10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

(Mark One)

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

For the Fiscal Year ended December 31, 2013

OR

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

Commission File Number 1-7908

ADAMS RESOURCES & ENERGY, INC.

(Exact name of registrant as specified in its charter)

Delaware	74-1753147	17 South Briar Hollow Lane  Suite 100	77027
		Houston, Texas
(State of Incorporation)	(I.R.S. Employer Identification No.)	(Address of Principal executive offices)	(Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act:

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

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”, ‟accelerated filer” and ‟smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ____                                                                Accelerated filer     X   

Non-accelerated filer ____                                                      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 28, 2013 was $144,823,864 based on the closing price of $68.89 per one share of common stock as reported on the NYSE MKT for such date.  A total of 4,217,596 shares of Common Stock were outstanding at March 1, 2014.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held May 14, 2014 are incorporated by reference into Part III of this report.

PART I

Forward-Looking Statements –Safe Harbor Provisions

This annual report on Form 10-K for the year ended December 31, 2013 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 (the ‟SEC”) 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.

Items 1 and 2.  BUSINESS AND PROPERTIES

Business Activities

Adams Resources & Energy, Inc. (‟ARE”), a Delaware corporation organized in 1973, and its subsidiaries (collectively, the ‟Company”), are engaged in the business of crude oil marketing, tank truck transportation of liquid chemicals, and oil and gas exploration and production.    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, 2013 are set forth in Note (8) to the 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 North Dakota. Gulfmark operates 187 tractor-trailer rigs and maintains over 55 pipeline inventory locations or injection stations.  Gulfmark has the ability to barge oil from four oil storage facilities along the intercoastal waterway of Texas and Louisiana and maintains 356,000 barrels of storage capacity at the dock facilities in order to access waterborne markets for its products. During 2013, Gulfmark purchased approximately 106,000 barrels per day of crude oil at the wellhead or lease level. 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 2013, Gulfmark had sales to four customers that comprised 18.5 percent, 17.7 percent, 15.8 percent and 10.4 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.

1

Operating results for the marketing segment 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 299 truck tractors of which 13 are independent owner-operator units and owns 480 tank trailers.  In addition, STC operates 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 527 wells of which 36 are Company operated.

Producing Wells--The following table sets forth the Company’s gross and net productive wells as of December 31, 2013. Gross wells are the total number of wells in which the Company has an interest, while net wells are the sum of the fractional interests owned.

	Oil Wells				Gas Wells				Total Wells
	Gross		Net		Gross		Net		Gross		Net
Texas		209		6.80		179		14.06		388		20.86
Other		94		4.10		45		4.82		139		8.92
		303		10.90		224		18.88		527		29.78

2

Acreage--The following table sets forth the Company’s gross and net developed and undeveloped acreage as of December 31, 2013.  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, production from non-owned shallow wells, or other contractual provisions delaying termination of leasehold rights.   The Company’s ownership in undeveloped acreage is substantially all in the form of a non-operated minority interest.  As such, the Company relies on the third party operator to manage the lease holdings.

	Developed Acreage				Undeveloped Acreage
	Gross		Net		Gross		Net
Texas		162,432		11,543		173,737		16,076
Kansas		889		45		16,283		814
Other		5,943		872		7,451		1,644
		169,264		12,460		197,471		18,534

Drilling Activity--The following table sets forth the Company’s drilling activity for each of the three years ended December 31, 2013.  All drilling activity was onshore in Texas, Louisiana, Arkansas and Kansas.

	2013				2012				2011
	Gross		Net		Gross		Net		Gross		Net
Exploratory wells drilled
- Productive		-		-		-		-		-		-
- Dry		3		.38		-		-		8		.87
Development wells drilled
- Productive		77		1.40		109		2.40		75		2.10
- Dry		-		-		-		-		3		.18
		80		1.78		109		2.40		86		3.15

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, 2013, are presented in the table below (in thousands):

	December 31,
	2013		2012		2011
Crude oil (thousands of barrels)		368		307		292
Natural gas (thousands of mcf)		6,286		8,837		9,661
Standardized measure of discounted future
net cash flows from oil and natural gas  reserves	$	17,836	$	16,355	$	20,931

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, 2013, 2012 and 2011 are based on market prices of $94.99, $93.85 and $95.85 per barrel for crude oil and $4.69, $3.51 and $4.69 per mcf for natural gas, respectively.  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 SEC regulations.  The price reported in reserve disclosures for natural gas for 2013 and 2012 includes the value of associated natural gas liquids.

3

Reserve estimates are based on many subjective factors.  The accuracy of these estimates depends on the quantity and quality of geological data, production performance data, 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 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 reserve valuations do not necessarily portray a realistic assessment of current value or future performance of such properties. These 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 calculations.  Also, certain assumptions have been made with respect to pricing. The estimates assume prices will remain constant from the date of the engineer’s assessment, 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 net oil and natural gas production for the three years ended December 31, 2013 was as follows:

Years Ended	Crude Oil		Natural
December 31,	(barrels)		Gas (mcf)
2013		102,300		1,608,000
2012		98,100		2,608,000
2011		61,500		1,895,000

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

	Years Ended December 31,
	2013		2012		2011
Average oil and condensate
sales price per barrel	$	79.15	$	84.39	$	93.23
Average natural gas
sales price per mcf	$	3.75	$	2.94	$	4.39
Average production cost, per equivalent
barrel, charged to expense	$	15.54	$	13.14	$	16.79

The Company 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.

4

-   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.

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 thereof, and (iii) protect public safety and the environment from oilfield waste, including the 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 and recovery of damages for injury to air, water or property as well as 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.

5

Trucking Activities --The Company’s marketing and transportation businesses operate truck fleets pursuant to authority of the DOT and various state authorities.  Trucking operations must be conducted in accordance with various laws relating to pollution and environmental control as well as safety requirements prescribed by states and the DOT. Matters such as weight and dimension of equipment are also subject to federal and state regulations.  These 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 requirements 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 private and 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 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.  See “Item 1A. Risk Factors – Environmental liabilities and environmental regulations may have an adverse effect on the Company.”  At December 31, 2013, the Company is unaware of any unresolved environmental issues for which additional accounting accruals are necessary.

Employees

At December 31, 2013, the Company employed 821 persons, 14 of whom were employed in the exploration and production of oil and gas, 365 in the marketing of crude oil, 424 in transportation operations, and 18 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.

6

Available Information

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

The Company maintains a corporate website at http://www.adamsresources.com, on which investors may access free of charge the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports as soon as is reasonably practicable after filing or furnishing such material with the SEC.  Additionally, the Company has adopted and posted on its website a Code of Business Ethics designed to reflect requirements of the Sarbanes-Oxley Act of 2002, NYSE MKT 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, Suite 100

Houston, Texas 77027

Item 1A. RISK FACTORS

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

Potential disruptions in the credit markets and concerns about global economic growth could have a significant adverse impact on global financial markets and commodity prices.  Such factors could contribute to a decline in the Company’s stock price and corresponding market capitalization.  Should commodity prices experience a period of rapid decline, future earnings will be reduced.  Since the Company has no bank debt obligations nor covenants tied to its stock price, potential declines in the Company’s stock price do not affect the Company’s liquidity or overall financial condition.  Should the capital and credit markets experience volatility and the availability of funds become 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 may be adverse to the Company’s transportation operation since it tends to suppress export demand for petrochemicals.  Conversely, a weak U.S. dollar exchange rate tends to stimulate export demand for petrochemicals.

7

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, the 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 and results of operations could be adversely affected by non-performance 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, contractual defaults 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  approximately 500 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 adverse 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 that 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:

8

·   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 marketing operation purchases initial production of crude oil 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 exploration and production of crude oil and natural gas 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.

9

Consistent with the industry standard, the Company’s insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage provided 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, 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 state legislators and the U.S. Congress that, if implemented, would either prohibit the practice of hydraulic fracturing or subject the process to regulation under state regulation or 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.  This 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 state or 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 requiring significant interpretations 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.

10

The Company’s exploration operations are 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.  Absent ongoing 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 is dependent upon an assessment of recoverable reserves, future oil and natural gas prices and operating costs, potential environmental and other liabilities, and other factors. These factors 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, price controls or mechanical difficulties.  In the future, the cost to find or acquire additional reserves may become prohibitive.

Oil and gas segment revenues are dependent on the ability to successfully complete drilling activity.

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

·   lack of acceptable prospective acreage;

·   inadequate capital resources;

·   weather;

·   title problems;

·   compliance with governmental regulations; and

·   mechanical difficulties.

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

Security issues exist relating to drivers, equipment and terminal facilities.

The Company transports liquid combustible materials including petrochemicals, and such materials may be a target for terrorist attacks.  While the Company employs a variety of security measures to mitigate risks, 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 certain administrative and civil legal proceedings as part of 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.

11

The Company is subject to risks associated with climate change.

Potential climate change and efforts to regulate ‟greenhouse gas” (‟GHG’s”) emissions have the potential to adversely affect the Company’s business including negatively impacting 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.  In addition, the demand for and consumption of its products and services (due to change in both costs and weather patterns), and the economic health of the regions in which the Company operates, 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.  Such breaches 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.

Item 1B. UNRESOLVED STAFF COMMENTS

None.

Item 3.  LEGAL PROCEEDINGS

During 2013 and continuing in 2014, AREC has been noticed as a defendant in a number of Louisiana based suits involving alleged environmental contamination from prior drilling operations.  Such suits typically allege improper disposal of oilfield wastes in earthen pits with one suit alleging subsidence contributing of the formation of a sink hole.  The Company is currently named as a defendant in four such suits.  The suits are styled LePetit Chateau Deluxe v. Adams Resources Exploration Corporation dated March 2004, Gustave J. LaBarre, Jr., et. al. v. Adams Resources Exploration Corporation et al dated October 2012, Edward Conner, et al v. Adams Resources Exploration Corporation dated October 2013 and Henning Management, LLC v. Adams Resources Exploration Corporation dated November 2013.  Each suit involves multiple industry defendants with substantially larger proportional interest in the properties.  The plaintiffs in each of these matters are seeking unspecified compensatory and punitive damages.    While management does not believe that a material adverse effect will result from the claims, significant attorney fees will be incurred to defend this item.  As of December 31, 2013, the Company has accrued $200,000 of future legal costs for these matters.

12

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

Item 4.  MINE SAFETY DISCLOSURES

Not Applicable.

13

PART II

Item 5. MARKET FOR THE REGISTRANT’S COMMON STOCK, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

The Company’s common stock is traded on the NYSE MKT 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 MKT for each calendar quarter since January 1, 2012.

	American Stock Exchange
	High		Low
2013
First Quarter	$	55.82	$	33.75
Second Quarter		70.80		43.00
Third Quarter		71.77		54.86
Fourth Quarter		70.01		47.46
2012
First Quarter	$	75.13	$	29.20
Second Quarter		74.73		27.85
Third Quarter		47.33		30.00
Fourth Quarter		36.20		28.10

At February 14, 2014 there were approximately 217 shareholders of record of the Company’s common stock and the closing stock price was $67.10 per share.  The Company has no securities authorized for issuance under equity compensation plans.  The Company made no repurchases of its stock during 2013 and 2012.

On December 17, 2012, the Company paid an annual cash dividend of $.62 per common share to its common stockholders.  On each of June 17, 2013, September 17, 2013 and December 16, 2013 the Company paid quarterly cash dividend of $.22 per common share to common its stockholders.  Such dividends totaled $2,614,954 and $3,027,841 for 2012 and 2013, respectively.

14

Performance Graph

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

1.   $100.00 was invested on December 31, 2008 in the Company’s common stock, the S&P 500 Index, and the S&P 500 Integrated Oil and Gas Index.

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

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

	12/08	12/09	12/10	12/11	12/12	12/13
Adams Resources & Energy, Inc.	100.00	132.70	149.73	183.26	224.99	444.24
S&P 500	100.00	126.46	145.51	148.59	172.37	228.19
S&P Integrated Oil & Gas	100.00	98.71	117.31	134.64	137.61	167.24

15

Item 6.  SELECTED FINANCIAL DATA

SELECTED FINANCIAL DATA

	Years Ended December 31,
	2013			2012			2011			2010			2009
	(In thousands, except per share data)
Revenues:
Marketing	$	3,863,057		$	3,292,948		$	2,961,176		$	2,005,301		$	1,770,600
Transportation		68,783			67,183			63,501			56,867			44,895
Oil and natural gas		14,129			15,954			14,060			11,021			8,650
	$	3,945,969		$	3,376,085		$	3,038,737		$	2,073,189		$	1,824,145
Operating earnings (loss):
Marketing	$	40,369		$	46,145		$	49,237		$	13,530		$	15,404
Transportation		5,180			10,253			8,521			6,623			2,128
Oil and gas operations		(2,113	)		(5,835	)		(16,797	)		(1,801	)		(3,791	)
Oil and gas property sale		-			2,203			2,923			-			-
General and administrative		(9,060	)		(8,810	)		(8,678	)		(7,858	)		(8,260	)
		34,376			43,956			35,206			10,494			5,481
Other income (expense):
Interest income		198			190			237			191			125
Interest expense		(24	)		(10	)		(8	)		(36	)		(25	)
Earnings (loss) from continuing operations
before income taxes		34,550			44,136			35,435			10,649			5,581
Income tax (provision) benefit		(12,429	)		(16,664	)		(12,717	)		(3,352	)		(2,030	)
Earnings (loss) from continuing
operations		22,121			27,472			22,718			7,297			3,551
Earnings (loss) from discontinued
operations, net of taxes		(511	)		319			213			1,334			598
Net earnings (loss)	$	21,610		$	27,791		$	22,931		$	8,631		$	4,149
Earnings (Loss) Per Share
From continuing operations		5.24			6.51			5.39			1.73			.84
From discontinued operations		(.12	)		.08			(.05	)		.32			.14
Basic and diluted earnings (loss) per share	$	5.12		$	6.59		$	5.34		$	2.05		$	.98
Dividends per common share	$	.66		$	.62		$	.57		$	.54		$	.50
Financial Position
Cash	$	60,733		$	47,239		$	37,066		$	29,032		$	16,806
Net working capital		79,561			58,474			48,871			39,978			38,372
Total assets		448,082			419,501			378,840			301,305			249,401
Long-term debt		-			-			-			-			-
Shareholders’ equity		154,685			135,858			110,682			90,155			83,801
Dividends on common shares		2,783			2,615			2,404			2,277			2,109

________________________________

Notes:

-   In 2012 and 2011, certain oil and natural gas producing properties were sold for $3.6 million and $6.6 million producing net gains of $2.2 million and $2.9 million, respectively.

-   The 2013, 2012 and 2011 oil and gas operating losses include property impairments totaling $2.6 million, $4.7 million and $14.8 million, respectively, recorded following unfavorable drilling results in 2013 and declining natural gas prices in 2012 and 2011.

16

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

Results of Operations

- Crude Oil

Crude oil marketing revenues, operating earnings, depreciation and certain costs are as follows (in thousands):

	2013		2012		2011
Revenues	$	3,863,057	$	3,292,948	$	2,961,176
Operating earnings	$	40,369	$	46,145	$	49,237
Depreciation	$	7,682	$	5,945	$	3,724
Driver commissions	$	19,478	$	15,151	$	12,284
Insurance	$	7,659	$	5,241	$	4,262
Fuel	$	13,808	$	11,617	$	9,982

Supplemental volume and price information:

	2013		2012		2011
Field Level Purchases per day (1)
Crude Oil – barrels		106,000		89,200		81,600
Average Purchase Price
Crude Oil – per barrel	$	99.57	$	99.66	$	96.77

(1)Reflects the volume purchased from third parties at the field level of operations.

Crude oil revenues increased in 2013 relative to 2012 and in 2012 relative to 2011 consistent with increased field level purchase volumes as shown in the table above.  Volume increases resulted from new production established by the Company’s customer base in the Eagle Ford shale trend of South Texas beginning in 2011, coupled with a new area of operation established in the Bakken field of North Dakota during 2013.

-   Crude Oil – Field Level Operating Earnings (Non GAAP Measure)

Two significant factors affecting comparative crude oil segment operating earnings are inventory valuations and forward commodity contract (derivatives or mark-to-market) valuations.  As a purchaser and shipper of crude oil, the Company holds inventory in storage tanks and third-party pipelines.  Inventory sales turnover occurs approximately every three days, but the quantity held in stock at the end of a given period is reasonably consistent.  As a result, during periods of increasing crude oil prices, the Company recognizes inventory liquidation gains while during periods of falling prices, the Company recognizes inventory liquidation and valuation losses.  Over time, these gains and losses tend to offset and have limited impact on cash flow.  While crude oil prices fluctuated during 2013 and 2012, the net impact yielded inventory valuation losses totaling $3,824,000 and $1,596,000, respectively as compared to inventory liquidation gains totaling $3,021,000 for 2011.    As of December 31, 2013, the Company held 306,633 barrels of crude oil inventory at a composite average price of $90.06 per barrel.

17

Crude oil marketing operating earnings are also affected by the valuations of the Company’s forward month commodity contracts (derivative instruments) as of the various report dates.  Such non-cash valuations are calculated and recorded at each period end based on the underlying data existing as of such date.  The Company generally enters into these derivative contracts as part of a pricing strategy based on crude oil purchases at the wellhead (field level).  Only those contracts qualifying as derivative instruments are accorded fair value treatment while the companion contracts to purchase crude oil at the wellhead (field level) are not accorded fair value treatment.  The valuation of derivative instruments at period end requires the recognition of ‟mark-to-market” gains and losses.  The impact on crude oil segment operating earnings of inventory liquidations and derivative valuations is summarized as follows (in thousands):

	2013		2012		2011
As reported segment operating earnings	$	40,369	$	46,145	$	49,237
Add (less) -
Inventory liquidation (gains) losses		3,824		1,596		(3,021	)
Derivative valuation (gains) losses		193		2,001		149
Field level operating earnings(1)	$	44,386	$	49,742	$	46,365

____________________________________

(1)   Such designation is unique to the Company and is not comparable to any similar measures developed by industry participants.

Field level operating earnings and field level purchase volumes (see earlier table) depict the Company’s day-to-day operation of acquiring crude oil at the wellhead, transporting the material, and delivering it to market at the sales point.  Comparative crude oil field level operating earnings decreased in 2013 relative to 2012 but increased in 2012 relative to 2011 with the noted volume additions and fluctuating unit margins for the comparative periods.  Unit margins initially began to widen during the third quarter of 2011 when South Texas sourced production started selling at a discount to world crude oil prices due to its relative abundance in relation to the infrastructure available to deliver such oil to market.  The initial burst in unit margins was most prevalent during the third quarter of 2011 with favorable unit margins continuing into 2012, and then diminishing in 2013 as competition and additional industry infrastructure development progressed in the region.  In addition, competitive pressure increased driver commission rates in 2013 and 2012 and a combination of higher mileage and deteriorating accident frequency increased insurance costs in 2013.  The Company anticipates continued volume growth from South Texas and North Dakota sourced production as these regions continue to develop, although competition should narrow margins.

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

18

- Transportation

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

	2013					2012					2011
	Amount		Change(1)			Amount		Change(1)			Amount		Change(1)
Revenues	$	68,783		2	%	$	67,183		6	%	$	63,501		12	%
Operating earnings	$	5,180		(49	)%	$	10,253		20	%	$	8,521		29	%
Depreciation	$	7,099		20	%	$	5,921		51	%	$	3,912		(9	)%
Driver commissions	$	13,152		3	%	$	12,773		3	%	$	12,369		6	%
Insurance	$	5,937		20	%	$	4,933		2	%	$	4,814		6	%
Fuel	$	14,813		2	%	$	14,516		-		$	14,519		35	%
Maintenance Expense	$	6,479		21	%	$	5,335		(8	)%	$	5,828		4	%

______________

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

Revenues for the transportation segment were consistent and strong for the comparative periods due to consistent customer demand.  Operating earnings for 2012 and 2011 benefitted from gains totaling $2.6 million and $1.2 million, respectively, from the sale of used equipment following the purchase of new truck replacements.  Such sales did not recur in 2013 within the transportation segment.  Operating earnings for 2013 were adversely impacted by increased depreciation, insurance and maintenance costs.  As shown above, maintenance expense increased in 2013, in part due to increased environmental compliance costs.

The Company’s customers predominately consist of the domestic petrochemical industry and contributing to customer demand is low natural gas prices (a basic feedstock cost for the petrochemical industry) and high export demand for petrochemicals.  With demand strength, industry capacity has been strained allowing rate increases and an opportunity for increased profitability.  However, an industry wide shortage of qualified drivers has affected the Company by suppressing current year revenues and results of operations.  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 $54 million.  Above that level, operating earnings will grow and below that level, losses result.

Transportation segment depreciation increased for 2013 and 2012 as older fully depreciated tractor units were replaced with new model year vehicles.  During 2013, the Company purchased 35 new trailers with 17 serving as replacements.  During 2012, the Company replaced 125 truck-tractors and one trailer.  During 2011 the Company replaced 115 older model truck-tractor units and added 10 new units to the fleet.  In addition, 25 trailers were added to the fleet during 2011.

19

- Oil and Gas

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

	2013						2012						2011
	Amount			Change(1)			Amount			Change(1)			Amount			Change(1)
Revenues	$	14,129			(11	)%	$	15,954			13	%	$	14,060			28	%
Operating earnings (loss)(2)		(2,113	)		42	%		(3,632	)		(74	)%		(13,874	)		689	%
Depreciation and depletion		7,494			(15	)%		8,848			7	%		8,249			77	%
Producing property impairments		1,373			(71	)%		4,699			(34	)%		7,105			651	%

______________

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

(2)   Includes gains from property sales of $2.2 million and $2.9 million in 2012 and 2011, respectively.

As shown in the table below, improving crude oil production volumes served to boost oil and gas segment revenues, with a partial offset occurring during 2013 as natural gas volumes declined.  Such volume changes resulting from the interplay of recent drilling efforts and normal production declines as low prices curtailed natural gas drilling.  Operating losses resulted in 2013, 2012 and 2011 following producing property impairments as well as increased prospect impairment expense as shown in the second table below.  Property impairments resulted in 2013 following adverse drilling results while 2012 and 2011 impairments followed declines in the then current and forward price for natural gas.

Comparative volumes and prices were as follows:

	2013			2012			2011
Production Volumes
- Crude oil		102,300	Bbls		98,100	Bbls		61,500	Bbls
- Natural gas		1,608,000	Mcf		2,608,000	Mcf		1,895,000	Mcf
Average Price
- Crude oil(1)	$	79.15	Bbls	$	84.39	Bbls	$	93.23	Bbls
- Natural gas	$	3.75	Mcf	$	2.94	Mcf	$	4.39	Mcf

___________________________

(1)   Crude oil prices and volumes include the sale of associated natural gas liquids production.

