
    292       267       242  
Natural gas (thousands of mcf)
    9,661       7,794       7,248  
Standardized measure of discounted future
net cash flows from oil and natural gas  reserves
  $ 20,931     $ 16,672     $ 9,305  

The estimated value of oil and natural gas reserves and future net revenues from oil and natural gas reserves was made by the Company's independent petroleum engineers.  The reserve value estimates provided at each of December 31, 2011, 2010 and 2009 are based on market prices of $95.85, $76.14 and $58.43 per barrel for crude oil and $4.69, $5.26 and $4.05 per mcf for natural gas, respectively.  For 2011 and 2010, such prices were based on the unweighted arithmetic average of the prices in effect on the first day of the month for each month of the respective twelve month periods as required by Security and Exchange Commission (“SEC”) regulations.  For 2009, the price reflects the market price on December 31, 2009.  The price reported for natural gas includes the value of associated natural gas liquids.



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

The Company's oil and natural gas production for the three years ended December 31, 2011 was as follows:
Years Ended
Crude Oil
December 31,
Gas (mcf)
    61,500       1,895,000  
    54,000       1,365,000  
    49,500       1,304,000  

Certain financial information relating to the Company's oil and natural gas division revenues and earnings is summarized as follows:
Years Ended December 31,
Average oil and condensate
sales price per barrel
  $ 93.23     $ 77.09     $ 58.10  
Average natural gas
sales price per mcf
  $ 4.39     $ 5.02     $ 4.43  
Average production cost, per equivalent
barrel, charged to expense
  $ 16.79     $ 13.99     $ 13.25  

The Company has had no reports to federal authorities or agencies of estimated oil and gas reserves. The Company is not obligated to provide any fixed and determinable quantities of oil or gas in the future under existing contracts or agreements associated with its oil and gas exploration and production segment.

Environmental Compliance and Regulation

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



The Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, as amended.
Comprehensive Environmental Response, Compensation and Liability Act of 1980 ("CERCLA" or "Superfund"), as amended.
The Clean Water Act of 1972, as amended.
Federal Oil Pollution Act of 1990, as amended.
The Clean Air Act of 1970, as amended.
The Toxic Substances Control Act of 1976, as amended.
The Emergency Planning and Community Right-to-Know Act.
The Occupational Safety and Health Act of 1970, as amended.
Texas Clean Air Act.
Texas Solid Waste Disposal Act.
Texas Water Code.
Texas Oil Spill Prevention and Response Act of 1991, as amended.

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

Louisiana Office of Conservation--This agency has primary statutory responsibility for regulation and conservation of oil, gas, and other natural resources in the State of Louisiana.  Their objectives are to (i) regulate the exploration and production of oil, natural gas and other hydrocarbons; (ii) control and allocate energy supplies and distribution and (iii) protect public safety and the State’s environment from oilfield waste, including regulation of underground injection and disposal practices.
State and Local Government Regulation--Many states are authorized by the United States Environmental Protection Agency (“EPA”) to enforce regulations promulgated under various federal statutes.  In addition, there are numerous other state and local authorities that regulate the environment, some of which impose more stringent environmental standards than federal laws and regulations.  The penalties for violations of state law vary, but typically include injunctive relief, recovery of damages for injury to air, water or property and fines for non-compliance.

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

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



Marketing Operations--The Company's marketing facilities are subject to a number of state and federal environmental statutes and regulations, including the regulation of underground fuel storage tanks.  While the Company has not owned or operated underground tanks for more than 10 years, historically the Company was an owner and operator of underground storage tanks.  The EPA's Office of Underground Tanks and applicable state laws establish regulations requiring owners or operators of underground fuel tanks to demonstrate evidence of financial responsibility for the costs of corrective action and the compensation of third parties for bodily injury and property damage caused by sudden and non-sudden accidental releases arising from operating underground tanks.  In addition, the EPA requires the installation of leak detection devices and stringent monitoring of the ongoing condition of underground tanks.  Should leakage develop in an underground tank, the operator is obligated for clean up costs.  During the period when the Company operated underground tanks, it secured insurance covering both third party liability and clean up costs.

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

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

Regulatory Status and Potential Environmental Liability--The operations and facilities of the Company are subject to numerous federal, state and local environmental laws and regulations including those described above, as well as associated permitting and licensing requirements.  The Company regards compliance with applicable environmental regulations as a critical component of its overall operation, and devotes significant attention to providing quality service and products to its customers, protecting the health and safety of its employees, and protecting the Company’s facilities from damage. Management believes the Company has obtained or applied for all permits and approvals required under existing environmental laws and regulations to operate its current business.  Management has reported that the Company is not subject to any pending or threatened environmental litigation or enforcement actions which could materially and adversely affect the Company's business.  The Company has, where appropriate, implemented operating procedures at each of its facilities designed to assure compliance with environmental laws and regulation. However, given the nature of the Company’s business, the Company is subject to environmental risks and the possibility remains that the Company's ownership of its facilities and its operations and activities could result in civil or criminal enforcement and public as well as private actions against the Company, which may necessitate or generate mandatory clean up activities, revocation of required permits or licenses, denial of application for future permits, and/or significant fines, penalties or damages, any and all of which could have a material adverse effect on the Company.  At December 31, 2011, the Company is unaware of any unresolved environmental issues for which additional accounting accruals are necessary.




At December 31, 2011 the Company employed 780 persons, 15 of whom were employed in the exploration and production of oil and gas, 345 in the marketing of crude oil, natural gas and petroleum products, 399 in transportation operations, and 21 in administrative capacities.  None of the Company's employees are represented by a union.  Management believes its employee relations are satisfactory.

Federal and State Taxation

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

Recent Event

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

Available Information

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

The Company maintains a corporate website at, on which investors may access free of charge the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as is reasonably practicable after filing or furnishing such material with the SEC.  Additionally, the Company has adopted and posted on its website a Code of Business Ethics designed to reflect requirements of the Sarbanes-Oxley Act of 2002, NYSE Amex Exchange rules and other applicable laws, rules and regulations. The Code of Business Ethics applies to all of the Company’s directors, officers and employees.  Any amendment to the Code of Business Ethics will be posted promptly on the Company’s website.  The information contained on or accessible from the Company’s website does not constitute a part of this report and is not incorporated by reference herein.  The Company will provide a printed copy of any of these aforementioned documents free of charge upon request by calling ARE at (713)-881-3600 or by writing to:
Adams Resources & Energy, Inc.
ATTN:  Richard B. Abshire
17 South Briar Hollow Lane, Ste 100
Houston, Texas 77027




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

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

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

Customer demand for the Company’s products and services is substantially dependent upon the general economic conditions for the United States which are cyclical in nature.  In particular, demand for liquid chemical truck transportation services is dependent on activity within the petrochemical sector of the U. S. economy.  Chemical sector demand typically varies with the housing and auto markets as well as the relative strength of the U. S. dollar to foreign currencies.  A relatively strong U.S. dollar exchange rate tends to suppress export demand for petrochemicals which is adverse to the Company’s transportation operation.  Conversely, a weak U. S. dollar exchange rate tends to stimulate export demand for petrochemicals.

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

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

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

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

The financial soundness of customers could affect the Company’s business and operating results

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



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

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

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

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

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

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

supply and demand for oil and gas and expectations regarding supply and demand;
political conditions in other oil-producing countries, including the possibility of insurgency or war in such areas;
economic conditions in the United States and worldwide;
governmental regulations and taxation;
impact of energy conservation efforts;
the price and availability of alternative fuel sources;
weather conditions;
availability of local, interstate and intrastate transportation systems; and
market uncertainty.

Revenues are generated under contracts that must be renegotiated periodically.

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



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

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

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

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

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

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

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

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

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

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



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

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

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

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

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

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

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

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

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

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



lack of acceptable prospective acreage;
inadequate capital resources;
title problems;
compliance with governmental regulations; and
mechanical difficulties.

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

Security issues exist relating to drivers, equipment and terminal facilities

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

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

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

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

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

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



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




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


Not Applicable




Item 5.

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

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

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

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




Performance Graph

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

$100.00 was invested on December 31, 2006 in the Company’s common stock, the S&P 500 Index, and the S&P 500 Integrated Oil and Gas Index.

Dividends are reinvested on the ex-dividend dates.