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

	2013		2012		2011
Dry hole expense	$	233	$	43	$	1,212
Prospect impairment		1,257		856		7,644
Seismic and geological		129		252		310
Total	$	1,619	$	1,151	$	9,166

20

During 2013, the Company participated in the drilling of 80 wells with three dry holes. Additionally, the Company had 34 wells in process on December 31, 2013 with ultimate evaluation anticipated during 2014.  Converting natural gas volumes to equate with crude oil volumes at a ratio of six to one, production volumes and proved reserve changes summarize as follows, on an equivalent barrel (Eq. Bbls) basis:

	2013			2012			2011
	(Eq. Bbls.)			(Eq. Bbls.)			(Eq. Bbls.)
Proved reserves – beginning of year		1,779,000			1,907,000			1,566,000
Estimated reserve additions		267,000			537,000			1,209,000
Production volumes		(370,000	)		(533,000	)		(377,000	)
Producing properties sold		(5,000	)		(71,000	)		(385,000	)
Revisions of previous estimates		(255,000	)		(61,000	)		(106,000	)
Proved reserves - end of year		1,416,000			1,779,000			1,907,000

For 2013 and for the three year period ended December 31, 2013, estimated reserve additions represented 157 percent and 72 percent, respectively, of production volumes.  Such reserve additions resulted from active drilling efforts during the periods presented.

Given the present low natural gas price environment, exploration and development activity during 2014 will be substantially reduced.  The Company’s current drilling and exploration efforts are primarily focused as follows:

West Texas Project

In 2008 the Company acquired an approximate 7.5% working interest in 49,015 gross acres located in Irion and Crockett Counties, Texas for the purpose of developing the Wolfcamp Shale.  A total of 190 wells have been drilled through December 31, 2013 with 177 wells on production and 13 wells being completed.  Drilling is expected to continue in 2014 with 31 wells scheduled for drilling.  Production from the Wolfcamp area is oil-rich with large amounts of gas and natural gas liquids.

South Texas Project

This investment’s goal is to extend the productive area of the Eagle Ford trend north in Fayette and Lavaca Counties, Texas.  Two wells have been drilled on this acreage indicating the project is on the gas-condensate window, but substantial Eagle Ford production has yet to be established.  Evaluation of this project continues and the Company holds a five percent working interest in this project which includes approximately 46,800 acres currently under lease.

Kansas

The Company presently holds a 6.8% interest in 30,000 acres in Pratt County, Kansas with the objective of further developing the Mississippi Lime trend.  One successful well has been completed on this acreage with a second well currently in process.  If warranted by results, approximately 10 additional horizontal well sites can be developed on this acreage.

In addition to current active drilling efforts, the Company maintains a fractional interest in approximately 142,163 acres in the East Texas – Haynesville trend.  The Haynesville program is a natural gas development play with the Company’s interest currently held by production and to date, the Company has participated in 93 wells on this acreage.  Further development of this property is contingent on increased natural gas prices.

21

 - Oil and gas property sales

In 2012, the Company sold, to third parties, its interest in two separate oil and gas producing properties.  One of the properties was located on-shore Texas with the second property located in Federal waters offshore Louisiana.  Proceeds from these two sales totaled $3,049,000 and the Company recorded a $1,728,000 pre-tax gain.  Since both properties had depleted substantially from their initial productive period, the sales were consummated before the properties lost further value.  Additionally in 2012, the Company sold to a third party fifty percent of its interest in certain Kansas oil and gas properties with the sale consummated to spur further development on the properties.  Total proceeds were $578,000 and the Company recorded a $475,000 pre-tax gain on sale.  The Company continues to participate in the development of these Kansas properties.

In 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.  Sales negotiations were conducted by the third party operator of the properties and the Company elected to participate in the sale due to attractive pricing.  Also during 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.    Further in 2011, the Company sold an interest in certain non-producing properties for $90,000 in proceeds and gain.

-   General and administrative expense, interest income and income tax

General and administrative expenses were generally consistent during the periods presented with elevated costs in 2013, 2012 and 2011 due to employee bonuses, consistent with increased corporate earnings.  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.

- Discontinued operations

Effective October 31, 2013 and due to inadequate earnings, the Company completed an orderly wind-down and closure of its natural gas marketing segment.  The Company incurred employee severance and other shut-down costs totaling $416,000 as a result of this event.  All obligations were satisfied and no further matters are anticipated.  During the first quarter of 2012, the Company sold contracts, inventory and certain equipment associated with its former refined products marketing segment and discontinued that operation.  The pre-tax gain from this sale, net of first quarter 2012 operating expenses and wind-down cost totaled $808,000.  See also Note 9 – Discontinued Operations to Unaudited Condensed Consolidated Financial Statements.

- Outlook

Crude oil marketing operations anticipate steady volume growth but competition continues to narrow unit margins by as much as one-third and an operating earnings decline is anticipated for 2014.  Demand for transportation services remains strong but driver shortages and persistently high operating cost has dampened profitability within this segment.  For the oil and gas segment, growth in production volumes should lead to continued earnings improvement especially if 2014 price increases in natural gas prices are sustained.

The Company has the following major objectives for 2014:

-   Manage declining marketing margins to maintain operating earnings at the $30 million level exclusive of inventory valuation gains or losses.

-   Maintain transportation operating earnings at the $5 million level.

-   Grow oil and gas operating earnings to the $2 million level.

22

Liquidity and Capital Resources

The Company’s liquidity primarily derives from net cash provided from operating activities, which was $43,976,000, $54,494,000 and $55,815,000 for each of 2013, 2012 and 2011, respectively.  As of December 31, 2013 and 2012, the Company had no bank debt or other forms of debenture obligations.  Cash and cash equivalents totaled $60,733,000 as of December 31, 2013, 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 $79,561,000 as of December 31, 2013.  The Company relies on its ability to obtain open-line trade credit from its suppliers especially with respect to its crude oil marketing operation.  In this regard, the Company generally maintains substantial cash balances and avoids debt obligations.

Capital expenditures during 2013 included $14,508,000 for marketing and transportation equipment additions, primarily consisting of truck-tractors, and $13,094,000 in property additions associated with oil and gas exploration and production activities.  For 2014, the Company anticipates expending an additional approximately $10 million on oil and gas development and exploration projects.  In addition, approximately $3 million will be expended during 2014 primarily for the purchase of 30 trailers for the transportation segment and approximately $15 million will be expended by the crude oil marketing operation for the purchase of 42 truck-tractors, 51 trailers and the construction of a barge loading facility.  The truck-tractors will serve to replace older units and to increase the marketing fleet by 32 units.  Funding for these 2014 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.

At various times during each month, the Company makes cash prepayments and/or early payments in advance of the normal due date to certain suppliers of crude oil within the marketing operations.  Crude oil supply prepayments totaled $13,705,000 as of December 31, 2013 and such amounts will be recouped and advanced from month to month as the suppliers deliver product to the Company.  In addition, in order to secure crude oil supply, the Company may also ‟early pay” its suppliers in advance of the normal payment due date of the twentieth of the month following the month of production.  Such ‟early payments” serve to reduce accounts payable as of the balance sheet date.  The Company also requires certain counterparties to make similar early payments or to post cash collateral with the Company in order to support their purchases from the Company.  Early payments received from customers serve to reduce accounts receivable as of the balance sheet date.  Such cash collateral held by the Company totaled $6,938,000 as of December 31, 2013.  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 suppliers of crude oil (see Note (1) to Consolidated Financial Statements).  The issuance of stand-by letters of credit enables the Company to avoid posting cash collateral when procuring crude oil supply.  As of December 31, 2013, letters of credit outstanding totaled $14.6 million.  The issued stand-by letters of credit are cancelled as the underlying purchase obligations are satisfied by cash payment when due.  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 marketing, transportation and exploration 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 $9.5 million commitment for 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 paid an annual dividend in the fourth quarter of each year, and the Company paid a $.62 per common share dividend or $2,615,000 to shareholders of record as of December 3, 2012.  On June 17, 2013, the Company initiated a quarterly dividend of $.22 per common share or $928,000.  A quarterly dividend of $.22 per common share or $928,000 was also paid during both the third and fourth quarters of 2013.  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 on Form 10-K).

23

Off-balance Sheet Arrangements

The Company maintains certain operating lease arrangements with independent truck owner-operators for use of their equipment and driver services 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, 2013, 2012, and 2011 was $8,281,000, $8,110,000 and $7,621,000, respectively.  As of December 31, 2013, rental commitments under long-term non-cancelable operating leases and terminal arrangements for the next five years are payable as follows:  2014 - $3,138,000; 2015 - $1,931,000; 2016 - $1,910,000; 2017 - $1,690,000; 2018 – $804,000 and $40,000 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 lease payment periods for contractual cash obligations is as follows (in thousands):

2014		2015		2016		2017		2018		Thereafter		Total
$	3,138	$	1,931	$	1,910	$	1,690	$	804	$	40	$	9,513

In addition to its lease obligations, the Company is also committed to purchase certain quantities of crude oil 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, 2013 are as follows (in thousands):

January		Remaining
2014		2014		2015		2016		Thereafter		Total
$	421,408	$	25	$	-	$	-	$	-	$	421,433

Insurance

From time to time, the marketplace for all forms of insurance enters into periods of severe cost increases. In the past, during such cyclical periods, the Company has seen costs escalate to the point where desired levels of insurance were either unavailable or unaffordable.  The Company’s primary insurance needs are workers’ compensation, automobile and umbrella coverage for its trucking fleet and medical insurance for employees.  During each of 2013, 2012 and 2011, insurance costs totaled $14.9 million, $11.5 million and $10.1 million, respectively with 2013 costs elevated due to adverse claims experience.  Insurance cost may experience rate increases during 2014 subject to market conditions and claims experience.  Since the Company is generally unable to pass on such cost increases, any increase will need to be absorbed by existing operations.

Competition

In all phases of its operations, the Company encounters strong competition from a number of entities. Many of these entities 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 as well as 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.

24

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 2013, 2012 and 2011.

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 that typically have durations of less than 18 months.  As of December 31, 2013, 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 accounts 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 these estimates depends on the quantity and quality of geological data, production performance data, 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 (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 calculations 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.

25

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 oil and natural gas properties. Estimated oil and natural gas reserve values also provide the standard for the Company’s periodic review of oil and natural gas properties for impairment.

Contingencies

During 2013 and continuing in 2014, AREC was noticed as a defendant in a number of Louisiana based lawsuits involving alleged environmental contamination from prior drilling operations.  Such suits typically allege improper disposal of oilfield wastes in earthen pits with one suit alleging oil and gas production subsidence contributing to the formation of a sink hole.  The Company is currently named as a defendant in four such suits.  Each suit involves multiple industry defendants with substantially larger proportional interest in the properties.  While management does not believe that a material adverse effect will result from the claims, significant attorney fees will be incurred to defend these items.  As of December 31, 2013, the Company has accrued $200,000 of future legal costs for these matters.

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 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) to 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 December 2011, the Financial Accounting Standards Board (‟FASB”) issued 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 Company adopted ASU 2011-11 effective January 1, 2013 and the adoption of ASU 2011-11 did not have a material impact on the Company’s consolidated financial statements, but additional disclosures regarding fair value measurements resulted.

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.

26

Item 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Interest Rate Risk

The Company had no long-term debt outstanding at December 31, 2013 and 2012.  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, 2013.

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, 2012 through December 31, 2013, the Company’s crude oil monthly average wholesale purchase costs ranged from an average low of $86.05 per barrel to a monthly average high of $113.10 per barrel during the same period. A hypothetical ten percent adverse change in average hydrocarbon prices, assuming no changes in volume levels, would have reduced earnings by approximately $4,173,000 and $3,937,000 for the comparative years ended December 31, 2013 and 2012, respectively.

27

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS

	Page
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM	29
FINANCIAL STATEMENTS:
Consolidated Balance Sheets as of December 31, 2013 and 2012	30
Consolidated Statements of Operations for the Years Ended
December 31, 2013, 2012 and 2011	31
Consolidated Statements of Shareholders’ Equity for the Years Ended
December 31, 2013, 2012 and 2011	32
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2013, 2012 and 2011	33
Notes to Consolidated Financial Statements	34

28

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Adams Resources & Energy, Inc.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Adams Resources & Energy, Inc. and subsidiaries (the "Company") as of December 31, 2013 and 2012, and the related consolidated statements of operations, shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2013. 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Adams Resources & Energy, Inc. and subsidiaries at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 13, 2014, expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/ Deloitte & Touche LLP

Houston, Texas

March 13, 2014

29

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands)

	December 31,
ASSETS	2013			2012
CURRENT ASSETS:
Cash and cash equivalents	$	60,733		$	47,239
Accounts receivable, net of allowance for doubtful accounts of
$252 and $206, respectively		243,930			228,415
Inventories		27,616			28,222
Fair value contracts		395			84
Income tax receivable		2,097			1,199
Prepayments		16,779			7,712
Current assets of discontinued operations		180			11,685
Total current assets		351,730			324,556
PROPERTY AND EQUIPMENT:
Marketing		52,996			46,177
Transportation		59,185			59,101
Oil and gas (successful efforts method)		98,947			90,431
Other		1,305			1,406
		212,433			197,115
Less – Accumulated depreciation, depletion and amortization		(120,568	)		(106,403	)
		91,865			90,712
OTHER ASSETS:
Deferred income tax asset		-			34
Cash deposits and other		4,487			4,199
	$	448,082		$	419,501
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	266,099		$	249,214
Accounts payable – related party		38			42
Fair value contracts		-			111
Accrued and other liabilities		5,583			6,959
Current deferred income taxes		358			240
Current liabilities of discontinued operations		91			9,516
Total current liabilities		272,169			266,082
LONG-TERM DEBT		-			-
OTHER LIABILITIES:
Asset retirement obligations		2,564			1,886
Deferred taxes and other liabilities		18,664			15,675
		293,397			283,643
COMMITMENTS AND CONTINGENCIES (NOTE 6)
SHAREHOLDERS’ EQUITY:
Preferred stock, $1.00 par value, 960,000 shares authorized,
none outstanding		-			-
Common stock, $.10 par value, 7,500,000 shares authorized,
4,217,596 issued and outstanding		422			422
Contributed capital		11,693			11,693
Retained earnings		142,570			123,743
Total shareholders’ equity		154,685			135,858
	$	448,082		$	419,501

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

30

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	Years Ended December 31,
	2013			2012			2011
REVENUES:
Marketing	$	3,863,057		$	3,292,948		$	2,961,176
Transportation		68,783			67,183			63,501
Oil and natural gas		14,129			15,954			14,060
		3,945,969			3,376,085			3,038,737
COSTS AND EXPENSES:
Marketing		3,815,006			3,240,858			2,908,215
Transportation		56,504			51,009			51,068
Oil and natural gas operations		8,748			12,941			22,608
Oil and natural gas property sale (gain)		-			(2,203	)		(2,923	)
General and administrative		9,060			8,810			8,678
Depreciation, depletion and amortization		22,275			20,714			15,885
		3,911,593			3,332,129			3,003,531
Operating Earnings		34,376			43,956			35,206
Other Income (Expense):
Interest income		198			190			237
Interest expense		(24	)		(10	)		(8	)
Earnings from continuing operations before income taxes		34,550			44,136			35,435
Income Tax (Provision) Benefit:
Current		(9,269	)		(11,286	)		(5,133	)
Deferred		(3,160	)		(5,378	)		(7,584	)
		(12,429	)		(16,664	)		(12,717	)
Earnings from continuing operations		22,121			27,472			22,718
Earnings (loss) from discontinued operations net of tax
(provision) benefit of $275, $(172) and $(114) respectively		(511	)		319			213
Net Earnings	$	21,610		$	27,791		$	22,931
EARNINGS PER SHARE:
From continuing operations		5.24			6.51			5.39
From discontinued operations		(.12	)		.08			.05
Basic and diluted net earnings per share	$	5.12		$	6.59		$	5.44
Dividends declared per common share	$	.66		$	.62		$	.57

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

31

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(In thousands)

								Total
	Common		Contributed		Retained			Shareholders’
	Stock		Capital		Earnings			Equity
BALANCE, January 1, 2011	$	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
Net earnings		-		-		27,791			27,791
Dividends paid on common stock		-		-		(2,615	)		(2,615	)
BALANCE, December 31, 2012	$	422	$	11,693		123,743			135,858
Net earnings		-		-		21,610			21,610
Dividends paid on common stock		-		-		(2,783	)		(2,783	)
BALANCE, December 31, 2013	$	422	$	11,693	$	142,570		$	154,685

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

32

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Years Ended December 31,
	2013			2012			2011
CASH PROVIDED BY OPERATIONS:
Net earnings	$	21,610		$	27,791		$	22,931
Adjustments to reconcile net earnings to net cash
from operating activities-
Depreciation, depletion and amortization		22,275			20,714			16,260
Property sale (gains)		(683	)		(6,298	)		(4,394	)
Dry hole costs incurred		233			43			1,212
Impairment of oil and natural gas properties		2,630			5,555			14,749
Provision for doubtful accounts		46			(51	)		1,141
Deferred income taxes		3,161			5,378			7,308
Net change in fair value contracts		(389	)		1,377			(97	)
Decrease (increase) in accounts receivable		(4,770	)		(4,820	)		(45,487	)
Decrease (increase) in inventories		606			(9,579	)		(5,598	)
Decrease (increase) in income tax receivable		(898	)		(719	)		1,836
Decrease (increase) in prepayments		(8,687	)		2,559			(2,547	)
Increase (decrease) in accounts payable		7,809			10,474			47,662
Increase (decrease) in accrued and other liabilities		(516	)		1,227			1,378
Other changes, net		1,549			843			(539	)
Net cash provided by operating activities		43,976			54,494			55,815
INVESTING ACTIVITIES:
Property and equipment additions		(27,602	)		(51,012	)		(53,276	)
Insurance and state collateral (deposits) refunds		(1,179	)		(582	)		(495	)
Proceeds from property sales		1,082			6,342			8,394
Proceeds from the sale of discontinued operations		-			3,546			-
Redemption of short-term investments		-			-			11,098
Investment in short-term investments		-			-			(11,098	)
Net cash (used in) investing activities		(27,699	)		(41,706	)		(45,377	)
FINANCING ACTIVITIES:
Dividend payments		(2,783	)		(2,615	)		(2,404	)
Net cash (used in) financing activities		(2,783	)		(2,615	)		(2,404	)
Increase (decrease) in cash and cash equivalents		13,494			10,173			8,034
Cash and cash equivalents at beginning of year		47,239			37,066			29,032
Cash and cash equivalents at end of year	$	60,733		$	47,239		$	37,066

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

33

ADAMS RESOURCES & ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)  Summary of Significant Accounting Policies

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Adams Resources & Energy, Inc., a Delaware corporation (‟ARE”) together with 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, 2013 were evaluated through the date of issuance of these financial statements.

Nature of Operations

The Company is engaged in the business of crude oil marketing, 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 trucking services.  Marketing business wholesale level sales of crude oil comprise in excess of 90 percent of accounts receivable and under industry practices, such items are ‟settled” and paid in cash within 20 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 trucking services.  For this component of receivables, the allowance for doubtful accounts is determined based on a review of specific accounts combined with a review of the general status of the aging of all accounts.

Inventories

Inventory consists of crude oil held in storage tanks and at third-party pipelines as part of the Company’s crude oil marketing operations.  Crude oil inventory is carried at the lower of average cost or market.

34

Prepayments

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

	December 31,
	2013		2012
Cash collateral deposits for commodity purchases	$	13,705	$	5,000
Insurance premiums		2,490		1,872
Rents, license and other		584		840
	$	16,779	$	7,712

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 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, 2013, 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, 2013, 2012 and 2011, there were $1,373,000, $4,699,000 and $7,105,000 respectively, of impairment provisions on producing oil and gas properties.

Fair value measurements for producing oil and gas properties that were subject to fair value impairment for the years ended December 31, 2013 and 2012 summarized as follows (in thousands):

	Producing Properties Subject to Fair Value Impairment
	2013			2012
Net book value at January 1	$	13,180		$	11,073
Property additions		5,661			13,083
Depletion taken		(3,727	)		(6,371	)
Impairment valuation loss		(1,373	)		(4,699	)
Net book at December 31	$	13,741		$	13,086

35

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

On a quarterly basis, management evaluates the carrying value of non-producing oil and gas leasehold properties and may deem them impaired based on remaining lease term, area drilling activity and the Company’s plans for the property.  This fair value measure depends highly on management’s assessment of the likelihood of continued exploration efforts in a given area and, as such, data inputs are categorized as ‟unobservable or Level 3” inputs.  Importantly, this fair value measure only applies to the write-down of capitalized costs and will never result in an increase to reported earnings.  Accordingly, impairment provisions on non-producing properties totaling $1,257,000, $856,000 and $7,644,000 were recorded for the years ending December 31, 2013, 2012 and 2011, respectively.  Capitalized costs for non-producing oil and gas leasehold interests currently represent approximately five percent of total oil and gas property costs and are categorized as follows (in thousands):

	December 31,		December 31,
	2013		2012
South Texas Project acreage	$	4,217	$	3,263
West Texas Project		116		180
Napoleonville Louisiana acreage		162		323
Other acreage areas		411		329
Total Non-producing Leasehold Costs	$	4,906	$	4,095

The South Texas, West Texas and Napoleonville acreage areas have active or scheduled drilling operations underway and holding the underlying acreage is essential to the ongoing exploration effort.  The ‟Other Acreage Areas” category consists of smaller onshore interests dispersed over a wide geographical area.  Since the Company is generally not the operator of its oil and gas property interests, it does not maintain underlying detail acreage data and is dependent on the operator when determining which specific acreage will ultimately be drilled.  However, the capitalized cost detail on a property-by-property basis is reviewed by management and deemed impaired if development is not anticipated prior to lease expiration.  Onshore leasehold periods are normally three years and may contain renewal options.  Capitalized cost activity on the ‟Other Acreage Areas” was as follows (in thousands):

	Leasehold Costs
	2013			2012
Net book value January 1	$	329		$	475
Property additions		304			810
Property sale		-			(100	)
Impairments		(222	)		(856	)
Net book value December 31	$	411		$	329

During 2012, the Company sold half of its interest in certain non-producing Kansas oil and gas properties.  Proceeds from the sale totaled $578,000 and the Company recorded a $475,000 pre-tax gain from this sale.  Also during 2012, the Company sold its interest in two oil and gas producing property units for total proceeds of $3,049,000.  The Company realized a $1,728,000 pre-tax gain from these two 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 2011 sale totaled $6.2 million and the pre-tax gain totaled $2,708,000.  Also during 2011, the Company sold a portion of its interest in certain non-producing oil and gas properties located in West Texas for $329,000 with a $125,000 pre-tax gain from this transaction.

During 2013, 2012 and 2011, the Company sold certain used trucks and equipment from its marketing and transportation segments and recorded pre-tax gains totaling $372,000, $2,482,000 and $1,246,000, respectively.

36

Cash Deposits and Other Assets

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

	December 31,
	2013		2012
Insurance collateral deposits	$	3,718	$	3,413
State collateral deposits		160		170
Materials and supplies		609		616
	$	4,487	$	4,199

Revenue Recognition

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

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

Certain crude oil contracts may be with a single counterparty to provide for similar quantities of crude oil to be bought and sold at different locations.  These contracts are entered into for a variety of reasons, including effecting the transportation of the commodity, to minimize credit exposure, and/or to meet the competitive demands of the customer.  Such buy/sell arrangements are reflected on a net revenue basis in the accompanying consolidated financial statements.  Reporting such crude oil contracts on a gross revenue basis would increase the Company’s reported revenues by $1,602,626,000, $1,381,352,000 and $1,812,561,000 for the years ended December 31, 2013, 2012 and 2011, respectively.