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

Adams Resources & Energy, Inc.
S&P 500
S&P Integrated Oil & Gas




Years Ended December 31,
(In thousands, except per share data)
  $ 3,136,838     $ 2,144,082     $ 1,889,583     $ 4,074,677     $ 2,558,545  
    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):
  $ 50,596     $ 16,724     $ 17,487     $ (2,704 )   $ 20,152  
    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
  $ 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  

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

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




Results of Operations

- Marketing

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

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  
  $ 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 )
  $ 50,596     $ 16,724     $ 17,487  
Crude oil
  $ 3,724     $ 2,320     $ 1,997  
Natural gas
    3       44       166  
Refined products
    375       503       533  
  $ 4,102     $ 2,867     $ 2,696  

Supplemental volume and price information is:

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

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

Comparison 2011 to 2010

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



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

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

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

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

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

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

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



-           Transportation

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

  $ 63,501       12 %   $ 56,867       27 %   $ 44,895       (34 )%
Operating earnings
  $ 8,521       29 %   $ 6,623       211 %   $ 2,128       (50 )%
  $ 3,912       (9 )%   $ 4,288       8 %   $ 3,970       3 %
Represents the percentage increase (decrease) from the prior year.

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

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

-           Oil and Gas

Oil and gas segment revenues and operating earnings are primarily derived from crude oil and natural gas production volumes and prices.  Comparative amounts for revenues, operating earnings and depreciation and depletion were as follows (in thousands):

  $ 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 )%
Represents the percentage increase (decrease) from the prior year.
Excludes gains from property sales



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

Comparative volumes and prices were as follows:

Production Volumes
- Crude Oil
- Natural Gas
Average Price
- Crude Oil
  $ 93.23  
  $ 77.09  
  $ 58.10  
- Natural Gas
  $ 4.39  
  $ 5.02  
  $ 4.43  

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

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

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

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

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



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

East Texas Project

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

West Texas Project

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

South Texas Project

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

Oil and gas property sales

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



General and administrative, interest income and income tax

General and administrative expenses were consistent during the three year review period ending December 31, 2011 except during 2011  such costs were elevated due to employee bonuses.  Interest income declined for 2011, 2010 and 2009 as interest rates on overnight deposits declined to near zero following the significant turmoil that occurred in the financial markets during the fall of 2008.  The provision for income taxes is based on Federal and State tax rates and variations are consistent with taxable income in the respective accounting periods.


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

The Company has the following major objectives for 2012:

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

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

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

Liquidity and Capital Resources

The Company’s liquidity primarily derives from net cash provided from operating activities, which was $55,815,000, $36,928,000 and $22,285,000 for each of 2011, 2010 and 2009, respectively.  As of December 31, 2011 and 2010, the Company had no bank debt or other forms of debenture obligations.  Cash and cash equivalents totaled $37,066,000 as of December 31, 2011, and such balances are maintained in order to meet the timing of day-to-day cash needs.  Working capital, the excess of current assets over current liabilities, totaled $48,808,000 as of December 31, 2011.

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



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

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

The most significant item affecting future increases or decreases in liquidity is earnings from operations and such earnings are dependent on the success of future operations (see Item 1A. Risk Factors in this annual report of Form 10-K).

Off-balance Sheet Arrangements

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

Contractual Cash Obligations

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

Lease payments
  $ 3,059     $ 2,148     $ 1,468     $ 1,201     $ 1,181     $ 1,602     $ 10,659  



In addition to its lease financing obligations, the Company is also committed to purchase certain quantities of crude oil and natural gas in connection with its marketing activities.  Such commodity purchase obligations are the basis for commodity sales, which generate the cash flow necessary to meet such purchase obligations.  Approximate commodity purchase obligations as of December 31, 2011 are as follows (in thousands):

Crude Oil
  $ 242,942     $ 1,473     $ -     $ -     $ -     $ 244,415  
Natural Gas
    8,622       260       -       -       -       8,882  
    $ 251,564     $ 1,733     $ -     $ -     $ -     $ 253,297  


From time to time, the marketplace for all forms of insurance enters into periods of severe cost increases. In the past, during such cyclical periods, the Company has seen costs escalate to the point where desired levels of insurance were either unavailable or unaffordable.  The Company’s primary insurance needs are worker’s compensation, automobile and umbrella coverage for its trucking fleet and medical insurance for employees.  During each of 2011, 2010 and 2009, insurance costs were consistent with activity and totaled $11.2 million, $10 million and $10.5 million, respectively.  Insurance cost may experience renewed rate increases during 2012 subject to market conditions.  Since the Company is generally unable to pass on such cost increases, any increase will need to be absorbed by existing operations.


In all phases of its operations, the Company encounters strong competition from a number of entities. Many of these competitors possess financial resources substantially in excess of those of the Company. The Company faces competition principally in establishing trade credit, pricing of available materials and quality of service.  In its oil and gas operation, the Company also competes for the acquisition of mineral properties. The Company's marketing division competes with major oil companies and other large industrial concerns that own or control significant refining and marketing facilities.  These major oil companies may offer their products to others on more favorable terms than those available to the Company.  From time to time in recent years, there have been supply imbalances for crude oil and natural gas in the marketplace.  This in turn has led to significant fluctuations in prices for crude oil and natural gas. As a result, there is a high degree of uncertainty regarding both the future market price for crude oil and natural gas and the available margin spread between wholesale acquisition costs and sales realization.

Critical Accounting Policies and Use of Estimates

Fair Value Accounting

The Company enters into certain forward commodity contracts that are required to be recorded at fair value and such contracts are recorded as either an asset or liability measured at its fair value.  Changes in fair value are recognized immediately in earnings unless the derivatives qualify for, and the Company elects, cash flow hedge accounting.  The Company had no contracts designated for hedge accounting during 2011, 2010 and 2009.

The Company utilizes a market approach to valuing its commodity contracts.  On a contract by contract, forward month by forward month basis, the Company obtains observable market data for valuing its contracts.  Such contracts typically have durations that are less than 18 months.  As of December 31, 2011, all of the Company’s market value measurements were based on either quoted prices in active markets (Level 1 inputs) or from inputs based on observable market data (Level 2 inputs). See discussion under “Fair Value Measurements” in Note 1 to the Consolidated Financial Statements.



The Company’s fair value contracts give rise to market risk, which represents the potential loss that may result from a change in the market value of a particular commitment.  The Company monitors and manages its exposure to market risk to ensure compliance with the Company’s risk management policies.  Such policies are regularly assessed to ensure their appropriateness given management’s objectives, strategies and current market conditions.

Trade Accounts

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

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

Oil and Gas Reserve Estimate

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

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




From time to time as incident to its operations, the Company becomes involved in various accidents, lawsuits and/or disputes.  Primarily as an operator of an extensive trucking fleet, the Company is a party to motor vehicle accidents, worker compensation claims or other items of general liability as are typical for the industry.  In addition, the Company has extensive operations that must comply with a wide variety of tax laws, environmental laws and labor laws, among others.  Should an incident occur, management evaluates the claim based on its nature, the facts and circumstances and the applicability of insurance coverage.  To the extent management believes that such event may impact the financial condition of the Company, management will estimate the monetary value of the claim and make appropriate accruals or disclosure as provided in the appropriate accounting literature guidelines.

Revenue Recognition

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

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

Recent Accounting Pronouncements

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

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

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



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


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

Interest Rate Risk

The Company had no long-term debt outstanding at December 31, 2011 and 2010.  A hypothetical ten percent adverse change in the floating rate would not have a material effect on the Company’s results of operations for the fiscal year ended December 31, 2011.

Commodity Price Risk

The Company’s major market risk exposure is in the pricing applicable to its marketing and production of crude oil and natural gas.  Realized pricing is primarily driven by the prevailing spot prices applicable to oil and gas.  Commodity price risk in the Company’s marketing operations represents the potential loss that may result from a change in the market value of an asset or a commitment.  From time to time, the Company enters into forward contracts to minimize or hedge the impact of market fluctuations on its purchases of crude oil and natural gas. The Company may also enter into price support contracts with certain customers to secure a floor price on the purchase of certain supply. In each instance, the Company locks in a separate matching price support contract with a third party in order to minimize the risk of these financial instruments.  Substantially all forward contracts fall within a six-month to eighteen-month term with no contracts extending longer than two years in duration.

Certain forward contracts are recorded at fair value, depending on management’s assessments of numerous accounting standards and positions that comply with generally accepted accounting principles in the United States. The fair value of such contracts is reflected in the balance sheet as fair value assets and liabilities and any revaluation is recognized on a net basis in the Company’s results of operations.  See discussion under “Fair Value Measurements” in Note 1 to the Consolidated Financial Statements.