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

Letter of Credit Facility

The Company maintains a Credit and Security Agreement with Wells Fargo Bank to provide a $60 million stand-by letter of credit facility that is used to support the Company’s crude oil purchases within the marketing segment.  This facility is collateralized by the eligible accounts receivable within the segment and certain marketing and transportation equipment.  Stand-by letters of credit issued totaled $14.6 million and $21.9 million as of December 31, 2013 and 2012, respectively.  The issued stand-by letters of credit are cancelled as the underlying purchase obligations are satisfied by cash payment when due.  The letter of credit facility places certain restrictions on the Company’s Gulfmark Energy, Inc. subsidiary.  Such restrictions included the maintenance of a combined 1.1 to 1.0 current ratio and the maintenance of positive net earnings excluding inventory valuation changes, as defined, among other restrictions.  The Company is currently in compliance with all such financial covenants.

37

Statement of Cash Flows

Interest paid totaled $24,000, $10,000 and $8,000 during the years ended December 31, 2013, 2012 and 2011, respectively.  Income taxes paid during these same periods totaled $9,949,000, $12,650,000, and $5,597,000, respectively.  In addition, State and Federal income tax refunds totaled $4,000, $10,000 and $2,743,000 in 2013, 2012 and 2011, respectively.  Non-cash investing activities for property and equipment items included in accounts payable as of period end were $1,507,000, $2,419,000 and $4,070,000 as of December 31, 2013, 2012 and 2011, respectively.  There were no significant non-cash financing activities in any of the periods reported.

Earnings per Share

Earnings per share are based on the weighted average number of shares of common stock and potentially dilutive common stock shares outstanding during the period. The weighted average number of shares outstanding was 4,217,596 for 2013, 2012 and 2011.  There were no potentially dilutive securities during those periods.

Share-Based Payments

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

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates. Examples of significant estimates used in the accompanying consolidated financial statements include the oil and gas reserve volumes that form the foundation for calculating depreciation, depletion and amortization and estimating cash flows to assess impairment triggers and estimated values associated with oil and gas properties.  Other examples include revenue accruals, the provision for bad debts, insurance related accruals, income tax permanent and timing differences, contingencies, and valuation of fair value contracts.

Income Taxes

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

Use of Derivative Instruments

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

None of the Company’s derivative instruments have been designated as hedging instruments and the estimated fair value of forward month commodity contracts (derivatives) is reflected in the accompanying Consolidated Balance Sheet as of December 31, 2013 as follows (in thousands):

	Balance Sheet Location and Amount
	Current			Other		Current			Other
	Assets			Assets		Liabilities			Liabilities
Asset Derivatives
- Fair Value Commodity
Contracts at Gross Valuation	$	449		$	-	$	-		$	-
Liability Derivatives
- Fair Value Commodity
Contracts at Gross Valuation		-			-		54			-
Less Counterparty Offsets		(54	)		-		(54	)		-
As Reported Fair Value Contracts	$	395		$	-	$	-		$	-

As of December 31, 2013, one 100,000 barrel crude oil commodity put option and one commodity purchase and sale contract comprised the Company’s derivative valuations.  The purchase and sale contract encompasses approximately 175 barrels of crude oil per day in each of January and February 2014.

Forward month commodity contracts (derivatives) are reflected in the accompanying Consolidated Balance Sheet as of December 31, 2012 as follows (in thousands):

	Balance Sheet Location and Amount
	Current			Other		Current			Other
	Assets			Assets		Liabilities			Liabilities
Asset Derivatives
- Fair Value Commodity
Contracts at Gross Valuation	$	354		$	-	$	-		$	-
Liability Derivatives
- Fair Value Commodity
Contracts at Gross Valuation		-			-		381			-
Less Counterparty Offsets		(270	)		-		(270	)		-
As Reported Fair Value Contracts	$	84		$	-	$	111		$	-

As of December 31, 2012, three commodity purchase and sales contracts comprised substantially all of the Company’s derivative valuations.  Such contracts encompassed the purchase and sale of approximately 900 barrels of crude oil per day in January 2013 and continuing at 200 barrels per day through June 2013.

The Company only enters into commodity contracts with creditworthy counterparties or obtains collateral support for such activities.  As of December 31, 2013 and 2012, the Company was not holding nor had it posted any collateral to support its forward month fair value derivative activity. The Company is not subject to any credit-risk related trigger events.  The Company has no other financial investment arrangements that would serve to offset its derivative contracts.

Forward month commodity contracts (derivatives) are reflected in the accompanying Consolidated Statement of Operations for the years ended December 31, 2013, 2012 and 2011 as follows (in thousands):

	Gain (Loss)
Location	2013			2012			2011
Revenues – marketing	$	(193	)	$	(1,365	)	$	119

 Fair Value Measurements

The carrying amount reported in the consolidated balance sheet for cash and cash equivalents, accounts receivable and accounts payable approximates fair value because of the immediate or short-term maturity of these financial instruments.  Marketable securities are recorded at fair value based on market quotations from actively traded liquid markets.

38

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

Fair value estimates are based on assumptions that market participants would use when pricing an asset or liability and the Company uses a fair value hierarchy of three levels that prioritizes the information used to develop those assumptions.  Currently, for all items presented herein, the Company utilizes a market approach to valuing its contracts.  On a contract by contract, forward month by forward month basis, the Company obtains observable market data for valuing its contracts.  The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data.  The fair value hierarchy is summarized as follows:

Level 1 – quoted prices in active markets for identical assets or liabilities that may be accessed at the measurement date.  Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.  For Level 1 valuation of marketable securities, the Company utilizes market quotations provided by its primary financial institution and for the valuations of derivative financial instruments, the Company utilizes the New York Mercantile Exchange ‟NYMEX” for such valuations.

Level 2 – (a) quoted prices for similar assets or liabilities in active markets, (b) quoted prices for identical assets or liabilities but in markets that are not actively traded or in which little information is released to the public, (c) observable inputs other than quoted prices, and (d) inputs derived from observable market data.  Source data for Level 2 inputs include information provided by the NYMEX, published price data and indices, third party price survey data and broker provided forward price statistics.

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

As of December 31, 2013, the Company’s fair value assets and liabilities are summarized and categorized as follows (in thousands):

	Market Data Inputs
	Gross Level 1		Gross Level 2			Gross Level 3		Counterparty
	Quoted Prices		Observable			Unobservable		Offsets			Total
Derivatives
- Current assets	$	-	$	449		$	-	$	(54	)	$	395
- Current liabilities		-		(54	)		-		54			-
Net Value	$	-	$	395		$	-	$	-		$	395

As of December 31, 2012, the Company’s fair value assets and liabilities are summarized and categorized as follows (in thousands):

	Market Data Inputs
	Gross Level 1		Gross Level 2			Gross Level 3		Counterparty
	Quoted Prices		Observable			Unobservable		Offsets			Total
Derivatives
- Current assets	$	-	$	354		$	-	$	(270	)	$	84
- Current liabilities		-		(381	)		-		270			(111	)
Net Value	$	-	$	(27	)	$	-	$	-		$	(27	)

39

When determining fair value measurements, the Company makes credit valuation adjustments to reflect both its own nonperformance risk and its counterparty’s nonperformance risk.  When adjusting the fair value of derivative contracts for the effect of nonperformance risk, the impact of netting and applicable credit enhancements, such as collateral postings, thresholds, and guarantees are considered.  Credit valuation adjustments utilize Level 3 inputs, such as credit scores to evaluate the likelihood of default by the Company or its counterparties.  As of December 31, 2013 and 2012, credit valuation adjustments were not significant to the overall valuation of the Company’s fair value contracts.  As a result, fair value assets and liabilities are included in their entirety in the fair value hierarchy.

The following table illustrates the factors impacting the change in the net value of the Company’s fair value contracts for the year ended December 31, 2013 (in thousands):

	Level 1		Level 2
	Quoted Prices		Observable			Total
Net Fair Value January 1,	$	-	$	(27	)	$	(27	)
- Net realized (gains) losses		-		27			27
- Option deposit		-		615			615
- Net unrealized gains (losses)		-		(220	)		(220	)
Net Fair Value December 31,	$	-	$	395		$	395

The following table illustrates the factors impacting the change in the net value of the Company’s fair value contracts for the year ended December 31, 2012 (in thousands):

	Level 1		Level 2
	Quoted Prices		Observable			Total
Net Fair Value January 1,	$	-	$	1,338		$	1,338
- Net realized (gains) losses		-		(1,338	)		(1,338	)
- Net unrealized gains (losses)		-		(27	)		(27	)
Net Fair Value December 31,	$	-	$	(27	)	$	(27	)

Asset Retirement Obligations

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

	2013			2012
Balance on January 1,	$	1,886		$	1,568
-Liabilities incurred		431			358
-Accretion of discount		85			63
-Liabilities settled		(138	)		(103	)
-Revisions to estimates		300			-
Balance on December 31,	$	2,564		$	1,886

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

40

Recent Accounts Pronouncement

In December 2011, the Financial Accounting Standards Board (‟FASB”) issued 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 Company adopted ASU 2011-11 effective January 1, 2013 and the adoption of ASU 2011-11 did not have a material impact on the Company’s consolidated financial statements, but additional disclosures regarding fair value measurements resulted.

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

(2)  Income Taxes

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

	Years ended December 31,
	2013			2012			2011
Current:
Federal	$	(8,102	)	$	(10,282	)	$	(4,336	)
State		(892	)		(1,176	)		(1,187	)
		(8,994	)		(11,458	)		(5,523	)
Deferred:
Federal		(2,682	)		(4,940	)		(7,407	)
State		(478	)		(438	)		99
		(3,160	)		(5,378	)		(7,308	)
	$	(12,154	)	$	(16,836	)	$	(12,831	)

The following table summarizes the components of the income tax (provision) benefit (in thousands):

	Years ended December 31,
	2013			2012			2011
From continuing operations	$	(12,429	)	$	(16,664	)	$	(12,717	)
From discontinued operations		275			(172	)		(114	)
	$	(12,154	)	$	(16,836	)	$	(12,831	)

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

	Years ended December 31,
	2013			2012			2011
Statutory federal income tax (provision) benefit	$	(11,819	)	$	(15,619	)	$	(12,517	)
State income tax (provision) benefit		(891	)		(1,049	)		(707	)
Federal statutory depletion		522			36			393
Other		34			(204	)		-
	$	(12,154	)	$	(16,836	)	$	(12,831	)

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

41

	Years Ended December 31,
	2013			2012
Current deferred tax asset (liability)
Allowance for doubtful accounts	$	424		$	581
Prepaid and other insurance		(855	)		(815	)
Fair value contracts		73			(6	)
Net current deferred liability		(358	)		(240	)
Long-term deferred tax asset (liability)
Property		(18,964	)		(15,957	)
Uniform capitalization		613			552
Other		(283	)		(221	)
Net long-term deferred tax  liability		(18,634	)		(15,626	)
Net deferred tax liability	$	(18,992	)	$	(15,866	)

Financial statement recognition and measurement of positions taken, or expected to be taken, by an entity in its income tax returns must consider the uncertainty and judgment involved in the determination and filing of income taxes.  Tax positions taken in an income tax return that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the tax position will be examined by taxing authorities with full knowledge of all relevant information.  The Company has no significant unrecognized tax benefits.  Interest and penalties associated with income tax liabilities are classified as income tax expense.

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

	Earliest Open
	Tax Year
Federal	2010
Texas	2009
Louisiana	2010
Michigan	2010

(3)  Concentration of Credit Risk

Credit risk represents the amount of loss the Company would absorb if its customers failed to perform pursuant to contractual terms.  Management of credit risk involves a number of considerations, such as the financial profile of the customer, the value of collateral held, if any, specific terms and duration of the contractual agreement, and the customer’s sensitivity to economic developments.  The Company has established various procedures to manage credit exposure, including initial credit approval, credit limits, and rights of offset.  Letters of credit and guarantees are also utilized to limit credit risk. Accounts receivable associated with crude oil  marketing activities comprise approximately 90 percent of the Company’s total receivables and industry practice requires payment for such sales to occur within 20 days of the end of the month following a transaction.  The Company’s customer makeup, credit policies and the relatively short duration of receivables mitigate the uncertainty typically associated with receivables management.

42

The Company’s largest customers consist of large multinational integrated oil companies and independent domestic refiners of crude oil.  In addition, the Company transacts business with independent oil producers, major chemical concerns, crude oil trading companies and a variety of commercial energy users.  Within this group of customers, the Company generally derives approximately 50 percent of its revenues from three to four large crude oil refining concerns.  While the Company has ongoing established relationships with certain domestic refiners of crude oil, alternative markets are readily available since the Company supplies less than one percent of U. S. domestic refiner demand.  As a fungible commodity delivered to major Gulf Coast supply points, the Company’s crude oil sales can be readily delivered to alternative end markets.  Management believes that a loss of any of those customers where the Company currently derives more than 10 percent of its revenues would not have a material adverse effect on the Company’s operations.

The Company had revenues from four customers in 2013 that comprised 18.5 percent, 17.7 percent, 15.8 percent and 10.4 percent of total revenues, respectively.  During 2012, three customers comprised 20.2 percent, 17.9 percent and 16.8 percent of total revenues.  During 2011, four customers comprised 18.2 percent, 15.4 percent, 13.4 percent and 11.3 percent of total revenues.

The Company had accounts receivable from three customers that comprised 16.0 percent, 15.8 percent and 12.7 percent, respectively of total accounts receivables at December 31, 2013.  Three customers comprised 22.1 percent, 21.4 percent and 11.4 percent, respectively, of total accounts receivable as of December 31, 2012.  Two customers comprised 24.5 percent and 21.5 percent, respectively, of total accounts receivable at December 31, 2011.

An allowance for doubtful accounts is provided where appropriate and accounts receivable presented herein are net of allowances for doubtful accounts of $252,000 and $206,000 at December 31, 2013 and 2012, respectively.

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

	2013			2012			2011
Balance, beginning of year	$	206		$	357		$	180
Provisions for bad debts		147			-			276
Less:  Write-offs and recoveries		(101	)		(151	)		(99	)
Balance, end of year	$	252		$	206		$	357

(4)  Employee Benefits

The Company maintains a 401(k) savings plan for the benefit of its employees.  The Company’s contributory expenses for the plan were $674,000, $645,000 and $597,000 in 2013, 2012 and 2011, respectively. No other pension or retirement plans are maintained by the Company.

43

(5)  Transactions with Affiliates

The late Mr. K. S. Adams, Jr., former Chairman of the Board and certain of his family partnerships and affiliates have participated as working interest owners with the Company’s subsidiary, Adams Resources Exploration Corporation.  Mr. Adams and such affiliates participated on terms similar to those afforded other non-affiliated working interest owners. In recent years, such related party transactions generally resulted after the Company first identified oil and gas prospects of interest.  Typically the available dollar commitment to participate in such transactions was greater than the amount management was comfortable putting at risk.  In such event, the Company first determined the percentage of the transaction it wanted to obtain, which allowed a related party to participate in the investment to the extent there was excess available.  In those instances where there was no excess availability there was no related party participation.  Similarly, related parties were not required to participate, nor was the Company obligated to offer any such participation to a related or other party.  When such related party transactions occurred, they were individually reviewed and approved by the Audit Committee comprised of the independent directors on the Company’s Board of Directors.  During 2013 and 2012, the Company’s investment commitments totaled approximately $12 million and $22.7 million, respectively, in those oil and gas projects where a related party was also participating in such investments.  As of December 31, 2013 and 2012, the Company owed a combined net total of $38,000 and $42,000, respectively, to these related parties.  In connection with the operation of certain oil and gas properties, the Company also charges such related parties for administrative overhead primarily as prescribed by the Council of Petroleum Accountants Society Bulletin 5. Such overhead recoveries totaled $152,000, $152,000 and $145,000 for the years ended December 31, 2013, 2012, and 2011, respectively.

The Company also enters into certain transactions in the normal course of business with other affiliated entities including direct cost reimbursement for shared phone and secretarial services.  For the years ended December 31, 2013, 2012 and 2011, the affiliated entities charged the Company $69,000, $64,000 and $42,000, respectively, of expense reimbursement and the Company charged the affiliates $99,000, $98,000 and $118,000, respectively, for such expense reimbursements. In January 2012, the Company relocated its primary office lease space to a building operated by an affiliated entity.  The lease rental rate was determined by an independent appraisal.  Rental expense paid to the related party for 2013 and 2012 totaled $481,000 and $442,000, respectively.

(6)  Commitments and Contingencies

The Company maintains certain operating lease arrangements with independent truck owner-operators for use of their equipment and driver services 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.  All operating lease commitments qualify for off-balance sheet treatment.  Such contracts require certain minimum monthly payments for the term of the contracts.  Rental expense for the years ended December 31, 2013, 2012, and 2011 was $8,281,000, $8,110,000 and $7,621,000, respectively.  At December 31, 2013, commitments under long-term non-cancelable operating leases and terminal arrangements for the next five years and thereafter are payable as follows:   2014 - $3,138,000; 2015 - $1,931,000; 2016 - $1,910,000; 2017 - $1,690,000; 2018 - $804,000 and $40,000 thereafter.

Under the Company’s automobile and workers’ compensation insurance policies, the Company can either receive a return of premium paid or be assessed for additional premiums up to pre-established limits. Additionally  in certain instances the risk of insured losses is shared with a group of similarly situated entities.  The Company has appropriately recognized estimated expenses and liabilities related to these policies for losses incurred but not reported to the Company or its insurance carrier of $1,796,000 and $1,545,000 as of December 31, 2013 and 2012, respectively.

44

Effective January 1, 2012, the Company began a self-insurance program for managing employee medical claims.  On a monthly basis, the Company establishes a liability for expected claims incurred.  As claims are paid, the liability is relieved.  As of December 31, 2013 and 2012, accrued medical claims totaled $1,129,000 and $506,000, respectively.  The Company maintains third party insurance stop-loss coverage for annual individual medical claims exceeding $100,000.  In addition, the Company maintains $2 million of umbrella insurance coverage for aggregate medical claims exceeding approximately $4.5 million for the calendar years 2013 and 2014.

During 2013 and continuing in 2014, AREC has been noticed as a defendant in a number of Louisiana based suits involving alleged environmental contamination from prior drilling operations.  Such suits typically allege improper disposal of oilfield wastes in earthen pits with one suit alleging subsidence contributing of the formation of a sink hole.  The Company is currently named as a defendant in four such suits.  The suits are styled LePetit Chateau Deluxe v. Adams Resources Exploration Corporation dated March 2004, Gustave J. LaBarre, Jr., et. al. v. Adams Resources Exploration Corporation et al dated October 2012, Edward Conner, et al v. Adams Resources Exploration Corporation dated October 2013 and Henning Management, LLC v. Adams Resources Exploration Corporation dated November 2013.  Each suit involves multiple industry defendants with substantially larger proportional interest in the properties.  The plaintiffs in each of these matters are seeking unspecified compensatory and punitive damages.    While management does not believe that a material adverse effect will result from the claims, significant attorney fees will be incurred to defend this item.  As of December 31, 2013, the Company has accrued $200,000 of future legal costs for these matters.

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

(7)  Guarantees

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

As of December 31, 2013, parental guaranteed obligations are approximately as follows (in thousands):

	2014		2015		2016		2017		Thereafter		Total
Commodity purchases	$	78,747		-		-		-		-		78,747
Letters of credit		14,600		-		-		-		-		14,600
	$	93,347	$	-	$	-	$	-	$	-	$	93,347

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

45

(8)  Segment Reporting

The Company is engaged in the business of crude oil and natural gas marketing as well as tank truck transportation of liquid chemicals, and oil and gas exploration and production.  Information concerning the Company’s various business activities is summarized as follows (in thousands):

			Segment Operating			Depreciation Depletion and		Property and Equipment
	Revenues		Earnings (loss)			Amortization		Additions
Year ended December 31, 2013-
Marketing	$	3,863,057	$	40,369		$	7,682	$	11,343
Transportation		68,783		5,180			7,099		3,165
Oil and gas		14,129		(2,113	)		7,494		13,094
	$	3,945,969	$	43,436		$	22,275	$	27,602
Year ended December 31, 2012-
Marketing	$	3,292,948	$	46,145		$	5,945	$	12,391
Transportation		67,183		10,253			5,921		15,538
Oil and gas		15,954		(3,632	)(1)		8,848		23,083
	$	3,376,085	$	52,766		$	20,714	$	51,012
Year ended December 31, 2011-
Marketing	$	2,961,176	$	49,237		$	3,724	$	13,554
Transportation		63,501		8,521			3,912		14,118
Oil and gas		14,060		(13,874	)(1)		8,249		24,580
	$	3,038,737	$	43,884		$	15,885	$	52,252

__________________________________

(1) Oil and gassegment operating earnings include gains on property sales totaling $2,203,000 and $2,923,000 during 2012 and 2011, respectively.

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

	Years Ended December 31,
	2013			2012			2011
Segment operating earnings	$	43,436		$	52,766		$	43,884
- General and administrative expenses		(9,060	)		(8,810	)		(8,678	)
Operating earnings		34,376			43,956			35,206
- Interest income		198			190			237
- Interest expense		(24	)		(10	)		(8	)
Earnings from continuing operations before
income taxes and discontinued operations	$	34,550		$	44,136		$	35,435

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

	Years Ended December 31,
	2013		2012		2011
Marketing	$	306,693	$	277,920	$	253,817
Transportation		34,406		38,940		27,221
Oil and gas		37,093		35,788		29,105
Other		69,890		66,853		68,697
	$	448,082	$	419,501	$	378,840

46

Intersegment sales are insignificant and all sales occurred in the United States.  Other identifiable assets are primarily corporate cash, corporate accounts receivable, and properties not identified with any specific segment of the Company’s business.  Accounting policies for transactions between reportable segments are consistent with applicable accounting policies as disclosed herein.

(9)  Discontinued Operations

On February 27, 2012, the Company completed the sale of contracts, inventory and certain equipment associated with the refined products segment of its marketing business.  Revenues from this segment included in net earnings from discontinued operations totaled $25,717,000 and $169,412,000 for the years ended December 31, 2012 and 2011, respectively.  This business had experienced marginal results in recent years including an operating loss of $788,000 for the year 2011.  The Company received $2 million in cash proceeds plus a cash payment of $1,546,000 for the agreed value of refined product inventories on the date of sale.  The net gain recognized upon this sale totaled $1,622,000.  The Company conducted an orderly wind-down of the operation during 2012 and 2013 which primarily consisted of collecting outstanding accounts receivable and satisfying all existing obligations.  The Company’s fee interest in certain parcels of real estate was retained and the estimated fair value of such properties exceeded the Company’s cost basis in the properties.  Therefore, an impairment assessment of long-lived assets was not necessary.  The proceeds secured from this transaction exceeded the sum of carrying costs of the assets sold plus severance and other wind-down costs and, as a result, pre-tax earnings from this former segment totaled $398,000 for the year ended December 31, 2012.

Due to inadequate earnings, effective October 31, 2013, the Company completed an orderly wind-down and closure of its natural gas marketing segment.  Revenues from this segment included in net earnings from discontinued operations totaled $2,377,000, $4,879,000 and $6,251,000 for the years ended December 31, 2013, 2012 and 2011, respectively.  The Company incurred employee severance and other shut-down costs totaling $416,000 as a result of this event.  All obligations were satisfied and no further events are anticipated.

(10)  Quarterly Financial Data (Unaudited) -

Selected quarterly financial data and earnings per share of the Company are presented below for the years ended December 31, 2013 and 2012 (in thousands, except per share data):

				Earnings from
				Continuing Operations				Net Earnings				Dividends
		Revenues		Amount		Per Share		Amount		Per Share		Amount		Per Share
	2013 -
March 31		$	952,435	$	8,073	$	1.91	$	8,015	$	1.90	$	-	$	-
June 30			965,098		6,521		1.55		6,330		1.50		928		.22
September 30			1,060,340		7,238		1.72		7,156		1.70		927		.22
December 31			968,096		289		.06		109		.02		928		.22
Total		$	3,945,969	$	22,121	$	5.24	$	21,610	$	5.12	$	2,783	$	.66
	2012 -
March 31		$	875,905	$	5,944	$	1.41	$	6,575	$	1.56	$	-	$	-
June 30			830,110		5,333		1.26		5,386		1.28		-		-
September 30			794,404		8,355		1.98		8,263		1.96		-		-
December 31			875,666		7,840		1.86		7,567		1.79		2,615		.62
Total		$	3,376,085	$	27,472	$	6.51	$	27,791	$	6.59	$	2,615	$	.62

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

47

(11)Oil and Gas Producing Activities (Unaudited)

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

Oil and Gas Producing Activities -

Total costs incurred in oil and gas exploration and development activities, all incurred within the United States, were as follows (in thousands):

	Years Ended December 31,
	2013		2012		2011
Property acquisition costs
Unproved	$	1,444	$	1,965	$	3,591
Proved		-		-		-
Exploration costs
Expensed		1,619		1,151		9,166
Capitalized		-		-		-
Development costs		10,160		20,219		12,133
Total costs incurred	$	13,223	$	23,335	$	24,890

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

	December 31,
	2013			2012
Unproved oil and gas properties	$	7,578		$	8,349
Proved oil and gas properties		91,369			82,083
		98,947			90,432
Accumulated depreciation, depletion
and amortization		(64,169	)		(57,833	)
Net capitalized cost	$	34,778		$	32,599

Estimated Oil and Natural Gas Reserves  -

The following information regarding estimates of the Company’s proved oil and gas reserves, all located in Texas and the south central region of the United States, is based on reports prepared on behalf of the Company by its independent petroleum engineers. Because oil and gas reserve estimates are inherently imprecise and require extensive judgments of reservoir engineering data, they are generally less precise than estimates made in conjunction with financial disclosures. The revisions of previous estimates as reflected in the table below result from changes in commodity pricing assumptions and from more precise engineering calculations based upon additional production histories and price changes.

48

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

	Years Ended December 31,
	2013						2012						2011
	Natural						Natural						Natural
	Gas			Oil			Gas			Oil			Gas			Oil
	(Mcf’s)			(Bbls.)			(Mcf’s)			(Bbls.)			(Mcf’s)			(Bbls.)
Total proved reserves-
Beginning of year		8,837			307			9,661			292			7,794			267
Revisions of previous estimates		(1,438	)		(17	)		(507	)		29			(520	)		(24	)
Oil and gas reserves sold		(28	)		-			(104	)		(54	)		(2,148	)		(26	)
Extensions, discoveries and
other reserve additions		523			180			2,395			138			6,430			137
Production		(1,608	)		(102	)		(2,608	)		(98	)		(1,895	)		(62	)
End of year		6,286			368			8,837			307			9,661			292

The components of proved oil and gas reserves for the three years ended December 31, 2013 is presented below.  All reserves are in the United States (in thousands):

	Years Ended December 31,
	2013				2012				2011
	Natural				Natural				Natural
	Gas		Oil		Gas		Oil		Gas		Oil
	(Mcf’s)		(Bbls.)		(Mcf’s)		(Bbls.)		(Mcf’s)		(Bbls.)
Proved developed reserves		6,157		367		8,708		306		9,433		277
Proved undeveloped reserves		129		1		129		1		228		15
Total proved reserves		6,286		368		8,837		307		9,661		292

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

The Company employs third party petroleum consultant, Ryder Scott Company, to prepare its oil and gas reserve data estimates as of December 31, 2013, 2012 and 2011.  The firm of Ryder Scott is well recognized within the industry for more than 50 years.  As prescribed by the SEC, such proved reserves were estimated using 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period, and year-end production and development costs for each of the years presented, all without escalation.

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

49

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

The standardized measure of discounted future net cash flows was determined based on the economic conditions in effect at the end of the years presented, except in those instances where fixed and determinable gas price escalations are included in contracts.  The disclosures below do not purport to present the fair market value of the Company’s oil and gas reserves.  An estimate of the fair market value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, a discount factor more representative of the time value of money and risks inherent in reserve estimates.  The standardized measure of discounted future net cash flows is presented as follows (in thousands):

	Years Ended December 31,
	2013			2012			2011
Future gross revenues	$	64,495		$	59,793		$	73,626
Future costs -
Lease operating expenses		(19,207	)		(16,357	)		(19,788	)
Development costs		(119	)		(299	)		(2,198	)
Future net cash flows before income taxes		45,169			43,137			51,640
Discount at 10% per annum		(17,729	)		(17,976	)		(19,439	)
Discounted future net cash flows
before income taxes		27,440			25,161			32,201
Future income taxes, net of discount at
10% per annum		(9,604	)		(8,806	)		(11,270	)
Standardized measure of discounted
future net cash flows	$	17,836		$	16,355		$	20,931

The reserve estimates provided at December 31, 2013, 2012 and 2011 are based on aggregate prices of $94.99, $93.85 and $95.85 per barrel for crude oil and $4.69, $3.51 and $4.69 per mcf for natural gas, respectively.  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 SEC regulations.  The price reported in the reserve disclosure for natural gas for 2013 includes the value of associated natural gas liquids.

  The effect of income taxes and discounting on the standardized measure of discounted future net cash flows is presented as follows (in thousands):

	Years ended December 31,
	2013			2012			2011
Future net cash flows before income taxes	$	45,169		$	43,137		$	51,640
Future income taxes		(15,809	)		(15,098	)		(18,074	)
Future net cash flows		29,360			28,039			33,566
Discount at 10% per annum		(11,524	)		(11,684	)		(12,635	)
Standardized measure of discounted
future net cash flows	$	17,836		$	16,355		$	20,931

50

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

	Years Ended December 31,
	2013			2012			2011
Beginning of year	$	16,355		$	20,931		$	16,672
Sale of oil and gas reserves		-			(3,802	)		(7,429	)
Net change in prices and production costs		9,341			(5,313	)		791
New field discoveries and extensions, net of future
production costs		9,767			9,513			18,769
Sales of oil and gas produced, net of production costs		(8,373	)		(8,953	)		(7,723	)
Net change due to revisions in quantity estimates		(3,624	)		(940	)		(1,739	)
Accretion of discount		1,797			1,944			1,678
Production rate changes and other		(6,629	)		511			2,204
Net change in income taxes		(798	)		2,464			(2,292	)
End of year	$	17,836		$	16,355		$	20,931

Results of Operations for Oil and Gas Producing Activities -

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

	Years Ended December 31,
	2013			2012			2011
Revenues	$	14,129		$	15,954		$	14,060
Costs and expenses -
Production		(5,756	)		(7,091	)		(6,337	)
Producing property impairment		(1,373	)		(4,699	)		(7,105	)
Exploration		(1,619	)		(1,151	)		(9,166	)
Oil and natural gas property sale gain		-			2,203			2,923
Depreciation, depletion and amortization		(7,494	)		(8,848	)		(8,249	)
Operating income (loss) before income taxes		(2,113	)		(3,632	)		(13,874	)
Income tax (expense) benefit		739			1,271			4,854
Operating income (loss)	$	(1,374	)	$	(2,361	)	$	(9,020	)

51

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

Item 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

The Company maintains ‟disclosure controls and procedures” as defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the ‟Exchange Act”) that are designed to ensure that information required to be disclosed in the reports that the Company files or submits under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and is accumulated and communicated to management, including the Company’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely discussions regarding required disclosure.  Management necessarily applied its judgment in assessing the costs and benefit of such controls and procedures, which, by their nature, can provide only reasonable assurance regarding management’s disclosure control objectives.

As of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures. Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded the Company’s disclosure controls and procedures were effective at a reasonable assurance level as of the end of the period covered by this report.

Management’s Report on Internal Control Over Financial Reporting

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

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

Management, including the Company’s Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2013.  In making this assessment, management used the criteria described in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on this assessment, management, including the Company’s Chief Executive Officer and Chief Financial Officer, concluded that internal control over financial reporting was effective at a reasonable assurance level as of December 31, 2013.

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

52

Changes in Internal Control over Financial Reporting

There have not been any changes in the Company’s internal control over financial reporting during the fiscal quarter ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

53

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Adams Resources & Energy, Inc.

Houston, Texas

We have audited the internal control over financial reporting of Adams Resources & Energy, Inc. and subsidiaries (the "Company") as of December 31, 2013, based on criteria established in Internal Control — Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on that risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control — Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2013 of the Company and our report dated March 13, 2014 expressed an unqualified opinion on those financial statements.

/s/Deloitte & Touche LLP

Houston, Texas

March 13, 2014

54

Item 9B.  OTHER INFORMATION

None.

55

PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information concerning directors, corporate governance and executive officers of the Company is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Shareholders to be held Wednesday, May 14, 2014, under the heading ‟Election of Directors” and ‟Executive Officers”, respectively, to be filed with the Commission not later than 120 days after the end of the fiscal year covered by this Form 10-K.

Item 11. EXECUTIVE COMPENSATION

The information required by Item 11 is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Shareholders to be held Wednesday, May 14, 2014, under the heading ‟Executive Compensation” to be filed with the Commission not later than 120 days after the end of the fiscal year covered by this Form 10-K.

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by Item 12 is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Shareholders to be held Wednesday, May 14, 2014, under the heading ‟Voting Securities and Principal Holders Thereof” to be filed with the Commission not later than 120 days after the end of the fiscal year covered by this Form 10-K.

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by Item 13 is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Shareholders to be held Wednesday, May 14, 2014, under the headings ‟Transactions with Related Parties” and ‟Director Independence” to be filed with the Commission not later than 120 days after the end of the fiscal year covered by this Form 10-K.

Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by Item 14 is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Shareholders to be held Wednesday, May 14, 2014, under the heading ‟Principal Accounting Fees and Services” to be filed with the Commission not later than 120 days after the end of the fiscal year covered by this Form 10-K.

56

PART IV

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

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

1.           Financial Statements

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of December 31, 2013 and 2012

Consolidated Statements of Operations for the Years Ended

December 31, 2013, 2012 and 2011

Consolidated Statements of Shareholders’ Equity for the Years Ended

December 31, 2013, 2012 and 2011

Consolidated Statements of Cash Flows for the Years Ended

December 31, 2013, 2012 and 2011

Notes to Consolidated Financial Statements

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

3.Exhibits required to be filed

3(a) - Certificate of Incorporation of the Company, as amended.  (Incorporated by reference to Exhibit 3(a) filed with the Annual Report on Form 10-K (-File No. 1-7908) of the Company for the fiscal year ended December 31, 1987).

3(b) - Bylaws of the Company, as amended.  (Incorporated by reference to Exhibit 3(b) filed with the Annual Report on Form 10-K for the year ended December 31, 2012 (-File No. 1-7908).

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

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

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

10.1(a)+ -  Employment agreement of Frank T. Webster, President, dated May 12, 2004 by and between Adams Resources & Energy, Inc. and Frank T. Webster (Incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2004).

57

10.1(b)+ -  Eleventh Amendment to Employment Agreement of Frank T. Webster, President, by and between Adams Resources & Energy, Inc. and Frank T. Webster effective December 5, 2013 (Incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on December 6, 2013).

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

10.1(d)+ -  First Amendment to Change in Control/Severance agreement by and between Adams Resources & Energy, Inc. and Richard B. Abshire effective December 6, 2011 (Incorporated by reference to Exhibit 10.2 to the Company’s current report on Form 8-K filed on December 7, 2011).

10.1(e)+ -  Amendment to Change in Control/Severance agreement by and between Adams Resources & Energy, Inc. and Sharon Davis effective December 6, 2011 (Incorporated by reference to Exhibit 10.3 to the Company’s current report on Form 8-K filed on December 7, 2011).

10.1(f)+ -  Non-Employee Director Change in Control Agreement by and between Adams Resources & Energy, Inc. and E. C. Reinauer, Jr., dated effective December 6, 2011 (Incorporated by reference to Exhibit 10.4 to the Company’s Form 8-K filed on December 7, 2011).

10.1(g)+ -  Non-Employee Director Change in Control Agreement by and between Adams Resources & Energy, Inc. and Townes G. Pressler, dated effective December 6, 2011 (Incorporated by reference to Exhibit 10.5 to the Company’s Form 8-K filed on December 7, 2011).

10.1(h)+ -  Non-Employee Director Change in Control Agreement by and between Adams Resources & Energy, Inc. and Larry E. Bell, dated effective December 6, 2011 (Incorporated by reference to Exhibit 10.5 to the Company’s Form 8-K filed on December 7, 2011).

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

21* - Subsidiaries of the Registrant

23.1* - Consent of Ryder Scott Company

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

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

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

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

99.1* - Ryder Scott Company Report

______________________________

*  - Filed herewith

  +  - Management contract or compensation plan or arrangement

58

Copies of all agreements defining the rights of holders of long-term debt of the Company and its subsidiaries, which agreements authorize amounts not in excess of 10% of the total consolidated assets of the Company, are not filed herewith but will be furnished to the Commission upon request.

59

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	ADAMS RESOURCES & ENERGY, INC.
	(Registrant)
By  /s/Richard B. Abshire	By /s/ Frank T. Webster
Richard B. Abshire,	Frank T. Webster
Vice President and Chief Financial Officer	Chief Executive Officer
(Principal Financial Officer and Principal Accounting Officer)	(P(Principal Executive Officer)

Date:  March 13, 2014

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.

By /s/ Frank T. Webster	By /s/ E. C. Reinauer, Jr.
Frank T. Webster, Director	E. C. Reinauer, Jr., Director
By /s/ Larry E. Bell	By /s/ Townes G. Pressler
Larry E. Bell, Director	Townes G. Pressler, Director
By /s/ Thomas S. Smith
Thomas S. Smith, Director
(Chairman)

60

EXHIBIT INDEX

Exhibit
Number	Description
3(a)	-      Certificate of Incorporation of the Company, as amended.  (Incorporated by reference to Exhibit 3(a) filed with the Annual Report on Form 10-K of the Company for the fiscal year ended December 31, 1987).
3(b)	-      Bylaws of the Company, as amended.  (Incorporated by reference to Exhibit 3(b) filed with the Annual Report on Form 10-K for the year ended December 31, 2012 (-File No. 1-7908).
3(c)	-      Adams Resources & Energy, Inc. and Subsidiaries’ Code of Ethics (Incorporated by reference to Exhibit 3(d) of the Annual Report on Form 10-K of the Company for the fiscal year ended December 31, 2002).
4(a)	-      Specimen common stock Certificate (Incorporated by reference to Exhibit 4(a) of the Annual Report on Form 10-K of the Company for the fiscal year ended December 31, 1991).
4(b)	-     Credit and Security Agreement between Gulfmark Energy, Inc., Adams Resources Marketing, Ltd and Wells Fargo Bank, National Association dated August 27, 2010 (Incorporated by reference to Exhibit 4(b) of the Quarterly Report on Form 10-Q for the period ended September 30, 2009).
10.1(a)+	-     Employment agreement of Frank T. Webster, President, dated May 12, 2004 by and between Adams Resources & Energy, Inc. and Frank T. Webster (Incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2004).
10.1(b)+	-     Eleventh Amendment to Employment Agreement of Frank T. Webster, President, by and between Adams Resources & Energy, Inc. and Frank T. Webster effective December 5, 2013 (Incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on December 6, 2013).
10.1(c)+	-     Change in Control/Severance agreement by and between Adams Resources & Energy, Inc. and Richard B. Abshire effective July 25, 2008 (Incorporated by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on July 25, 2008).
10.1(d)+	-     First Amendment to Change in Control/Severance agreement by and between Adams Resources & Energy, Inc. and Richard B. Abshire effective December 6, 2011 (Incorporated by reference to Exhibit 10.2 to the Company’s current report on Form 8-K filed on December 7, 2011).
10.1(e)+	-     Amendment to Change in Control/Severance agreement by and between Adams Resources & Energy, Inc. and Sharon Davis effective December 6, 2011 (Incorporated by reference to Exhibit 10.3 to the Company’s current report on Form 8-K filed on December 7, 2011).
10.1(f)+	-     Non-Employee Director Change in Control Agreement by and between Adams Resources & Energy, Inc. and E. C. Reinauer, Jr., dated December 6, 2011 (Incorporated by reference to Exhibit 10.4 to the Company’s Form 8-K filed on December 7, 2011).

61

10.1(g)+	-     Non-Employee Director Change in Control Agreement by and between Adams Resources & Energy, Inc. and Townes G. Pressler, dated effective December 6, 2011 (Incorporated by reference to Exhibit 10.5 to the Company’s Form 8-K filed on December 7, 2011).
10.1(h)+	-     Non-Employee Director Change in Control Agreement by and between Adams Resources & Energy, Inc. and Larry E. Bell, dated effective December 6, 2011 (Incorporated by reference to Exhibit 10.5 to the Company’s Form 8-K filed on December 7, 2011).
10.1(i)+	-     Standard form Indemnification Agreement between Adams Resources & Energy, Inc. and Officers or Directors (Incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2011).
21*	-      Subsidiaries of the Registrant
23.1*	-      Consent of Ryder Scott Company
31.1*	-      Certification Pursuant to 17 CFR 13a-14(a)/15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	-      Certification Pursuant to 17 CFR 13a-14(a)/15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1*	-     Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2*	-     Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1*	-     Ryder Scott Company Report
101.INS*	-     XBRL Instance Document
101.SCH*	-     XBRL Schema Document
101.CAL*	-     XBRL Calculation Linkbase Document
101.LAB*	-     XBRL Label Linkbase Document
101.PRE*	-     XBRL Presentation Linkbase Document

______________________________

*   - Filed herewith

+   - Management contract or compensation plan or arrangement.

** - Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language):  (i) the Consolidated Statements of Income – Year Ended December 31, 2013 and 2012, (ii) the Consolidated Balance Sheets – December 31, 2013 and December 31, 2012, (iii) the Consolidated Statements of Cash Flows – Year Ended December 31, 2013 and 2012 and (iv) Notes to Consolidated Financial Statements.

 

EX-21

EX-23

EXHIBIT 23.1

CONSENT OF RYDER SCOTT COMPANY, L.P.

The undersigned hereby consents to the references to our firm in the form and context in which they appear in the Annual Report on Form 10-K of Adams Resources & Energy, Inc. for the year ended December 31, 2013 (the “Annual Report”).  We hereby further consent to the inclusion in the Annual Report of our report entitled “Adams Resources Exploration Corporation – Estimated Future Reserves and Income Attributable to Certain Leasehold and Royalty Interests – SEC Parameters – As of December 31, 2013” and to the inclusion of our report dated February 10, 2014 as an exhibit to the Annual Report.

/s/ Ryder Scott Company, L.P.

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

Houston, Texas

March 13, 2014

EX-31.1

 Exhibit 31.1

ADAMS RESOURCES & ENERGY, INC.

CERTIFICATION PURSUANT TO

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

AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Frank T. Webster certify that:

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

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

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

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

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

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

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

(d) disclosed in this report any change in the registrant’s internal control over financial reporting  that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

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

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

(b)   any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  March 13, 2014

/s/ Frank T. Webster                                                                           

Frank T. Webster

Chief Executive Officer

EX-31.2

 Exhibit 31.2

ADAMS RESOURCES & ENERGY, INC.

CERTIFICATION PURSUANT TO

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

AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Richard B. Abshire, certify that:

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

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

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

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

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

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

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

(d)  disclosed in this report any change in the registrant’s internal control over financial reporting  that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

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

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

(b)   any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  March 13, 2014

/s/ Richard B. Abshire                                                                           

Richard B. Abshire

Chief Financial Officer

EX-32.1

 Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Adams Resources & Energy, Inc. (the ‟Company”) on Form 10-K for the year ended December 31, 2013, as filed with the Securities and Exchange Commission, (the ‟Report”), I, Frank T. Webster, Chief Executive Officer of the Company, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), that to the best of my knowledge:

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

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

/s/ Frank T. Webster                                           

Frank T. Webster

Chief Executive Officer

March 13, 2014

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

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

EX-32.2

 Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Adams Resources & Energy, Inc. (the ‟Company”) on Form 10-K for the year ended December 31, 2013, as filed with the Securities and Exchange Commission, (the ‟Report”), I, Richard B. Abshire, Chief Financial Officer of the Company, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), that to the best of my knowledge:

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

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

/s/ Richard B. Abshire                                           

Richard B. Abshire

Chief Financial Officer

March 13, 2014

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

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

EX-99.1

 Exhibit 99.1

ADAMS RESOURCES EXPLORATION CORPORATION

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold and Royalty Interests

SEC Parameters

As of

December 31, 2013

\s\ Fred W. Ziehe

Fred W. Ziehe, P.E.

TBPE License No. 63630

Managing Senior Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

February 10, 2014

Adams Resources Exploration Corporation

17 S. Briar Hollow Lane, Suite 100

Houston, TX  77027

Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold and royalty interests of Adams Resources Exploration Corporation (Adams) as of December 31, 2013.  The subject properties are located in the states of Arkansas, Kansas, Louisiana, Montana, Oklahoma and Texas.  The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations).  Our third party study, completed on February 7, 2014 and presented herein, was prepared for public disclosure by Adams in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The properties reviewed by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon and gas reserves of Adams.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2013, are related to hydrocarbon prices.  The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations.  Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report.  The results of this study are summarized below.

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold and Royalty Interests of

Adams Resources Exploration Corporation

As of December 31, 2013

	Proved
	Developed								Total
	Producing		Non-Producing		Undeveloped				Proved
Net Remaining Reserves
Oil/Condensate – MBbls		353.9		13.9		0.6		368.4
Gas – MMCF		6,139		18		129		6,286
MBOE		1,377.1		16.9		22.1		1,416.1
Income Data (M$)
Future Gross Revenue	$	58,888.2	$	1,439.7	$	537.7	$	60,865.6
Deductions		15,452.3		103.4		140.7		15,696.4
Future Net Income (FNI)	$	43,435.9	$	1,336.3	$	397.0	$	45,169.2
Discounted FNI @ 10%	$	26,532.4	$	644.6	$	262.6	$	27,439.6

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

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

The future gross revenue is after the deduction of production taxes.  The deductions incorporate the normal direct costs of operating the wells, certain variable operating costs shown as “Other” deductions, ad valorem taxes, recompletion costs, and development costs.  The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income.  Liquid hydrocarbon reserves account for approximately 54 percent and gas reserves account for the remaining 46 percent of total future gross revenue from proved reserves.