Historically, prices received for oil and natural gas sales have been volatile and unpredictable with price volatility expected to continue.  From January 1, 2010 through December 31, 2011 natural gas price realizations ranged from a monthly low of $3.42 per mmbtu to a monthly high of $5.80 per mmbtu.  Crude oil prices ranged from a monthly average low of $70.90 per barrel to a high of $109.94 per barrel during the same period. A hypothetical ten percent adverse change in average natural gas and crude oil prices, assuming no changes in volume levels, would have reduced earnings by approximately $3,252,000 and $2,393,000 for the comparative years ended December 31, 2011 and 2010, respectively.






Consolidated Balance Sheets as of December 31, 2011 and 2010
Consolidated Statements of Operations for the Years Ended
December 31, 2011, 2010 and 2009
Consolidated Statements of Shareholders’ Equity for the Years Ended
December 31, 2011, 2010 and 2009
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2011, 2010 and 2009
Notes to Consolidated Financial Statements




To the Board of Directors and Stockholders of
Adams Resources & Energy, Inc.
Houston, Texas

We have audited the accompanying consolidated balance sheets of Adams Resources & Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2011.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Adams Resources & Energy, Inc. and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for the each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

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


Houston, Texas
March 22, 2012



(In thousands)
December 31,
Cash and cash equivalents
  $ 37,066     $ 29,032  
Accounts receivable, net of allowance for doubtful accounts of
$2,205 and $1,064, respectively
    234,515       190,169  
    20,189       14,591  
Fair value contracts
    2,064       2,764  
Income tax receivable
    480       2,316  
    10,651       8,104  
Total current assets
    304,965       246,976  
    38,467       25,407  
    54,359       43,131  
Oil and gas (successful efforts method)
    81,668       73,011  
    1,553       188  
      176,047       141,737  
Less – Accumulated depreciation, depletion and amortization
    (106,812 )     (94,148 )
      69,235       47,589  
Oil and gas property held for sale
    -       3,389  
Deferred income tax asset
    473       374  
Cash deposits and other
    4,167       2,977  
    $ 378,840     $ 301,305  
Accounts payable
  $ 248,656     $ 200,763  
Accounts payable – related party
    58       9  
Fair value contracts
    681       1,478  
Accrued and other liabilities
    6,194       3,894  
Current deferred income taxes
    505       854  
Total current liabilities
    256,094       206,998  
Asset retirement obligations
    1,568       1,390  
Deferred taxes and other liabilities
    10,496       2,762  
      268,158       211,150  
Preferred stock, $1.00 par value, 960,000 shares authorized,
none outstanding
    -       -  
Common stock, $.10 par value, 7,500,000 shares authorized,
4,217,596 issued and outstanding
    422       422  
Contributed capital
    11,693       11,693  
Retained earnings
    98,567       78,040  
Total shareholders’ equity
    110,682       90,155  
    $ 378,840     $ 301,305  

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



(In thousands, except per share data)

Years Ended December 31,
  $ 3,136,838     $ 2,144,082     $ 1,889,583  
    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  
    3,082,140       2,124,491       1,869,400  
    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:
    (5,523 )     (371 )     (1,280 )
    (7,308 )     (3,699 )     (1,072 )
      (12,831 )     (4,070 )     (2,352 )
Net Earnings
  $ 22,931     $ 8,631     $ 4,149  
Basic and diluted net earnings per share
  $ 5.44     $ 2.05     $ .98  

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



(In thousands)

BALANCE, January 1, 2009
  $ 422     $ 11,693     $ 69,646     $ 81,761  
Net earnings
    -       -       4,149       4,149  
Dividends paid on common stock
    -       -       (2,109 )     (2,109 )
BALANCE, December 31, 2009
  $ 422     $ 11,693     $ 71,686     $ 83,801  
Net earnings
    -       -       8,631       8,631  
Dividends paid on common stock
    -       -       (2,277 )     (2,277 )
BALANCE, December 31, 2010
  $ 422     $ 11,693     $ 78,040     $ 90,155  
Net earnings
    -       -       22,931       22,931  
Dividends paid on common stock
    -       -       (2,404 )     (2,404 )
BALANCE, December 31, 2011
  $ 422     $ 11,693     $ 98,567     $ 110,682  

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



(In thousands)