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

	Discounted Future Net Income (M$)
	As of December 31, 2013
Discount Rate		Total
Percent		Proved
5		$33,703.6
15		$23,484.0
20		$20,742.6
25		$18,719.3

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

Reserves Included in This Report

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

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

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

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

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

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

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

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

Estimates of Reserves

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

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

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

The proved reserves for the properties included herein were estimated by performance methods, the volumetric method, analogy, or a combination of methods.  Almost all of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods.  These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of historical monthly production and pressure data generally available through September 2013, and in some instances with test data available through November 2013, in those cases where such data were considered to be definitive.  The data utilized in this analysis were furnished to Ryder Scott by Adams or obtained from public data sources and were considered sufficient for the purpose thereof.  The remaining small portion of the proved producing reserves were estimated by analogy where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

All of the proved developed non-producing and undeveloped reserves included herein were estimated by the volumetric method, analogy, or a combination of methods.  The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by Adams or which we have obtained from public data sources that were available through November 2013.  The data utilized from the analogues as well as well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof.

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

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

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

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

Future Production Rates

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

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

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

Hydrocarbon Prices

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

Adams furnished us with the above mentioned average prices in effect on December 31, 2013.  These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold.  These benchmark prices are prior to the adjustments for differentials as described herein.  The table below summarizes the “benchmark prices” and “price reference” used for the geographic areas included in the report.  In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.  In cases where there are numerous contracts or price references within the same geographic area, the benchmark price is represented by the unweighted arithmetic average of the initial 12-month average first-day-of-the-month benchmark prices used.

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

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

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
Total U.S. Domestic	Oil/Condensate	Various 1	$91.54/Bbl	$94.99/Bbl
	Gas	Various 2	$3.598/MMBTU	$4.69/MCF

1Oil/Cond Benchmarks include Postings for:  LOTT Arkansas Sweet, Kansas Common, North Dakota – Williston Sweet, N Louisiana, St. James, So Louisiana Light, OK Sweet, East Tx Field, Giddings, Tx Upper Gulf Coast, Flint Hills So Tx Sweet, W Central Tx, and W Tx Intermediate – Area 1

2Gas Benchmarks include:  Carthage Hub, CIG, El Paso-Permian, Henry Hub, Houston Ship Channel, NGPL_MC,  NGPL(STX), NGPL_TexOk Zone, Southern Natural Gas, Texas Eastern, Transwestern Permian Basin, and Trunkline ELA

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

Costs

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

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

The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with Adams’ plans to develop these reserves as of December 31, 2013.  The implementation of Adams’ development plans as presented to us and incorporated herein is subject to the approval process adopted by Adams’ management.  As the result of our inquiries during the course of preparing this report, Adams has informed us that the development activities included herein have been subjected to and received the internal approvals required by Adams’ management at the appropriate local, regional and/or corporate level.  In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Adams.  Additionally, Adams has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

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

Standards of Independence and Professional Qualification

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

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

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

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

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

Terms of Usage

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

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

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

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

\s\ Fred W. Ziehe

Fred W. Ziehe, P.E.

TBPE License No. 63630

Managing Senior Vice President

[SEAL]

FWZ/pl

Professional Qualifications of Primary Technical Person

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

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

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

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Ziehe fulfills.  As part of his 2013 continuing education hours, Mr. Ziehe received training that included causes and effects in the oil and gas price markets, ethics training, portfolio analysis of unconventional resources, petroleum accounting, and various topics at the 2013 Ryder Scott Reserve Conference.  During 2012, 2011, 2009, and 2008, Mr. Ziehe also presented internal and external training sessions on items required for disclosure in an SEC reserve letter, the comment letter process between the SEC and filing companies, training for price requirements in an SEC reserve report, and methodologies for determining price differentials.

Based on his educational background, professional training and more than 38 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Ziehe has attained the professional qualifications as a Reserves Estimator and Reserves Auditor as set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

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

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

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

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

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

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

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

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

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

RESERVES (SEC DEFINITIONS)

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

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

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

PROVED RESERVES (SEC DEFINITIONS)

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

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

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

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

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

PETROLEUM RESERVES DEFINITIONS

Page

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

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

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

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

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

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

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

PETROLEUM RESERVES DEFINITIONS

Page

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

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

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

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

DEVELOPED RESERVES (SEC DEFINITIONS)

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

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

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

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

Developed Producing (SPE-PRMS Definitions)

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

Developed Producing Reserves

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

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

PETROLEUM RESERVES DEFINITIONS

Page

Developed Non-Producing

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

Shut-In

Shut-in Reserves are expected to be recovered from:

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

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

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

Behind-Pipe

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

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

UNDEVELOPED RESERVES (SEC DEFINITIONS)

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

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

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

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

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

XML

Commitments and Contingencies (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 Lawsuit	Dec. 31, 2012	Dec. 31, 2011
Commitments and Contingencies [Abstract]
Rental expense	$ 8,281,000	$ 8,110,000	$ 7,621,000
Commitments under long-term non-cancelable operating leases [Abstract]
2014	3,138,000
2015	1,931,000
2016	1,910,000
2017	1,690,000
2018	804,000
Thereafter	40,000
Estimated expenses and related liabilities for losses incurred not reported to insurance carrier	1,796,000	1,545,000
Accrued medical claims	1,129,000	506,000
Minimum annual individual medical claims for stop loss coverage	100,000
Umbrella insurance coverage	2,000,000
Minimum aggregate medical claims for umbrella insurance coverage for 2013	4,500,000
Minimum aggregate medical claims for umbrella insurance coverage for 2014	4,500,000
Number of suits alleging oil and gas production	1
Total number of lawsuits	4
Accrued future legal costs	$ 200,000

XML

Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Data (Unaudited) [Abstract]

Selected quarterly financial data and earnings per share

Selected quarterly financial data and earnings per share of the Company are presented below for the years ended December 31, 2013 and 2012 (in thousands, except per share data):

				Earnings from
				Continuing Operations				Net Earnings				Dividends
		Revenues		Amount		Per Share		Amount		Per Share		Amount		Per Share
	2013 -
March 31		$	952,435	$	8,073	$	1.91	$	8,015	$	1.90	$	-	$	-
June 30			965,098		6,521		1.55		6,330		1.50		928		.22
September 30			1,060,340		7,238		1.72		7,156		1.70		927		.22
December 31			968,096		289		.06		109		.02		928		.22
Total		$	3,945,969	$	22,121	$	5.24	$	21,610	$	5.12	$	2,783	$	.66
	2012 -
March 31		$	875,905	$	5,944	$	1.41	$	6,575	$	1.56	$	-	$	-
June 30			830,110		5,333		1.26		5,386		1.28		-		-
September 30			794,404		8,355		1.98		8,263		1.96		-		-
December 31			875,666		7,840		1.86		7,567		1.79		2,615		.62
Total		$	3,376,085	$	27,472	$	6.51	$	27,791	$	6.59	$	2,615	$	.62

XML

Quarterly Financial Data (Unaudited) (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Selected quarterly financial data and earnings per share [Abstract]
Revenues	$ 968,096	$ 1,060,340	$ 965,098	$ 952,435	$ 875,666	$ 794,404	$ 830,110	$ 875,905	$ 3,945,969	$ 3,376,085	$ 3,038,737
Earnings from continuing operations	289	7,238	6,521	8,073	7,840	8,355	5,333	5,944	22,121	27,472	22,718
Earnings from continuing operations, Per Share (in dollars per share)	$ 0.06	$ 1.72	$ 1.55	$ 1.91	$ 1.86	$ 1.98	$ 1.26	$ 1.41	$ 5.24	$ 6.51	$ 5.39
Net Earnings	109	7,156	6,330	8,015	7,567	8,263	5,386	6,575	21,610	27,791	22,931
Net Earnings, Per Share (in dollars per share)	$ 0.02	$ 1.70	$ 1.50	$ 1.90	$ 1.79	$ 1.96	$ 1.28	$ 1.56	$ 5.12	$ 6.59	$ 5.44
Dividends	$ 928	$ 927	$ 928	$ 0	$ 2,615	$ 0	$ 0	$ 0	$ 2,783	$ 2,615	$ 2,404
Dividends, Per share (in dollars per share)	$ 0.22	$ 0.22	$ 0.22	$ 0	$ 0.62	$ 0	$ 0	$ 0	$ 0.66	$ 0.62

XML

Income Taxes

12 Months Ended

Dec. 31, 2013

Income Taxes [Abstract]

Income Taxes

(2)  Income Taxes

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

	Years ended December 31,
	2013			2012			2011
Current:
Federal	$	(8,102	)	$	(10,282	)	$	(4,336	)
State		(892	)		(1,176	)		(1,187	)
		(8,994	)		(11,458	)		(5,523	)
Deferred:
Federal		(2,682	)		(4,940	)		(7,407	)
State		(478	)		(438	)		99
		(3,160	)		(5,378	)		(7,308	)
	$	(12,154	)	$	(16,836	)	$	(12,831	)

The following table summarizes the components of the income tax (provision) benefit (in thousands):

	Years ended December 31,
	2013			2012			2011
From continuing operations	$	(12,429	)	$	(16,664	)	$	(12,717	)
From discontinued operations		275			(172	)		(114	)
	$	(12,154	)	$	(16,836	)	$	(12,831	)

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

	Years ended December 31,
	2013			2012			2011
Statutory federal income tax (provision) benefit	$	(11,819	)	$	(15,619	)	$	(12,517	)
State income tax (provision) benefit		(891	)		(1,049	)		(707	)
Federal statutory depletion		522			36			393
Other		34			(204	)		-
	$	(12,154	)	$	(16,836	)	$	(12,831	)

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

	Years Ended December 31,
	2013			2012
Current deferred tax asset (liability)
Allowance for doubtful accounts	$	424		$	581
Prepaid and other insurance		(855	)		(815	)
Fair value contracts		73			(6	)
Net current deferred liability		(358	)		(240	)
Long-term deferred tax asset (liability)
Property		(18,964	)		(15,957	)
Uniform capitalization		613			552
Other		(283	)		(221	)
Net long-term deferred tax  liability		(18,634	)		(15,626	)
Net deferred tax liability	$	(18,992	)	$	(15,866	)

Financial statement recognition and measurement of positions taken, or expected to be taken, by an entity in its income tax returns must consider the uncertainty and judgment involved in the determination and filing of income taxes.  Tax positions taken in an income tax return that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the tax position will be examined by taxing authorities with full knowledge of all relevant information.  The Company has no significant unrecognized tax benefits.  Interest and penalties associated with income tax liabilities are classified as income tax expense.

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

	Earliest Open
	Tax Year
Federal	2010
Texas	2009
Louisiana	2010
Michigan	2010

XML

Income Taxes (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current [Abstract]
Federal	$ (8,102)	$ (10,282)	$ (4,336)
State	(892)	(1,176)	(1,187)
Current income tax (provision) benefit	(8,994)	(11,458)	(5,523)
Deferred [Abstract]
Federal	(2,682)	(4,940)	(7,407)
State	(478)	(438)	99
Deferred income tax (provision) benefit	(3,160)	(5,378)	(7,308)
Income tax (provision) benefit	(12,154)	(16,836)	(12,831)
Income tax (provision) benefit, continuing and discontinued operations [Abstract]
From continuing operations	(12,429)	(16,664)	(12,717)
From discontinued operations	275	(172)	(114)
Income tax (provision) benefit	(12,154)	(16,836)	(12,831)
Reconciliation of taxes computed at the corporate federal income tax rate to the reported income tax (provision) [Abstract]
Statutory federal income tax (provision) benefit	(11,819)	(15,619)	(12,517)
State income tax (provision) benefit	(891)	(1,049)	(707)
Federal statutory depletion	522	36	393
Other	34	(204)	0
Income tax (provision) benefit	(12,154)	(16,836)	(12,831)
Current deferred tax asset (liability) [Abstract]
Allowance for doubtful accounts	424	581
Prepaid and other insurance	(855)	(815)
Fair value contracts	73	(6)
Net current deferred liability	(358)	(240)
Long-term deferred tax asset (liability) [Abstract]
Property	(18,964)	(15,957)
Uniform capitalization	613	552
Other	(283)	(221)
Net long-term deferred tax liability	(18,634)	(15,626)
Net deferred tax liability	$ (18,992)	$ (15,866)
Federal [Member]
Income Tax Examination [Line Items]
Earliest Open Tax Year	2010
Texas [Member]
Income Tax Examination [Line Items]
Earliest Open Tax Year	2009
Louisiana [Member]
Income Tax Examination [Line Items]
Earliest Open Tax Year	2010
Michigan [Member]
Income Tax Examination [Line Items]
Earliest Open Tax Year	2010

XML

Summary of Significant Accounting Policies, Derivatives by Hedging Relationship and Fair Value Measurements (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Company's asset retirement obligations [Roll Forward]
Balance on January 1,	$ 1,886,000	$ 1,568,000
Liabilities incurred	431,000	358,000
Accretion of discount	85,000	63,000
Liabilities settled	(138,000)	(103,000)
Revisions to estimates	300,000	0
Balance on December 31,	2,564,000	1,886,000
Escrow cash	75,000
Level 1 Quoted Prices [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net Value	0	0
Factors impacting the change in the net value of the Company's fair value contracts [Abstract]
Net Fair Value January 1,	0	0
Net realized (gains) losses	0	0
Option deposit	0
Net unrealized gains (losses)	0	0
Net Fair Value December 31,	0	0
Level 2 Observable [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net Value	395,000	(27,000)
Factors impacting the change in the net value of the Company's fair value contracts [Abstract]
Net Fair Value January 1,	(27,000)	1,338,000
Net realized (gains) losses	27,000	(1,338,000)
Option deposit	615,000
Net unrealized gains (losses)	(220,000)	(27,000)
Net Fair Value December 31,	395,000	(27,000)
Total Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net Value	395,000	(27,000)
Factors impacting the change in the net value of the Company's fair value contracts [Abstract]
Net Fair Value January 1,	(27,000)	1,338,000
Net realized (gains) losses	27,000	(1,338,000)
Option deposit	615,000
Net unrealized gains (losses)	(220,000)	(27,000)
Net Fair Value December 31,	395,000	(27,000)
Fair Value, Measurements, Recurring [Member] | Level 1 Quoted Prices [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives - Current assets	0	0
Derivatives - Current liabilities	0	0
Net Value	0	0
Factors impacting the change in the net value of the Company's fair value contracts [Abstract]
Net Fair Value December 31,	0	0
Fair Value, Measurements, Recurring [Member] | Level 2 Observable [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives - Current assets	449,000	354,000
Derivatives - Current liabilities	(54,000)	(381,000)
Net Value	395,000	(27,000)
Factors impacting the change in the net value of the Company's fair value contracts [Abstract]
Net Fair Value December 31,	395,000	(27,000)
Fair Value, Measurements, Recurring [Member] | Level 3 Unobservable [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives - Current assets	0	0
Derivatives - Current liabilities	0	0
Net Value	0	0
Factors impacting the change in the net value of the Company's fair value contracts [Abstract]
Net Fair Value December 31,	0	0
Fair Value, Measurements, Recurring [Member] | Counterparty Offsets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives - Current assets	(54,000)	(270,000)
Derivatives - Current liabilities	54,000	270,000
Net Value	0	0
Factors impacting the change in the net value of the Company's fair value contracts [Abstract]
Net Fair Value December 31,	0	0
Fair Value, Measurements, Recurring [Member] | Total Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives - Current assets	395,000	84,000
Derivatives - Current liabilities	0	(111,000)
Net Value	395,000	(27,000)
Factors impacting the change in the net value of the Company's fair value contracts [Abstract]
Net Fair Value December 31,	395,000	(27,000)
Commodity Contract [Member] | Revenues - marketing [Member] | Not Designated as Hedging Instrument [Member]
Earnings (loss) recognized in income [Abstract]
Earnings (Loss)	$ (193,000)	$ (1,365,000)	$ 119,000

XML

Concentration of Credit Risk (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Concentration Risk [Line Items]
Industry practice payment of receivables	20 days
Percentage of US demand supplied by company (in hundredths)	1.00%
Allowance for doubtful accounts	$ 252	$ 206
Changes in the allowance for doubtful accounts [Roll Forward]
Balance, beginning of year	206	357	180
Provisions for bad debts	147	0	276
Less: Write-offs and recoveries	(101)	(151)	(99)
Balance, end of year	$ 252	$ 206	$ 357
Customer Concentration Risk [Member] | Minimum [Member]
Concentration Risk [Line Items]
Number of customers	3
Customer Concentration Risk [Member] | Maximum [Member]
Concentration Risk [Line Items]
Number of customers	4
Accounts Receivable [Member]
Concentration Risk [Line Items]
Number of customers	3	3	2
Accounts Receivable [Member] | Product Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration risk, percentage (in hundredths)	90.00%
Accounts Receivable [Member] | Customer One [Member]
Concentration Risk [Line Items]
Concentration risk, percentage (in hundredths)	16.00%	22.10%	24.50%
Accounts Receivable [Member] | Customer Two [Member]
Concentration Risk [Line Items]
Concentration risk, percentage (in hundredths)	15.80%	21.40%	21.50%
Accounts Receivable [Member] | Customer Three [Member]
Concentration Risk [Line Items]
Concentration risk, percentage (in hundredths)	12.70%	11.40%
Revenue [Member]
Concentration Risk [Line Items]
Number of customers	4	3	4
Revenue [Member] | Customer Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration risk, percentage (in hundredths)	50.00%
Revenue [Member] | Customer One [Member]
Concentration Risk [Line Items]
Concentration risk, percentage (in hundredths)	18.50%	20.20%	18.20%
Revenue [Member] | Customer Two [Member]
Concentration Risk [Line Items]
Concentration risk, percentage (in hundredths)	17.70%	17.90%	15.40%
Revenue [Member] | Customer Three [Member]
Concentration Risk [Line Items]
Concentration risk, percentage (in hundredths)	15.80%	16.80%	13.40%
Revenue [Member] | Customer Four [Member]
Concentration Risk [Line Items]
Concentration risk, percentage (in hundredths)	10.40%		11.30%

XML

Employee Benefits (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Employee Benefits [Abstract]
Contributory expenses by employer	$ 674,000	$ 645,000	$ 597,000

XML

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

Summary of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

(1)  Summary of Significant Accounting Policies

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Adams Resources & Energy, Inc., a Delaware corporation (‟ARE”) together with 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, 2013 were evaluated through the date of issuance of these financial statements.

Nature of Operations

The Company is engaged in the business of crude oil marketing, 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 trucking services.  Marketing business wholesale level sales of crude oil comprise in excess of 90 percent of accounts receivable and under industry practices, such items are ‟settled” and paid in cash within 20 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 trucking services.  For this component of receivables, the allowance for doubtful accounts is determined based on a review of specific accounts combined with a review of the general status of the aging of all accounts.

Inventories

Inventory consists of crude oil held in storage tanks and at third-party pipelines as part of the Company’s crude oil marketing operations.  Crude oil inventory is carried at the lower of average cost or market.

Prepayments

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

	December 31,
	2013		2012
Cash collateral deposits for commodity purchases	$	13,705	$	5,000
Insurance premiums		2,490		1,872
Rents, license and other		584		840
	$	16,779	$	7,712

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 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, 2013, 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, 2013, 2012 and 2011, there were $1,373,000, $4,699,000 and $7,105,000 respectively, of impairment provisions on producing oil and gas properties.

Fair value measurements for producing oil and gas properties that were subject to fair value impairment for the years ended December 31, 2013 and 2012 summarized as follows (in thousands):

	Producing Properties Subject to Fair Value Impairment
	2013			2012
Net book value at January 1	$	13,180		$	11,073
Property additions		5,661			13,083
Depletion taken		(3,727	)		(6,371	)
Impairment valuation loss		(1,373	)		(4,699	)
Net book at December 31	$	13,741		$	13,086

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

On a quarterly basis, management evaluates the carrying value of non-producing oil and gas leasehold properties and may deem them impaired based on remaining lease term, area drilling activity and the Company’s plans for the property.  This fair value measure depends highly on management’s assessment of the likelihood of continued exploration efforts in a given area and, as such, data inputs are categorized as ‟unobservable or Level 3” inputs.  Importantly, this fair value measure only applies to the write-down of capitalized costs and will never result in an increase to reported earnings.  Accordingly, impairment provisions on non-producing properties totaling $1,257,000, $856,000 and $7,644,000 were recorded for the years ending December 31, 2013, 2012 and 2011, respectively.  Capitalized costs for non-producing oil and gas leasehold interests currently represent approximately five percent of total oil and gas property costs and are categorized as follows (in thousands):

	December 31,		December 31,
	2013		2012
South Texas Project acreage	$	4,217	$	3,263
West Texas Project		116		180
Napoleonville Louisiana acreage		162		323
Other acreage areas		411		329
Total Non-producing Leasehold Costs	$	4,906	$	4,095

The South Texas, West Texas and Napoleonville acreage areas have active or scheduled drilling operations underway and holding the underlying acreage is essential to the ongoing exploration effort.  The ‟Other Acreage Areas” category consists of smaller onshore interests dispersed over a wide geographical area.  Since the Company is generally not the operator of its oil and gas property interests, it does not maintain underlying detail acreage data and is dependent on the operator when determining which specific acreage will ultimately be drilled.  However, the capitalized cost detail on a property-by-property basis is reviewed by management and deemed impaired if development is not anticipated prior to lease expiration.  Onshore leasehold periods are normally three years and may contain renewal options.  Capitalized cost activity on the ‟Other Acreage Areas” was as follows (in thousands):

	Leasehold Costs
	2013			2012
Net book value January 1	$	329		$	475
Property additions		304			810
Property sale		-			(100	)
Impairments		(222	)		(856	)
Net book value December 31	$	411		$	329

During 2012, the Company sold half of its interest in certain non-producing Kansas oil and gas properties.  Proceeds from the sale totaled $578,000 and the Company recorded a $475,000 pre-tax gain from this sale.  Also during 2012, the Company sold its interest in two oil and gas producing property units for total proceeds of $3,049,000.  The Company realized a $1,728,000 pre-tax gain from these two 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 2011 sale totaled $6.2 million and the pre-tax gain totaled $2,708,000.  Also during 2011, the Company sold a portion of its interest in certain non-producing oil and gas properties located in West Texas for $329,000 with a $125,000 pre-tax gain from this transaction.

During 2013, 2012 and 2011, the Company sold certain used trucks and equipment from its marketing and transportation segments and recorded pre-tax gains totaling $372,000, $2,482,000 and $1,246,000, respectively.

Cash Deposits and Other Assets

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

	December 31,
	2013		2012
Insurance collateral deposits	$	3,718	$	3,413
State collateral deposits		160		170
Materials and supplies		609		616
	$	4,487	$	4,199

Revenue Recognition

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

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

Certain crude oil contracts may be with a single counterparty to provide for similar quantities of crude oil to be bought and sold at different locations.  These contracts are entered into for a variety of reasons, including effecting the transportation of the commodity, to minimize credit exposure, and/or to meet the competitive demands of the customer.  Such buy/sell arrangements are reflected on a net revenue basis in the accompanying consolidated financial statements.  Reporting such crude oil contracts on a gross revenue basis would increase the Company’s reported revenues by $1,602,626,000, $1,381,352,000 and $1,812,561,000 for the years ended December 31, 2013, 2012 and 2011, respectively.

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

Letter of Credit Facility

The Company maintains a Credit and Security Agreement with Wells Fargo Bank to provide a $60 million stand-by letter of credit facility that is used to support the Company’s crude oil purchases within the marketing segment.  This facility is collateralized by the eligible accounts receivable within the segment and certain marketing and transportation equipment.  Stand-by letters of credit issued totaled $14.6 million and $21.9 million as of December 31, 2013 and 2012, respectively.  The issued stand-by letters of credit are cancelled as the underlying purchase obligations are satisfied by cash payment when due.  The letter of credit facility places certain restrictions on the Company’s Gulfmark Energy, Inc. subsidiary.  Such restrictions included the maintenance of a combined 1.1 to 1.0 current ratio and the maintenance of positive net earnings excluding inventory valuation changes, as defined, among other restrictions.  The Company is currently in compliance with all such financial covenants.

Statement of Cash Flows

Interest paid totaled $24,000, $10,000 and $8,000 during the years ended December 31, 2013, 2012 and 2011, respectively.  Income taxes paid during these same periods totaled $9,949,000, $12,650,000, and $5,597,000, respectively.  In addition, State and Federal income tax refunds totaled $4,000, $10,000 and $2,743,000 in 2013, 2012 and 2011, respectively.  Non-cash investing activities for property and equipment items included in accounts payable as of period end were $1,507,000, $2,419,000 and $4,070,000 as of December 31, 2013, 2012 and 2011, respectively.  There were no significant non-cash financing activities in any of the periods reported.

Earnings per Share

Earnings per share are based on the weighted average number of shares of common stock and potentially dilutive common stock shares outstanding during the period. The weighted average number of shares outstanding was 4,217,596 for 2013, 2012 and 2011.  There were no potentially dilutive securities during those periods.

Share-Based Payments

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

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates. Examples of significant estimates used in the accompanying consolidated financial statements include the oil and gas reserve volumes that form the foundation for calculating depreciation, depletion and amortization and estimating cash flows to assess impairment triggers and estimated values associated with oil and gas properties.  Other examples include revenue accruals, the provision for bad debts, insurance related accruals, income tax permanent and timing differences, contingencies, and valuation of fair value contracts.

Income Taxes

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

Use of Derivative Instruments

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

None of the Company’s derivative instruments have been designated as hedging instruments and the estimated fair value of forward month commodity contracts (derivatives) is reflected in the accompanying Consolidated Balance Sheet as of December 31, 2013 as follows (in thousands):

	Balance Sheet Location and Amount
	Current			Other		Current			Other
	Assets			Assets		Liabilities			Liabilities
Asset Derivatives
- Fair Value Commodity
Contracts at Gross Valuation	$	449		$	-	$	-		$	-
Liability Derivatives
- Fair Value Commodity
Contracts at Gross Valuation		-			-		54			-
Less Counterparty Offsets		(54	)		-		(54	)		-
As Reported Fair Value Contracts	$	395		$	-	$	-		$	-

As of December 31, 2013, one 100,000 barrel crude oil commodity put option and one commodity purchase and sale contract comprised the Company’s derivative valuations.  The purchase and sale contract encompasses approximately 175 barrels of crude oil per day in each of January and February 2014.

Forward month commodity contracts (derivatives) are reflected in the accompanying Consolidated Balance Sheet as of December 31, 2012 as follows (in thousands):

	Balance Sheet Location and Amount
	Current			Other		Current			Other
	Assets			Assets		Liabilities			Liabilities
Asset Derivatives
- Fair Value Commodity
Contracts at Gross Valuation	$	354		$	-	$	-		$	-
Liability Derivatives
- Fair Value Commodity
Contracts at Gross Valuation		-			-		381			-
Less Counterparty Offsets		(270	)		-		(270	)		-
As Reported Fair Value Contracts	$	84		$	-	$	111		$	-

As of December 31, 2012, three commodity purchase and sales contracts comprised substantially all of the Company’s derivative valuations.  Such contracts encompassed the purchase and sale of approximately 900 barrels of crude oil per day in January 2013 and continuing at 200 barrels per day through June 2013.

The Company only enters into commodity contracts with creditworthy counterparties or obtains collateral support for such activities.  As of December 31, 2013 and 2012, the Company was not holding nor had it posted any collateral to support its forward month fair value derivative activity. The Company is not subject to any credit-risk related trigger events.  The Company has no other financial investment arrangements that would serve to offset its derivative contracts.

Forward month commodity contracts (derivatives) are reflected in the accompanying Consolidated Statement of Operations for the years ended December 31, 2013, 2012 and 2011 as follows (in thousands):

	Gain (Loss)
Location	2013			2012			2011
Revenues – marketing	$	(193	)	$	(1,365	)	$	119

 Fair Value Measurements

The carrying amount reported in the consolidated balance sheet for cash and cash equivalents, accounts receivable and accounts payable approximates fair value because of the immediate or short-term maturity of these financial instruments.  Marketable securities are recorded at fair value based on market quotations from actively traded liquid markets.

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

Fair value estimates are based on assumptions that market participants would use when pricing an asset or liability and the Company uses a fair value hierarchy of three levels that prioritizes the information used to develop those assumptions.  Currently, for all items presented herein, the Company utilizes a market approach to valuing its contracts.  On a contract by contract, forward month by forward month basis, the Company obtains observable market data for valuing its contracts.  The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data.  The fair value hierarchy is summarized as follows:

Level 1 – quoted prices in active markets for identical assets or liabilities that may be accessed at the measurement date.  Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.  For Level 1 valuation of marketable securities, the Company utilizes market quotations provided by its primary financial institution and for the valuations of derivative financial instruments, the Company utilizes the New York Mercantile Exchange ‟NYMEX” for such valuations.

Level 2 – (a) quoted prices for similar assets or liabilities in active markets, (b) quoted prices for identical assets or liabilities but in markets that are not actively traded or in which little information is released to the public, (c) observable inputs other than quoted prices, and (d) inputs derived from observable market data.  Source data for Level 2 inputs include information provided by the NYMEX, published price data and indices, third party price survey data and broker provided forward price statistics.

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

As of December 31, 2013, the Company’s fair value assets and liabilities are summarized and categorized as follows (in thousands):

	Market Data Inputs
	Gross Level 1		Gross Level 2			Gross Level 3		Counterparty
	Quoted Prices		Observable			Unobservable		Offsets			Total
Derivatives
- Current assets	$	-	$	449		$	-	$	(54	)	$	395
- Current liabilities		-		(54	)		-		54			-
Net Value	$	-	$	395		$	-	$	-		$	395

As of December 31, 2012, the Company’s fair value assets and liabilities are summarized and categorized as follows (in thousands):

	Market Data Inputs
	Gross Level 1		Gross Level 2			Gross Level 3		Counterparty
	Quoted Prices		Observable			Unobservable		Offsets			Total
Derivatives
- Current assets	$	-	$	354		$	-	$	(270	)	$	84
- Current liabilities		-		(381	)		-		270			(111	)
Net Value	$	-	$	(27	)	$	-	$	-		$	(27	)

When determining fair value measurements, the Company makes credit valuation adjustments to reflect both its own nonperformance risk and its counterparty’s nonperformance risk.  When adjusting the fair value of derivative contracts for the effect of nonperformance risk, the impact of netting and applicable credit enhancements, such as collateral postings, thresholds, and guarantees are considered.  Credit valuation adjustments utilize Level 3 inputs, such as credit scores to evaluate the likelihood of default by the Company or its counterparties.  As of December 31, 2013 and 2012, credit valuation adjustments were not significant to the overall valuation of the Company’s fair value contracts.  As a result, fair value assets and liabilities are included in their entirety in the fair value hierarchy.

The following table illustrates the factors impacting the change in the net value of the Company’s fair value contracts for the year ended December 31, 2013 (in thousands):

	Level 1		Level 2
	Quoted Prices		Observable			Total
Net Fair Value January 1,	$	-	$	(27	)	$	(27	)
- Net realized (gains) losses		-		27			27
- Option deposit		-		615			615
- Net unrealized gains (losses)		-		(220	)		(220	)
Net Fair Value December 31,	$	-	$	395		$	395

The following table illustrates the factors impacting the change in the net value of the Company’s fair value contracts for the year ended December 31, 2012 (in thousands):

	Level 1		Level 2
	Quoted Prices		Observable			Total
Net Fair Value January 1,	$	-	$	1,338		$	1,338
- Net realized (gains) losses		-		(1,338	)		(1,338	)
- Net unrealized gains (losses)		-		(27	)		(27	)
Net Fair Value December 31,	$	-	$	(27	)	$	(27	)

Asset Retirement Obligations

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

	2013			2012
Balance on January 1,	$	1,886		$	1,568
-Liabilities incurred		431			358
-Accretion of discount		85			63
-Liabilities settled		(138	)		(103	)
-Revisions to estimates		300			-
Balance on December 31,	$	2,564		$	1,886

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

Recent Accounts Pronouncement

In December 2011, the Financial Accounting Standards Board (‟FASB”) issued 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 Company adopted ASU 2011-11 effective January 1, 2013 and the adoption of ASU 2011-11 did not have a material impact on the Company’s consolidated financial statements, but additional disclosures regarding fair value measurements resulted.

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.

XML

Transactions with Affiliates (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Chairman and Chief Executive Officer, and Certain Family Partnerships and Affiliates [Member]
Related Party Transaction [Line Items]
Investment commitments with related party	$ 12,000,000	$ 22,700,000
Due to related parties, current	38,000	42,000
Expense reimbursements from related parties	152,000	152,000	145,000
Other Affiliated Entities [Member]
Related Party Transaction [Line Items]
Expense reimbursements from related parties	69,000	64,000	42,000
Expense reimbursements to related parties	99,000	98,000	118,000
Rent expense paid	$ 481,000	$ 442,000

XML

CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
CURRENT ASSETS:
Cash and cash equivalents	$ 60,733	$ 47,239
Accounts receivable, net of allowance for doubtful accounts of $252 and $206, respectively	243,930	228,415
Inventories	27,616	28,222
Fair value contracts	395	84
Income tax receivable	2,097	1,199
Prepayments	16,779	7,712
Current assets of discontinued operations	180	11,685
Total current assets	351,730	324,556
PROPERTY AND EQUIPMENT:
Marketing	52,996	46,177
Transportation	59,185	59,101
Oil and gas (successful efforts method)	98,947	90,431
Other	1,305	1,406
Property and equipment	212,433	197,115
Less - Accumulated depreciation, depletion and amortization	(120,568)	(106,403)
Net property and equipment	91,865	90,712
OTHER ASSETS:
Deferred income tax asset	0	34
Cash deposits and other	4,487	4,199
Total Assets	448,082	419,501
CURRENT LIABILITIES:
Accounts payable	266,099	249,214
Accounts payable - related party	38	42
Fair value contracts	0	111
Accrued and other liabilities	5,583	6,959
Current deferred income taxes	358	240
Current liabilities of discontinued operations	91	9,516
Total current liabilities	272,169	266,082
LONG-TERM DEBT	0	0
OTHER LIABILITIES:
Asset retirement obligations	2,564	1,886
Deferred taxes and other liabilities	18,664	15,675
Total liabilities	293,397	283,643
COMMITMENTS AND CONTINGENCIES (NOTE 6)
SHAREHOLDERS' EQUITY:
Preferred stock, $1.00 par value, 960,000 shares authorized, none outstanding	0	0
Common stock, $.10 par value, 7,500,000 shares authorized, 4,217,596 issued and outstanding	422	422
Contributed capital	11,693	11,693
Retained earnings	142,570	123,743
Total shareholders' equity	154,685	135,858
Liabilities and shareholders' equity	$ 448,082	$ 419,501

XML

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (USD $) In Thousands, unless otherwise specified	Common Stock [Member]	Contributed Capital [Member]	Retained Earnings [Member]	Total
BALANCE at Dec. 31, 2010	$ 422	$ 11,693	$ 78,040	$ 90,155
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net earnings	0	0	22,931	22,931
Dividends paid on common stock	0	0	(2,404)	(2,404)
BALANCE at Dec. 31, 2011	422	11,693	98,567	110,682
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net earnings	0	0	27,791	27,791
Dividends paid on common stock	0	0	(2,615)	(2,615)
BALANCE at Dec. 31, 2012	422	11,693	123,743	135,858
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net earnings	0	0	21,610	21,610
Dividends paid on common stock	0	0	(2,783)	(2,783)
BALANCE at Dec. 31, 2013	$ 422	$ 11,693	$ 142,570	$ 154,685

XML

Segment Reporting (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011
Activities by segment [Abstract]
Revenues	$ 968,096,000	$ 1,060,340,000	$ 965,098,000	$ 952,435,000	$ 875,666,000	$ 794,404,000	$ 830,110,000	$ 875,905,000	$ 3,945,969,000	$ 3,376,085,000		$ 3,038,737,000
Segment Operating Earnings (loss)									43,436,000	52,766,000		43,884,000
Depreciation Depletion and Amortization									22,275,000	20,714,000		15,885,000
Property and Equipment Additions									27,602,000	51,012,000		52,252,000
Gain on property sale									683,000	6,298,000		4,394,000
Segment operating earnings [Abstract]
Segment operating earnings									43,436,000	52,766,000		43,884,000
General and administrative expenses									(9,060,000)	(8,810,000)		(8,678,000)
Operating Earnings									34,376,000	43,956,000		35,206,000
Interest income									198,000	190,000		237,000
Interest expense									(24,000)	(10,000)		(8,000)
Earnings from continuing operations before income taxes									34,550,000	44,136,000		35,435,000
Identifiable assets by segment [Abstract]
Assets	448,082,000				419,501,000				448,082,000	419,501,000		378,840,000
Marketing [Member]
Activities by segment [Abstract]
Revenues									3,863,057,000	3,292,948,000		2,961,176,000
Segment Operating Earnings (loss)									40,369,000	46,145,000		49,237,000
Depreciation Depletion and Amortization									7,682,000	5,945,000		3,724,000
Property and Equipment Additions									11,343,000	12,391,000		13,554,000
Segment operating earnings [Abstract]
Segment operating earnings									40,369,000	46,145,000		49,237,000
Identifiable assets by segment [Abstract]
Assets	306,693,000				277,920,000				306,693,000	277,920,000		253,817,000
Transportation [Member]
Activities by segment [Abstract]
Revenues									68,783,000	67,183,000		63,501,000
Segment Operating Earnings (loss)									5,180,000	10,253,000		8,521,000
Depreciation Depletion and Amortization									7,099,000	5,921,000		3,912,000
Property and Equipment Additions									3,165,000	15,538,000		14,118,000
Segment operating earnings [Abstract]
Segment operating earnings									5,180,000	10,253,000		8,521,000
Identifiable assets by segment [Abstract]
Assets	34,406,000				38,940,000				34,406,000	38,940,000		27,221,000
Oil and Gas [Member]
Activities by segment [Abstract]
Revenues									14,129,000	15,954,000		14,060,000
Segment Operating Earnings (loss)									(2,113,000)	(3,632,000)	[1]	(13,874,000)	[1]
Depreciation Depletion and Amortization									7,494,000	8,848,000		8,249,000
Property and Equipment Additions									13,094,000	23,083,000		24,580,000
Gain on property sale										2,203,000		2,923,000
Segment operating earnings [Abstract]
Segment operating earnings									(2,113,000)	(3,632,000)	[1]	(13,874,000)	[1]
Identifiable assets by segment [Abstract]
Assets	37,093,000				35,788,000				37,093,000	35,788,000		29,105,000
Other [Member]
Identifiable assets by segment [Abstract]
Assets	$ 69,890,000				$ 66,853,000				$ 69,890,000	$ 66,853,000		$ 68,697,000

[1] Oil and gas segment operating earnings include gains on property sales totaling $2,203,000 and $2,923,000 during 2012 and 2011, respectively.

XML

Concentration of Credit Risk (Tables)

12 Months Ended

Dec. 31, 2013

Concentration of Credit Risk [Abstract]

Changes in the allowance for doubtful accounts

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

	2013			2012			2011
Balance, beginning of year	$	206		$	357		$	180
Provisions for bad debts		147			-			276
Less:  Write-offs and recoveries		(101	)		(151	)		(99	)
Balance, end of year	$	252		$	206		$	357

XML

Discontinued Operations (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Refined products segment [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revenues from discontinued operations		$ 25,717,000	$ 169,412,000
Operating income (loss) from discontinued operation			788,000
Proceeds from sale of contracts and certain equipment		2,000,000
Proceeds from sale of inventory		1,546,000
Gain (loss) on disposal of discontinued operation		1,622,000
Pre-tax earnings from discontinued operation		398,000
Natural gas marketing segment [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revenues from discontinued operations	2,377,000	4,879,000	6,251,000
Employee severance and other shut-down costs	$ 416,000

XML

Segment Reporting (Tables)

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Information concerning business activities and assets by segment

The Company is engaged in the business of crude oil and natural gas marketing as well as tank truck transportation of liquid chemicals, and oil and gas exploration and production.  Information concerning the Company’s various business activities is summarized as follows (in thousands):

			Segment Operating			Depreciation Depletion and		Property and Equipment
	Revenues		Earnings (loss)			Amortization		Additions
Year ended December 31, 2013-
Marketing	$	3,863,057	$	40,369		$	7,682	$	11,343
Transportation		68,783		5,180			7,099		3,165
Oil and gas		14,129		(2,113	)		7,494		13,094
	$	3,945,969	$	43,436		$	22,275	$	27,602
Year ended December 31, 2012-
Marketing	$	3,292,948	$	46,145		$	5,945	$	12,391
Transportation		67,183		10,253			5,921		15,538
Oil and gas		15,954		(3,632	)(1)		8,848		23,083
	$	3,376,085	$	52,766		$	20,714	$	51,012
Year ended December 31, 2011-
Marketing	$	2,961,176	$	49,237		$	3,724	$	13,554
Transportation		63,501		8,521			3,912		14,118
Oil and gas		14,060		(13,874	)(1)		8,249		24,580
	$	3,038,737	$	43,884		$	15,885	$	52,252

__________________________________

(1) Oil and gassegment operating earnings include gains on property sales totaling $2,203,000 and $2,923,000 during 2012 and 2011, respectively.

Reconciliation of segment earnings to earnings before income taxes

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

	Years Ended December 31,
	2013			2012			2011
Segment operating earnings	$	43,436		$	52,766		$	43,884
- General and administrative expenses		(9,060	)		(8,810	)		(8,678	)
Operating earnings		34,376			43,956			35,206
- Interest income		198			190			237
- Interest expense		(24	)		(10	)		(8	)
Earnings from continuing operations before
income taxes and discontinued operations	$	34,550		$	44,136		$	35,435

Identifiable assets by industry segment

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

	Years Ended December 31,
	2013		2012		2011
Marketing	$	306,693	$	277,920	$	253,817
Transportation		34,406		38,940		27,221
Oil and gas		37,093		35,788		29,105
Other		69,890		66,853		68,697
	$	448,082	$	419,501	$	378,840

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CASH PROVIDED BY OPERATIONS:
Net earnings	$ 21,610	$ 27,791	$ 22,931
Adjustments to reconcile net earnings to net cash from operating activities -
Depreciation, depletion and amortization	22,275	20,714	16,260
Property sale (gains)	(683)	(6,298)	(4,394)
Dry hole costs incurred	233	43	1,212
Impairment of oil and natural gas properties	2,630	5,555	14,749
Provision for doubtful accounts	46	(51)	1,141
Deferred income taxes	3,161	5,378	7,308
Net change in fair value contracts	(389)	1,377	(97)
Decrease (increase) in accounts receivable	(4,770)	(4,820)	(45,487)
Decrease (increase) in inventories	606	(9,579)	(5,598)
Decrease (increase) in income tax receivable	(898)	(719)	1,836
Decrease (increase) in prepayments	(8,687)	2,559	(2,547)
Increase (decrease) in accounts payable	7,809	10,474	47,662
Increase (decrease) in accrued and other liabilities	(516)	1,227	1,378
Other changes, net	1,549	843	(539)
Net cash provided by operating activities	43,976	54,494	55,815
INVESTING ACTIVITIES:
Property and equipment additions	(27,602)	(51,012)	(53,276)
Insurance and state collateral (deposits) refunds	(1,179)	(582)	(495)
Proceeds from property sales	1,082	6,342	8,394
Proceeds from the sale of discontinued operations	0	3,546	0
Redemption of short-term investments	0	0	11,098
Investment in short-term investments	0	0	(11,098)
Net cash (used in) investing activities	(27,699)	(41,706)	(45,377)
FINANCING ACTIVITIES:
Dividend payments	(2,783)	(2,615)	(2,404)
Net cash (used in) financing activities	(2,783)	(2,615)	(2,404)
Increase (decrease) in cash and cash equivalents	13,494	10,173	8,034
Cash and cash equivalents at beginning of year	47,239	37,066	29,032
Cash and cash equivalents at end of year	$ 60,733	$ 47,239	$ 37,066

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
CURRENT ASSETS:
Allowance for doubtful accounts	$ 252	$ 206
SHAREHOLDERS' EQUITY:
Preferred stock - par value (in dollars per share)	$ 1.00	$ 1.00
Preferred stock - shares authorized (in shares)	960,000	960,000
Preferred stock - outstanding (in shares)	0	0
Common stock - par value (in dollars per share)	$ 0.10	$ 0.10
Common stock - shares authorized (in shares)	7,500,000	7,500,000
Common stock - shares issued (in shares)	4,217,596	4,217,596
Common stock - shares outstanding (in shares)	4,217,596	4,217,596

XML

Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Data (Unaudited) [Abstract]

Quarterly Financial Data (Unaudited)

(10)  Quarterly Financial Data (Unaudited) -

Selected quarterly financial data and earnings per share of the Company are presented below for the years ended December 31, 2013 and 2012 (in thousands, except per share data):

				Earnings from
				Continuing Operations				Net Earnings				Dividends
		Revenues		Amount		Per Share		Amount		Per Share		Amount		Per Share
	2013 -
March 31		$	952,435	$	8,073	$	1.91	$	8,015	$	1.90	$	-	$	-
June 30			965,098		6,521		1.55		6,330		1.50		928		.22
September 30			1,060,340		7,238		1.72		7,156		1.70		927		.22
December 31			968,096		289		.06		109		.02		928		.22
Total		$	3,945,969	$	22,121	$	5.24	$	21,610	$	5.12	$	2,783	$	.66
	2012 -
March 31		$	875,905	$	5,944	$	1.41	$	6,575	$	1.56	$	-	$	-
June 30			830,110		5,333		1.26		5,386		1.28		-		-
September 30			794,404		8,355		1.98		8,263		1.96		-		-
December 31			875,666		7,840		1.86		7,567		1.79		2,615		.62
Total		$	3,376,085	$	27,472	$	6.51	$	27,791	$	6.59	$	2,615	$	.62

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

XML

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Mar. 01, 2014	Jun. 28, 2013
Document and Entity Information [Abstract]
Entity Registrant Name	ADAMS RESOURCES & ENERGY, INC.
Entity Central Index Key	0000002178
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Public Float			$ 144,823,864
Entity Common Stock, Shares Outstanding		4,217,596
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2013

XML

Oil and Gas Producing Activities (Unaudited)

12 Months Ended

Dec. 31, 2013

Oil and Gas Producing Activities (Unaudited) [Abstract]

Oil and Gas Producing Activities (Unaudited)

(11) Oil and Gas Producing Activities (Unaudited)

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

Oil and Gas Producing Activities -

Total costs incurred in oil and gas exploration and development activities, all incurred within the United States, were as follows (in thousands):

	Years Ended December 31,
	2013		2012		2011
Property acquisition costs
Unproved	$	1,444	$	1,965	$	3,591
Proved		-		-		-
Exploration costs
Expensed		1,619		1,151		9,166
Capitalized		-		-		-
Development costs		10,160		20,219		12,133
Total costs incurred	$	13,223	$	23,335	$	24,890

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

	December 31,
	2013			2012
Unproved oil and gas properties	$	7,578		$	8,349
Proved oil and gas properties		91,369			82,083
		98,947			90,432
Accumulated depreciation, depletion
and amortization		(64,169	)		(57,833	)
Net capitalized cost	$	34,778		$	32,599

Estimated Oil and Natural Gas Reserves  -

The following information regarding estimates of the Company’s proved oil and gas reserves, all located in Texas and the south central region of the United States, is based on reports prepared on behalf of the Company by its independent petroleum engineers. Because oil and gas reserve estimates are inherently imprecise and require extensive judgments of reservoir engineering data, they are generally less precise than estimates made in conjunction with financial disclosures. The revisions of previous estimates as reflected in the table below result from changes in commodity pricing assumptions and from more precise engineering calculations based upon additional production histories and price changes.