Years Ended December 31,
Net earnings
  $ 22,931     $ 8,631     $ 4,149  
Adjustments to reconcile net earnings to net cash
from operating activities-
Depreciation, depletion and amortization
    16,260       11,817       10,320  
Property sale (gains) losses
    (4,394 )     94       (177 )
Dry hole costs incurred
    1,212       1,894       661  
Impairment of oil and natural gas properties
    14,749       2,224       3,773  
Provision for doubtful accounts
    1,141       29       430  
Deferred income taxes
    7,308       3,699       1,072  
Net change in fair value contracts
    (97 )     (1,036 )     251  
Decrease (increase) in accounts receivable
    (45,487 )     (34,257 )     (36,515 )
Decrease (increase) in inventories
    (5,598 )     669       (1,053 )
Decrease (increase) in income tax receivable
    1,836       (145 )     1,458  
Decrease (increase) in prepayments
    (2,547 )     2,700       (5,580 )
Increase (decrease) in accounts payable
    47,662       40,521       43,069  
Increase (decrease) in accrued and other liabilities
    1,378       (406 )     (58 )
Other changes, net
    (539 )     494       485  
Net cash provided by operating activities
    55,815       36,928       22,285  
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 )
Dividend payments
    (2,404 )     (2,277 )     (2,109 )
Net cash (used in) financing activities
    (2,404 )     (2,277 )     (2,109 )
Increase (decrease) in cash and cash equivalents
    8,034       12,226       (1,402 )
Cash and cash equivalents at beginning of year
    29,032       16,806       18,208  
Cash and cash equivalents at end of year
  $ 37,066     $ 29,032     $ 16,806  

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




(1)  Summary of Significant Accounting Policies

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Adams Resources & Energy, Inc., a Delaware corporation, and its wholly owned subsidiaries (the "Company") after elimination of all  intercompany accounts and transactions.  The impact on the accompanying financial statements of events occurring after December 31, 2011 has been evaluated through the date of issuance of these financial statements.

Nature of Operations

The Company is engaged in the business of crude oil, natural gas and petroleum products marketing, as well as tank truck transportation of liquid chemicals and oil and gas exploration and production.  Its primary area of operation is within a 1,000 mile radius of Houston, Texas.

Cash and Cash Equivalents

Cash and cash equivalents include any Treasury bill, commercial paper, money market fund or federal funds with maturity of 90 days or less.  Depending on cash availability and market conditions, investments in corporate and municipal bonds, which are classified as investments in marketable securities, may also be made from time to time.  Cash and cash equivalents are maintained with major financial institutions and such deposits may exceed the amount of federally backed insurance provided.  While the Company regularly monitors the financial stability of such institutions, cash and cash equivalents ultimately remain at risk subject to the financial viability of such institutions.

Marketable Securities

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

Allowance for Doubtful Accounts

Accounts receivable result from sales of crude oil, natural gas and refined products as well as from trucking services.  Marketing business wholesale level sales of crude oil and natural gas comprise in excess of 90 percent of accounts receivable and under industry practices, such items are “settled” and paid in cash within 25 days of the month following the transaction date.  For such receivables, an allowance for doubtful accounts is determined based on specific account identification.  The balance of accounts receivable results primarily from sales of refined petroleum products and trucking services.  For this component of receivables, the allowance for doubtful accounts is determined based on a review of specific accounts combined with a review of the general status of the aging of all accounts.




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

December 31,
Crude oil
  $ 18,464     $ 12,909  
Petroleum products
    1,725       1,682  
    $ 20,189     $ 14,591  


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

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

Property and Equipment

Expenditures for major renewals and betterments are capitalized, and expenditures for maintenance and repairs are expensed as incurred.  Interest costs incurred in connection with major capital expenditures are capitalized and amortized over the lives of the related assets. When properties are retired or sold, the related cost and accumulated depreciation, depletion and amortization ("DD&A") is removed from the accounts and any gain or loss is reflected in earnings.

Oil and gas exploration and development expenditures are accounted for in accordance with the successful efforts method of accounting.  Direct costs of acquiring developed or undeveloped leasehold acreage, including lease bonus, brokerage and other fees, are capitalized. Exploratory drilling costs are initially capitalized until the properties are evaluated and determined to be either productive or nonproductive.  Such evaluations are made on a quarterly basis.  If an exploratory well is determined to be nonproductive, the costs of drilling the well are charged to expense. Costs incurred to drill and complete development wells, including dry holes, are capitalized.  As of December 31, 2011, the Company had no unevaluated or suspended exploratory drilling costs.

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



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

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

Producing Properties
Subject to Fair
Value Impairment
Net book value at January 1
  $ 8,704     $ 2,220  
Property additions