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

	Years Ended December 31,
	2013						2012						2011
	Natural						Natural						Natural
	Gas			Oil			Gas			Oil			Gas			Oil
	(Mcf’s)			(Bbls.)			(Mcf’s)			(Bbls.)			(Mcf’s)			(Bbls.)
Total proved reserves-
Beginning of year		8,837			307			9,661			292			7,794			267
Revisions of previous estimates		(1,438	)		(17	)		(507	)		29			(520	)		(24	)
Oil and gas reserves sold		(28	)		-			(104	)		(54	)		(2,148	)		(26	)
Extensions, discoveries and
other reserve additions		523			180			2,395			138			6,430			137
Production		(1,608	)		(102	)		(2,608	)		(98	)		(1,895	)		(62	)
End of year		6,286			368			8,837			307			9,661			292

The components of proved oil and gas reserves for the three years ended December 31, 2013 is presented below.  All reserves are in the United States (in thousands):

	Years Ended December 31,
	2013				2012				2011
	Natural				Natural				Natural
	Gas		Oil		Gas		Oil		Gas		Oil
	(Mcf’s)		(Bbls.)		(Mcf’s)		(Bbls.)		(Mcf’s)		(Bbls.)
Proved developed reserves		6,157		367		8,708		306		9,433		277
Proved undeveloped reserves		129		1		129		1		228		15
Total proved reserves		6,286		368		8,837		307		9,661		292

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

The Company employs third party petroleum consultant, Ryder Scott Company, to prepare its oil and gas reserve data estimates as of December 31, 2013, 2012 and 2011.  The firm of Ryder Scott is well recognized within the industry for more than 50 years.  As prescribed by the SEC, such proved reserves were estimated using 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period, and year-end production and development costs for each of the years presented, all without escalation.

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

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

The standardized measure of discounted future net cash flows was determined based on the economic conditions in effect at the end of the years presented, except in those instances where fixed and determinable gas price escalations are included in contracts.  The disclosures below do not purport to present the fair market value of the Company’s oil and gas reserves.  An estimate of the fair market value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, a discount factor more representative of the time value of money and risks inherent in reserve estimates.  The standardized measure of discounted future net cash flows is presented as follows (in thousands):

	Years Ended December 31,
	2013			2012			2011
Future gross revenues	$	64,495		$	59,793		$	73,626
Future costs -
Lease operating expenses		(19,207	)		(16,357	)		(19,788	)
Development costs		(119	)		(299	)		(2,198	)
Future net cash flows before income taxes		45,169			43,137			51,640
Discount at 10% per annum		(17,729	)		(17,976	)		(19,439	)
Discounted future net cash flows
before income taxes		27,440			25,161			32,201
Future income taxes, net of discount at
10% per annum		(9,604	)		(8,806	)		(11,270	)
Standardized measure of discounted
future net cash flows	$	17,836		$	16,355		$	20,931

The reserve estimates provided at December 31, 2013, 2012 and 2011 are based on aggregate prices of $94.99, $93.85 and $95.85 per barrel for crude oil and $4.69, $3.51 and $4.69 per mcf for natural gas, respectively.  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 SEC regulations.  The price reported in the reserve disclosure for natural gas for 2013 includes the value of associated natural gas liquids.

  The effect of income taxes and discounting on the standardized measure of discounted future net cash flows is presented as follows (in thousands):

	Years ended December 31,
	2013			2012			2011
Future net cash flows before income taxes	$	45,169		$	43,137		$	51,640
Future income taxes		(15,809	)		(15,098	)		(18,074	)
Future net cash flows		29,360			28,039			33,566
Discount at 10% per annum		(11,524	)		(11,684	)		(12,635	)
Standardized measure of discounted
future net cash flows	$	17,836		$	16,355		$	20,931

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

	Years Ended December 31,
	2013			2012			2011
Beginning of year	$	16,355		$	20,931		$	16,672
Sale of oil and gas reserves		-			(3,802	)		(7,429	)
Net change in prices and production costs		9,341			(5,313	)		791
New field discoveries and extensions, net of future
production costs		9,767			9,513			18,769
Sales of oil and gas produced, net of production costs		(8,373	)		(8,953	)		(7,723	)
Net change due to revisions in quantity estimates		(3,624	)		(940	)		(1,739	)
Accretion of discount		1,797			1,944			1,678
Production rate changes and other		(6,629	)		511			2,204
Net change in income taxes		(798	)		2,464			(2,292	)
End of year	$	17,836		$	16,355		$	20,931

Results of Operations for Oil and Gas Producing Activities -

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

	Years Ended December 31,
	2013			2012			2011
Revenues	$	14,129		$	15,954		$	14,060
Costs and expenses -
Production		(5,756	)		(7,091	)		(6,337	)
Producing property impairment		(1,373	)		(4,699	)		(7,105	)
Exploration		(1,619	)		(1,151	)		(9,166	)
Oil and natural gas property sale gain		-			2,203			2,923
Depreciation, depletion and amortization		(7,494	)		(8,848	)		(8,249	)
Operating income (loss) before income taxes		(2,113	)		(3,632	)		(13,874	)
Income tax (expense) benefit		739			1,271			4,854
Operating income (loss)	$	(1,374	)	$	(2,361	)	$	(9,020	)

XML

CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
REVENUES:
Marketing	$ 3,863,057	$ 3,292,948	$ 2,961,176
Transportation	68,783	67,183	63,501
Oil and natural gas	14,129	15,954	14,060
Total revenues	3,945,969	3,376,085	3,038,737
COSTS AND EXPENSES:
Marketing	3,815,006	3,240,858	2,908,215
Transportation	56,504	51,009	51,068
Oil and natural gas operations	8,748	12,941	22,608
Oil and natural gas property sale (gain)	0	(2,203)	(2,923)
General and administrative	9,060	8,810	8,678
Depreciation, depletion and amortization	22,275	20,714	15,885
Total costs and expenses	3,911,593	3,332,129	3,003,531
Operating Earnings	34,376	43,956	35,206
Other Income (Expense):
Interest income	198	190	237
Interest expense	(24)	(10)	(8)
Earnings from continuing operations before income taxes	34,550	44,136	35,435
Income Tax (Provision) Benefit:
Current	(9,269)	(11,286)	(5,133)
Deferred	(3,160)	(5,378)	(7,584)
Income tax (provision) benefit	(12,429)	(16,664)	(12,717)
Earnings from continuing operations	22,121	27,472	22,718
Earnings (loss) from discontinued operations net of tax (provision) benefit of $275, $(172) and $(114) respectively	(511)	319	213
Net Earnings	$ 21,610	$ 27,791	$ 22,931
EARNINGS PER SHARE:
From continuing operations (in dollars per share)	$ 5.24	$ 6.51	$ 5.39
From discontinued operations (in dollars per share)	$ (0.12)	$ 0.08	$ 0.05
Basic and diluted net earnings per share (in dollars per share)	$ 5.12	$ 6.59	$ 5.44
Dividends declared per common share (in dollars per share)	$ 0.66	$ 0.62	$ 0.57

XML

Transactions with Affiliates

12 Months Ended

Dec. 31, 2013

Transactions with Affiliates [Abstract]

Transactions with Affiliates

(5)  Transactions with Affiliates

The late Mr. K. S. Adams, Jr., former Chairman of the Board and certain of his family partnerships and affiliates have participated as working interest owners with the Company’s subsidiary, Adams Resources Exploration Corporation.  Mr. Adams and such affiliates participated on terms similar to those afforded other non-affiliated working interest owners. In recent years, such related party transactions generally resulted after the Company first identified oil and gas prospects of interest.  Typically the available dollar commitment to participate in such transactions was greater than the amount management was comfortable putting at risk.  In such event, the Company first determined the percentage of the transaction it wanted to obtain, which allowed a related party to participate in the investment to the extent there was excess available.  In those instances where there was no excess availability there was no related party participation.  Similarly, related parties were not required to participate, nor was the Company obligated to offer any such participation to a related or other party.  When such related party transactions occurred, they were individually reviewed and approved by the Audit Committee comprised of the independent directors on the Company’s Board of Directors.  During 2013 and 2012, the Company’s investment commitments totaled approximately $12 million and $22.7 million, respectively, in those oil and gas projects where a related party was also participating in such investments.  As of December 31, 2013 and 2012, the Company owed a combined net total of $38,000 and $42,000, respectively, to these related parties.  In connection with the operation of certain oil and gas properties, the Company also charges such related parties for administrative overhead primarily as prescribed by the Council of Petroleum Accountants Society Bulletin 5. Such overhead recoveries totaled $152,000, $152,000 and $145,000 for the years ended December 31, 2013, 2012, and 2011, respectively.

The Company also enters into certain transactions in the normal course of business with other affiliated entities including direct cost reimbursement for shared phone and secretarial services.  For the years ended December 31, 2013, 2012 and 2011, the affiliated entities charged the Company $69,000, $64,000 and $42,000, respectively, of expense reimbursement and the Company charged the affiliates $99,000, $98,000 and $118,000, respectively, for such expense reimbursements. In January 2012, the Company relocated its primary office lease space to a building operated by an affiliated entity.  The lease rental rate was determined by an independent appraisal.  Rental expense paid to the related party for 2013 and 2012 totaled $481,000 and $442,000, respectively.

XML

Employee Benefits

12 Months Ended

Dec. 31, 2013

Employee Benefits [Abstract]

Employee Benefits

(4)  Employee Benefits

The Company maintains a 401(k) savings plan for the benefit of its employees.  The Company’s contributory expenses for the plan were $674,000, $645,000 and $597,000 in 2013, 2012 and 2011, respectively. No other pension or retirement plans are maintained by the Company.

XML

Guarantees (Tables)

12 Months Ended

Dec. 31, 2013

Guarantees [Abstract]

Parental guaranteed obligations

As of December 31, 2013, parental guaranteed obligations are approximately as follows (in thousands):

	2014		2015		2016		2017		Thereafter		Total
Commodity purchases	$	78,747		-		-		-		-		78,747
Letters of credit		14,600		-		-		-		-		14,600
	$	93,347	$	-	$	-	$	-	$	-	$	93,347

XML

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Summary of Significant Accounting Policies [Abstract]

Principles of Consolidation

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Adams Resources & Energy, Inc., a Delaware corporation (‟ARE”) together with 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, 2013 were evaluated through the date of issuance of these financial statements.

Nature of Operations

Nature of Operations

The Company is engaged in the business of crude oil marketing, 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

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

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

Allowance for Doubtful Accounts

Accounts receivable result from sales of crude oil, natural gas and trucking services.  Marketing business wholesale level sales of crude oil comprise in excess of 90 percent of accounts receivable and under industry practices, such items are ‟settled” and paid in cash within 20 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 trucking services.  For this component of receivables, the allowance for doubtful accounts is determined based on a review of specific accounts combined with a review of the general status of the aging of all accounts.

Inventories

Inventories

Inventory consists of crude oil held in storage tanks and at third-party pipelines as part of the Company’s crude oil marketing operations.  Crude oil inventory is carried at the lower of average cost or market.

Prepayments

Prepayments

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

	December 31,
	2013		2012
Cash collateral deposits for commodity purchases	$	13,705	$	5,000
Insurance premiums		2,490		1,872
Rents, license and other		584		840
	$	16,779	$	7,712

Property and Equipment

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 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, 2013, 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, 2013, 2012 and 2011, there were $1,373,000, $4,699,000 and $7,105,000 respectively, of impairment provisions on producing oil and gas properties.

Fair value measurements for producing oil and gas properties that were subject to fair value impairment for the years ended December 31, 2013 and 2012 summarized as follows (in thousands):

	Producing Properties Subject to Fair Value Impairment
	2013			2012
Net book value at January 1	$	13,180		$	11,073
Property additions		5,661			13,083
Depletion taken		(3,727	)		(6,371	)
Impairment valuation loss		(1,373	)		(4,699	)
Net book at December 31	$	13,741		$	13,086

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

On a quarterly basis, management evaluates the carrying value of non-producing oil and gas leasehold properties and may deem them impaired based on remaining lease term, area drilling activity and the Company’s plans for the property.  This fair value measure depends highly on management’s assessment of the likelihood of continued exploration efforts in a given area and, as such, data inputs are categorized as ‟unobservable or Level 3” inputs.  Importantly, this fair value measure only applies to the write-down of capitalized costs and will never result in an increase to reported earnings.  Accordingly, impairment provisions on non-producing properties totaling $1,257,000, $856,000 and $7,644,000 were recorded for the years ending December 31, 2013, 2012 and 2011, respectively.  Capitalized costs for non-producing oil and gas leasehold interests currently represent approximately five percent of total oil and gas property costs and are categorized as follows (in thousands):

	December 31,		December 31,
	2013		2012
South Texas Project acreage	$	4,217	$	3,263
West Texas Project		116		180
Napoleonville Louisiana acreage		162		323
Other acreage areas		411		329
Total Non-producing Leasehold Costs	$	4,906	$	4,095

The South Texas, West Texas and Napoleonville acreage areas have active or scheduled drilling operations underway and holding the underlying acreage is essential to the ongoing exploration effort.  The ‟Other Acreage Areas” category consists of smaller onshore interests dispersed over a wide geographical area.  Since the Company is generally not the operator of its oil and gas property interests, it does not maintain underlying detail acreage data and is dependent on the operator when determining which specific acreage will ultimately be drilled.  However, the capitalized cost detail on a property-by-property basis is reviewed by management and deemed impaired if development is not anticipated prior to lease expiration.  Onshore leasehold periods are normally three years and may contain renewal options.  Capitalized cost activity on the ‟Other Acreage Areas” was as follows (in thousands):

	Leasehold Costs
	2013			2012
Net book value January 1	$	329		$	475
Property additions		304			810
Property sale		-			(100	)
Impairments		(222	)		(856	)
Net book value December 31	$	411		$	329

During 2012, the Company sold half of its interest in certain non-producing Kansas oil and gas properties.  Proceeds from the sale totaled $578,000 and the Company recorded a $475,000 pre-tax gain from this sale.  Also during 2012, the Company sold its interest in two oil and gas producing property units for total proceeds of $3,049,000.  The Company realized a $1,728,000 pre-tax gain from these two 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 2011 sale totaled $6.2 million and the pre-tax gain totaled $2,708,000.  Also during 2011, the Company sold a portion of its interest in certain non-producing oil and gas properties located in West Texas for $329,000 with a $125,000 pre-tax gain from this transaction.

During 2013, 2012 and 2011, the Company sold certain used trucks and equipment from its marketing and transportation segments and recorded pre-tax gains totaling $372,000, $2,482,000 and $1,246,000, respectively.

Cash Deposits and Other Assets

Cash Deposits and Other Assets

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

	December 31,
	2013		2012
Insurance collateral deposits	$	3,718	$	3,413
State collateral deposits		160		170
Materials and supplies		609		616
	$	4,487	$	4,199

Revenue Recognition

Revenue Recognition

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

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

Certain crude oil contracts may be with a single counterparty to provide for similar quantities of crude oil to be bought and sold at different locations.  These contracts are entered into for a variety of reasons, including effecting the transportation of the commodity, to minimize credit exposure, and/or to meet the competitive demands of the customer.  Such buy/sell arrangements are reflected on a net revenue basis in the accompanying consolidated financial statements.  Reporting such crude oil contracts on a gross revenue basis would increase the Company’s reported revenues by $1,602,626,000, $1,381,352,000 and $1,812,561,000 for the years ended December 31, 2013, 2012 and 2011, respectively.

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

Letter of Credit Facility

Letter of Credit Facility

The Company maintains a Credit and Security Agreement with Wells Fargo Bank to provide a $60 million stand-by letter of credit facility that is used to support the Company’s crude oil purchases within the marketing segment.  This facility is collateralized by the eligible accounts receivable within the segment and certain marketing and transportation equipment.  Stand-by letters of credit issued totaled $14.6 million and $21.9 million as of December 31, 2013 and 2012, respectively.  The issued stand-by letters of credit are cancelled as the underlying purchase obligations are satisfied by cash payment when due.  The letter of credit facility places certain restrictions on the Company’s Gulfmark Energy, Inc. subsidiary.  Such restrictions included the maintenance of a combined 1.1 to 1.0 current ratio and the maintenance of positive net earnings excluding inventory valuation changes, as defined, among other restrictions.  The Company is currently in compliance with all such financial covenants.

Statement of Cash Flows

Statement of Cash Flows

Interest paid totaled $24,000, $10,000 and $8,000 during the years ended December 31, 2013, 2012 and 2011, respectively.  Income taxes paid during these same periods totaled $9,949,000, $12,650,000, and $5,597,000, respectively.  In addition, State and Federal income tax refunds totaled $4,000, $10,000 and $2,743,000 in 2013, 2012 and 2011, respectively.  Non-cash investing activities for property and equipment items included in accounts payable as of period end were $1,507,000, $2,419,000 and $4,070,000 as of December 31, 2013, 2012 and 2011, respectively.  There were no significant non-cash financing activities in any of the periods reported.

Earnings Per Share

Earnings per Share

Earnings per share are based on the weighted average number of shares of common stock and potentially dilutive common stock shares outstanding during the period. The weighted average number of shares outstanding was 4,217,596 for 2013, 2012 and 2011.  There were no potentially dilutive securities during those periods.

Share-Based Payments

Share-Based Payments

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

Use of Estimates

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates. Examples of significant estimates used in the accompanying consolidated financial statements include the oil and gas reserve volumes that form the foundation for calculating depreciation, depletion and amortization and estimating cash flows to assess impairment triggers and estimated values associated with oil and gas properties.  Other examples include revenue accruals, the provision for bad debts, insurance related accruals, income tax permanent and timing differences, contingencies, and valuation of fair value contracts.

Income Taxes

Income Taxes

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

Use of Derivative Instruments

Use of Derivative Instruments

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

None of the Company’s derivative instruments have been designated as hedging instruments and the estimated fair value of forward month commodity contracts (derivatives) is reflected in the accompanying Consolidated Balance Sheet as of December 31, 2013 as follows (in thousands):

	Balance Sheet Location and Amount
	Current			Other		Current			Other
	Assets			Assets		Liabilities			Liabilities
Asset Derivatives
- Fair Value Commodity
Contracts at Gross Valuation	$	449		$	-	$	-		$	-
Liability Derivatives
- Fair Value Commodity
Contracts at Gross Valuation		-			-		54			-
Less Counterparty Offsets		(54	)		-		(54	)		-
As Reported Fair Value Contracts	$	395		$	-	$	-		$	-

As of December 31, 2013, one 100,000 barrel crude oil commodity put option and one commodity purchase and sale contract comprised the Company’s derivative valuations.  The purchase and sale contract encompasses approximately 175 barrels of crude oil per day in each of January and February 2014.

Forward month commodity contracts (derivatives) are reflected in the accompanying Consolidated Balance Sheet as of December 31, 2012 as follows (in thousands):

	Balance Sheet Location and Amount
	Current			Other		Current			Other
	Assets			Assets		Liabilities			Liabilities
Asset Derivatives
- Fair Value Commodity
Contracts at Gross Valuation	$	354		$	-	$	-		$	-
Liability Derivatives
- Fair Value Commodity
Contracts at Gross Valuation		-			-		381			-
Less Counterparty Offsets		(270	)		-		(270	)		-
As Reported Fair Value Contracts	$	84		$	-	$	111		$	-

As of December 31, 2012, three commodity purchase and sales contracts comprised substantially all of the Company’s derivative valuations.  Such contracts encompassed the purchase and sale of approximately 900 barrels of crude oil per day in January 2013 and continuing at 200 barrels per day through June 2013.

The Company only enters into commodity contracts with creditworthy counterparties or obtains collateral support for such activities.  As of December 31, 2013 and 2012, the Company was not holding nor had it posted any collateral to support its forward month fair value derivative activity. The Company is not subject to any credit-risk related trigger events.  The Company has no other financial investment arrangements that would serve to offset its derivative contracts.

Forward month commodity contracts (derivatives) are reflected in the accompanying Consolidated Statement of Operations for the years ended December 31, 2013, 2012 and 2011 as follows (in thousands):

	Gain (Loss)
Location	2013			2012			2011
Revenues – marketing	$	(193	)	$	(1,365	)	$	119

Fair Value Measurements

Fair Value Measurements

The carrying amount reported in the consolidated balance sheet for cash and cash equivalents, accounts receivable and accounts payable approximates fair value because of the immediate or short-term maturity of these financial instruments.  Marketable securities are recorded at fair value based on market quotations from actively traded liquid markets.

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

Fair value estimates are based on assumptions that market participants would use when pricing an asset or liability and the Company uses a fair value hierarchy of three levels that prioritizes the information used to develop those assumptions.  Currently, for all items presented herein, the Company utilizes a market approach to valuing its contracts.  On a contract by contract, forward month by forward month basis, the Company obtains observable market data for valuing its contracts.  The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data.  The fair value hierarchy is summarized as follows:

Level 1 – quoted prices in active markets for identical assets or liabilities that may be accessed at the measurement date.  Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.  For Level 1 valuation of marketable securities, the Company utilizes market quotations provided by its primary financial institution and for the valuations of derivative financial instruments, the Company utilizes the New York Mercantile Exchange ‟NYMEX” for such valuations.

Level 2 – (a) quoted prices for similar assets or liabilities in active markets, (b) quoted prices for identical assets or liabilities but in markets that are not actively traded or in which little information is released to the public, (c) observable inputs other than quoted prices, and (d) inputs derived from observable market data.  Source data for Level 2 inputs include information provided by the NYMEX, published price data and indices, third party price survey data and broker provided forward price statistics.

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

As of December 31, 2013, the Company’s fair value assets and liabilities are summarized and categorized as follows (in thousands):

	Market Data Inputs
	Gross Level 1		Gross Level 2			Gross Level 3		Counterparty
	Quoted Prices		Observable			Unobservable		Offsets			Total
Derivatives
- Current assets	$	-	$	449		$	-	$	(54	)	$	395
- Current liabilities		-		(54	)		-		54			-
Net Value	$	-	$	395		$	-	$	-		$	395

As of December 31, 2012, the Company’s fair value assets and liabilities are summarized and categorized as follows (in thousands):

	Market Data Inputs
	Gross Level 1		Gross Level 2			Gross Level 3		Counterparty
	Quoted Prices		Observable			Unobservable		Offsets			Total
Derivatives
- Current assets	$	-	$	354		$	-	$	(270	)	$	84
- Current liabilities		-		(381	)		-		270			(111	)
Net Value	$	-	$	(27	)	$	-	$	-		$	(27	)

When determining fair value measurements, the Company makes credit valuation adjustments to reflect both its own nonperformance risk and its counterparty’s nonperformance risk.  When adjusting the fair value of derivative contracts for the effect of nonperformance risk, the impact of netting and applicable credit enhancements, such as collateral postings, thresholds, and guarantees are considered.  Credit valuation adjustments utilize Level 3 inputs, such as credit scores to evaluate the likelihood of default by the Company or its counterparties.  As of December 31, 2013 and 2012, credit valuation adjustments were not significant to the overall valuation of the Company’s fair value contracts.  As a result, fair value assets and liabilities are included in their entirety in the fair value hierarchy.

The following table illustrates the factors impacting the change in the net value of the Company’s fair value contracts for the year ended December 31, 2013 (in thousands):

	Level 1		Level 2
	Quoted Prices		Observable			Total
Net Fair Value January 1,	$	-	$	(27	)	$	(27	)
- Net realized (gains) losses		-		27			27
- Option deposit		-		615			615
- Net unrealized gains (losses)		-		(220	)		(220	)
Net Fair Value December 31,	$	-	$	395		$	395

The following table illustrates the factors impacting the change in the net value of the Company’s fair value contracts for the year ended December 31, 2012 (in thousands):

	Level 1		Level 2
	Quoted Prices		Observable			Total
Net Fair Value January 1,	$	-	$	1,338		$	1,338
- Net realized (gains) losses		-		(1,338	)		(1,338	)
- Net unrealized gains (losses)		-		(27	)		(27	)
Net Fair Value December 31,	$	-	$	(27	)	$	(27	)

Asset Retirement Obligations

Asset Retirement Obligations

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

	2013			2012
Balance on January 1,	$	1,886		$	1,568
-Liabilities incurred		431			358
-Accretion of discount		85			63
-Liabilities settled		(138	)		(103	)
-Revisions to estimates		300			-
Balance on December 31,	$	2,564		$	1,886

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

Recent Accounts Pronouncement

Recent Accounts Pronouncement

In December 2011, the Financial Accounting Standards Board (‟FASB”) issued 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 Company adopted ASU 2011-11 effective January 1, 2013 and the adoption of ASU 2011-11 did not have a material impact on the Company’s consolidated financial statements, but additional disclosures regarding fair value measurements resulted.

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.

XML

Segment Reporting

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Segment Reporting

(8)  Segment Reporting

The Company is engaged in the business of crude oil and natural gas marketing as well as tank truck transportation of liquid chemicals, and oil and gas exploration and production.  Information concerning the Company’s various business activities is summarized as follows (in thousands):

			Segment Operating			Depreciation Depletion and		Property and Equipment
	Revenues		Earnings (loss)			Amortization		Additions
Year ended December 31, 2013-
Marketing	$	3,863,057	$	40,369		$	7,682	$	11,343
Transportation		68,783		5,180			7,099		3,165
Oil and gas		14,129		(2,113	)		7,494		13,094
	$	3,945,969	$	43,436		$	22,275	$	27,602
Year ended December 31, 2012-
Marketing	$	3,292,948	$	46,145		$	5,945	$	12,391
Transportation		67,183		10,253			5,921		15,538
Oil and gas		15,954		(3,632	)(1)		8,848		23,083
	$	3,376,085	$	52,766		$	20,714	$	51,012
Year ended December 31, 2011-
Marketing	$	2,961,176	$	49,237		$	3,724	$	13,554
Transportation		63,501		8,521			3,912		14,118
Oil and gas		14,060		(13,874	)(1)		8,249		24,580
	$	3,038,737	$	43,884		$	15,885	$	52,252

__________________________________

(1) Oil and gassegment operating earnings include gains on property sales totaling $2,203,000 and $2,923,000 during 2012 and 2011, respectively.

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

	Years Ended December 31,
	2013			2012			2011
Segment operating earnings	$	43,436		$	52,766		$	43,884
- General and administrative expenses		(9,060	)		(8,810	)		(8,678	)
Operating earnings		34,376			43,956			35,206
- Interest income		198			190			237
- Interest expense		(24	)		(10	)		(8	)
Earnings from continuing operations before
income taxes and discontinued operations	$	34,550		$	44,136		$	35,435

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

	Years Ended December 31,
	2013		2012		2011
Marketing	$	306,693	$	277,920	$	253,817
Transportation		34,406		38,940		27,221
Oil and gas		37,093		35,788		29,105
Other		69,890		66,853		68,697
	$	448,082	$	419,501	$	378,840

Intersegment sales are insignificant and all sales occurred in the United States.  Other identifiable assets are primarily corporate cash, corporate accounts receivable, and properties not identified with any specific segment of the Company’s business.  Accounting policies for transactions between reportable segments are consistent with applicable accounting policies as disclosed herein.

XML

Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies [Abstract]

Commitments and Contingencies

(6)  Commitments and Contingencies

The Company maintains certain operating lease arrangements with independent truck owner-operators for use of their equipment and driver services 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.  All operating lease commitments qualify for off-balance sheet treatment.  Such contracts require certain minimum monthly payments for the term of the contracts.  Rental expense for the years ended December 31, 2013, 2012, and 2011 was $8,281,000, $8,110,000 and $7,621,000, respectively.  At December 31, 2013, commitments under long-term non-cancelable operating leases and terminal arrangements for the next five years and thereafter are payable as follows:   2014 - $3,138,000; 2015 - $1,931,000; 2016 - $1,910,000; 2017 - $1,690,000; 2018 - $804,000 and $40,000 thereafter.

Under the Company’s automobile and workers’ compensation insurance policies, the Company can either receive a return of premium paid or be assessed for additional premiums up to pre-established limits. Additionally  in certain instances the risk of insured losses is shared with a group of similarly situated entities.  The Company has appropriately recognized estimated expenses and liabilities related to these policies for losses incurred but not reported to the Company or its insurance carrier of $1,796,000 and $1,545,000 as of December 31, 2013 and 2012, respectively.

Effective January 1, 2012, the Company began a self-insurance program for managing employee medical claims.  On a monthly basis, the Company establishes a liability for expected claims incurred.  As claims are paid, the liability is relieved.  As of December 31, 2013 and 2012, accrued medical claims totaled $1,129,000 and $506,000, respectively.  The Company maintains third party insurance stop-loss coverage for annual individual medical claims exceeding $100,000.  In addition, the Company maintains $2 million of umbrella insurance coverage for aggregate medical claims exceeding approximately $4.5 million for the calendar years 2013 and 2014.

During 2013 and continuing in 2014, AREC has been noticed as a defendant in a number of Louisiana based suits involving alleged environmental contamination from prior drilling operations.  Such suits typically allege improper disposal of oilfield wastes in earthen pits with one suit alleging subsidence contributing of the formation of a sink hole.  The Company is currently named as a defendant in four such suits.  The suits are styled LePetit Chateau Deluxe v. Adams Resources Exploration Corporation dated March 2004, Gustave J. LaBarre, Jr., et. al. v. Adams Resources Exploration Corporation et al dated October 2012, Edward Conner, et al v. Adams Resources Exploration Corporation dated October 2013 and Henning Management, LLC v. Adams Resources Exploration Corporation dated November 2013.  Each suit involves multiple industry defendants with substantially larger proportional interest in the properties.  The plaintiffs in each of these matters are seeking unspecified compensatory and punitive damages.    While management does not believe that a material adverse effect will result from the claims, significant attorney fees will be incurred to defend this item.  As of December 31, 2013, the Company has accrued $200,000 of future legal costs for these matters.

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

XML

Guarantees

12 Months Ended

Dec. 31, 2013

Guarantees [Abstract]

Guarantees

(7)  Guarantees

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

As of December 31, 2013, parental guaranteed obligations are approximately as follows (in thousands):

	2014		2015		2016		2017		Thereafter		Total
Commodity purchases	$	78,747		-		-		-		-		78,747
Letters of credit		14,600		-		-		-		-		14,600
	$	93,347	$	-	$	-	$	-	$	-	$	93,347

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

XML

Discontinued Operations

12 Months Ended

Dec. 31, 2013

Discontinued Operations [Abstract]

Discontinued Operations

(9)  Discontinued Operations

On February 27, 2012, the Company completed the sale of contracts, inventory and certain equipment associated with the refined products segment of its marketing business.  Revenues from this segment included in net earnings from discontinued operations totaled $25,717,000 and $169,412,000 for the years ended December 31, 2012 and 2011, respectively.  This business had experienced marginal results in recent years including an operating loss of $788,000 for the year 2011.  The Company received $2 million in cash proceeds plus a cash payment of $1,546,000 for the agreed value of refined product inventories on the date of sale.  The net gain recognized upon this sale totaled $1,622,000.  The Company conducted an orderly wind-down of the operation during 2012 and 2013 which primarily consisted of collecting outstanding accounts receivable and satisfying all existing obligations.  The Company’s fee interest in certain parcels of real estate was retained and the estimated fair value of such properties exceeded the Company’s cost basis in the properties.  Therefore, an impairment assessment of long-lived assets was not necessary.  The proceeds secured from this transaction exceeded the sum of carrying costs of the assets sold plus severance and other wind-down costs and, as a result, pre-tax earnings from this former segment totaled $398,000 for the year ended December 31, 2012.

Due to inadequate earnings, effective October 31, 2013, the Company completed an orderly wind-down and closure of its natural gas marketing segment.  Revenues from this segment included in net earnings from discontinued operations totaled $2,377,000, $4,879,000 and $6,251,000 for the years ended December 31, 2013, 2012 and 2011, respectively.  The Company incurred employee severance and other shut-down costs totaling $416,000 as a result of this event.  All obligations were satisfied and no further events are anticipated.

XML

Guarantees (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013
Parental guaranteed obligations [Abstract]
Commodity purchases, 2014	$ 78,747
Commodity purchases, 2015	0
Commodity purchases, 2016	0
Commodity purchases, 2017	0
Commodity purchases, Thereafter	0
Commodity purchases, Total	78,747
Guaranteed obligations, 2014	93,347
Guaranteed obligations, 2015	0
Guaranteed obligations, 2016	0
Guaranteed obligations, 2017	0
Guaranteed obligations Thereafter	0
Guaranteed obligations, Total	93,347
Letters of credit [Member]
Parental guaranteed obligations [Abstract]
Letters of credit, 2014	14,600
Letters of credit, 2015	0
Letters of credit, 2016	0
Letters of credit, 2017	0
Letters of credit, Thereafter	0
Letters of credit, Total	$ 14,600

XML

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Income Taxes [Abstract]

Components of the Company's income tax (provision) benefit

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

	Years ended December 31,
	2013			2012			2011
Current:
Federal	$	(8,102	)	$	(10,282	)	$	(4,336	)
State		(892	)		(1,176	)		(1,187	)
		(8,994	)		(11,458	)		(5,523	)
Deferred:
Federal		(2,682	)		(4,940	)		(7,407	)
State		(478	)		(438	)		99
		(3,160	)		(5,378	)		(7,308	)
	$	(12,154	)	$	(16,836	)	$	(12,831	)

Income tax (provision) benefit allocable to continuing and discontinued operations

The following table summarizes the components of the income tax (provision) benefit (in thousands):

	Years ended December 31,
	2013			2012			2011
From continuing operations	$	(12,429	)	$	(16,664	)	$	(12,717	)
From discontinued operations		275			(172	)		(114	)
	$	(12,154	)	$	(16,836	)	$	(12,831	)

Reconciliation of taxes computed at the corporate federal income tax rate to the reported income tax (provision)

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

	Years ended December 31,
	2013			2012			2011
Statutory federal income tax (provision) benefit	$	(11,819	)	$	(15,619	)	$	(12,517	)
State income tax (provision) benefit		(891	)		(1,049	)		(707	)
Federal statutory depletion		522			36			393
Other		34			(204	)		-
	$	(12,154	)	$	(16,836	)	$	(12,831	)

Components of the federal deferred tax asset (liability)

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

	Years Ended December 31,
	2013			2012
Current deferred tax asset (liability)
Allowance for doubtful accounts	$	424		$	581
Prepaid and other insurance		(855	)		(815	)
Fair value contracts		73			(6	)
Net current deferred liability		(358	)		(240	)
Long-term deferred tax asset (liability)
Property		(18,964	)		(15,957	)
Uniform capitalization		613			552
Other		(283	)		(221	)
Net long-term deferred tax  liability		(18,634	)		(15,626	)
Net deferred tax liability	$	(18,992	)	$	(15,866	)

Earliest tax years remaining for Federal and major states of operations

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

	Earliest Open
	Tax Year
Federal	2010
Texas	2009
Louisiana	2010
Michigan	2010

XML

Oil and Gas Producing Activities (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Oil and Gas Producing Activities (Unaudited) [Abstract]

Cost incurred in oil and gas exploration and development activities

Total costs incurred in oil and gas exploration and development activities, all incurred within the United States, were as follows (in thousands):

	Years Ended December 31,
	2013		2012		2011
Property acquisition costs
Unproved	$	1,444	$	1,965	$	3,591
Proved		-		-		-
Exploration costs
Expensed		1,619		1,151		9,166
Capitalized		-		-		-
Development costs		10,160		20,219		12,133
Total costs incurred	$	13,223	$	23,335	$	24,890

Capitalized costs relating to oil and gas producing activities

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

	December 31,
	2013			2012
Unproved oil and gas properties	$	7,578		$	8,349
Proved oil and gas properties		91,369			82,083
		98,947			90,432
Accumulated depreciation, depletion
and amortization		(64,169	)		(57,833	)
Net capitalized cost	$	34,778		$	32,599

Proved developed and undeveloped oil and gas reserves

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

	Years Ended December 31,
	2013						2012						2011
	Natural						Natural						Natural
	Gas			Oil			Gas			Oil			Gas			Oil
	(Mcf’s)			(Bbls.)			(Mcf’s)			(Bbls.)			(Mcf’s)			(Bbls.)
Total proved reserves-
Beginning of year		8,837			307			9,661			292			7,794			267
Revisions of previous estimates		(1,438	)		(17	)		(507	)		29			(520	)		(24	)
Oil and gas reserves sold		(28	)		-			(104	)		(54	)		(2,148	)		(26	)
Extensions, discoveries and
other reserve additions		523			180			2,395			138			6,430			137
Production		(1,608	)		(102	)		(2,608	)		(98	)		(1,895	)		(62	)
End of year		6,286			368			8,837			307			9,661			292

Components of proved oil and gas reserves

The components of proved oil and gas reserves for the three years ended December 31, 2013 is presented below.  All reserves are in the United States (in thousands):

	Years Ended December 31,
	2013				2012				2011
	Natural				Natural				Natural
	Gas		Oil		Gas		Oil		Gas		Oil
	(Mcf’s)		(Bbls.)		(Mcf’s)		(Bbls.)		(Mcf’s)		(Bbls.)
Proved developed reserves		6,157		367		8,708		306		9,433		277
Proved undeveloped reserves		129		1		129		1		228		15
Total proved reserves		6,286		368		8,837		307		9,661		292

Standardized measure of discounted future net cash flows

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

	Years Ended December 31,
	2013			2012			2011
Future gross revenues	$	64,495		$	59,793		$	73,626
Future costs -
Lease operating expenses		(19,207	)		(16,357	)		(19,788	)
Development costs		(119	)		(299	)		(2,198	)
Future net cash flows before income taxes		45,169			43,137			51,640
Discount at 10% per annum		(17,729	)		(17,976	)		(19,439	)
Discounted future net cash flows
before income taxes		27,440			25,161			32,201
Future income taxes, net of discount at
10% per annum		(9,604	)		(8,806	)		(11,270	)
Standardized measure of discounted
future net cash flows	$	17,836		$	16,355		$	20,931

Effect of income taxes and discounting on the standardized measure of discounted future net cash flows

  The effect of income taxes and discounting on the standardized measure of discounted future net cash flows is presented as follows (in thousands):

	Years ended December 31,
	2013			2012			2011
Future net cash flows before income taxes	$	45,169		$	43,137		$	51,640
Future income taxes		(15,809	)		(15,098	)		(18,074	)
Future net cash flows		29,360			28,039			33,566
Discount at 10% per annum		(11,524	)		(11,684	)		(12,635	)
Standardized measure of discounted
future net cash flows	$	17,836		$	16,355		$	20,931

Principal sources of changes in the standardized measure of discounted future net flows

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

	Years Ended December 31,
	2013			2012			2011
Beginning of year	$	16,355		$	20,931		$	16,672
Sale of oil and gas reserves		-			(3,802	)		(7,429	)
Net change in prices and production costs		9,341			(5,313	)		791
New field discoveries and extensions, net of future
production costs		9,767			9,513			18,769
Sales of oil and gas produced, net of production costs		(8,373	)		(8,953	)		(7,723	)
Net change due to revisions in quantity estimates		(3,624	)		(940	)		(1,739	)
Accretion of discount		1,797			1,944			1,678
Production rate changes and other		(6,629	)		511			2,204
Net change in income taxes		(798	)		2,464			(2,292	)
End of year	$	17,836		$	16,355		$	20,931

Results of operations for oil and gas producing activities

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

	Years Ended December 31,
	2013			2012			2011
Revenues	$	14,129		$	15,954		$	14,060
Costs and expenses -
Production		(5,756	)		(7,091	)		(6,337	)
Producing property impairment		(1,373	)		(4,699	)		(7,105	)
Exploration		(1,619	)		(1,151	)		(9,166	)
Oil and natural gas property sale gain		-			2,203			2,923
Depreciation, depletion and amortization		(7,494	)		(8,848	)		(8,249	)
Operating income (loss) before income taxes		(2,113	)		(3,632	)		(13,874	)
Income tax (expense) benefit		739			1,271			4,854
Operating income (loss)	$	(1,374	)	$	(2,361	)	$	(9,020	)

XML

CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CONSOLIDATED STATEMENTS OF OPERATIONS [Abstract]
Earnings (loss) from discontinued operations, tax	$ 275	$ (172)	$ (114)

XML

Concentration of Credit Risk

12 Months Ended

Dec. 31, 2013

Concentration of Credit Risk [Abstract]

Concentration of Credit Risk

(3)  Concentration of Credit Risk

Credit risk represents the amount of loss the Company would absorb if its customers failed to perform pursuant to contractual terms.  Management of credit risk involves a number of considerations, such as the financial profile of the customer, the value of collateral held, if any, specific terms and duration of the contractual agreement, and the customer’s sensitivity to economic developments.  The Company has established various procedures to manage credit exposure, including initial credit approval, credit limits, and rights of offset.  Letters of credit and guarantees are also utilized to limit credit risk. Accounts receivable associated with crude oil  marketing activities comprise approximately 90 percent of the Company’s total receivables and industry practice requires payment for such sales to occur within 20 days of the end of the month following a transaction.  The Company’s customer makeup, credit policies and the relatively short duration of receivables mitigate the uncertainty typically associated with receivables management.

The Company’s largest customers consist of large multinational integrated oil companies and independent domestic refiners of crude oil.  In addition, the Company transacts business with independent oil producers, major chemical concerns, crude oil trading companies and a variety of commercial energy users.  Within this group of customers, the Company generally derives approximately 50 percent of its revenues from three to four large crude oil refining concerns.  While the Company has ongoing established relationships with certain domestic refiners of crude oil, alternative markets are readily available since the Company supplies less than one percent of U. S. domestic refiner demand.  As a fungible commodity delivered to major Gulf Coast supply points, the Company’s crude oil sales can be readily delivered to alternative end markets.  Management believes that a loss of any of those customers where the Company currently derives more than 10 percent of its revenues would not have a material adverse effect on the Company’s operations.

The Company had revenues from four customers in 2013 that comprised 18.5 percent, 17.7 percent, 15.8 percent and 10.4 percent of total revenues, respectively.  During 2012, three customers comprised 20.2 percent, 17.9 percent and 16.8 percent of total revenues.  During 2011, four customers comprised 18.2 percent, 15.4 percent, 13.4 percent and 11.3 percent of total revenues.

The Company had accounts receivable from three customers that comprised 16.0 percent, 15.8 percent and 12.7 percent, respectively of total accounts receivables at December 31, 2013.  Three customers comprised 22.1 percent, 21.4 percent and 11.4 percent, respectively, of total accounts receivable as of December 31, 2012.  Two customers comprised 24.5 percent and 21.5 percent, respectively, of total accounts receivable at December 31, 2011.

An allowance for doubtful accounts is provided where appropriate and accounts receivable presented herein are net of allowances for doubtful accounts of $252,000 and $206,000 at December 31, 2013 and 2012, respectively.

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

	2013			2012			2011
Balance, beginning of year	$	206		$	357		$	180
Provisions for bad debts		147			-			276
Less:  Write-offs and recoveries		(101	)		(151	)		(99	)
Balance, end of year	$	252		$	206		$	357

XML

Summary of Significant Accounting Policies (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 Contract mi	Dec. 31, 2012 Contract	Dec. 31, 2011
Nature of Operations [Abstract]
Primary area of operation (in miles)	1,000
Allowance for Doubtful Accounts [Abstract]
Percentage of crude oil and natural gas sales in accounts receivable (in hundredths)	90.00%
Number of days, cash is received from transaction date	20 days
Components of prepayments and other [Abstract]
Cash collateral deposits for commodity purchases	$ 13,705,000	$ 5,000,000
Insurance premiums	2,490,000	1,872,000
Rents, license and other	584,000	840,000
Prepayments, total	16,779,000	7,712,000
Property, Plant and Equipment [Line Items]
Exploratory drilling costs	0
Fair value measurements for producing oil and gas properties that were subject to fair value impairment [Abstract]
Property additions	13,223,000	23,335,000	24,890,000
Impairment valuation loss	(2,630,000)	(5,555,000)	(14,749,000)
Total Non-producing Leasehold Costs	4,906,000	4,095,000
Pre-tax gain on sale of oil and gas properties	0	2,203,000	2,923,000
Pre-tax gain on sale of equipment	372,000	2,482,000	1,246,000
Cash Deposits and Other Assets [Abstract]
Insurance collateral deposits	3,718,000	3,413,000
State collateral deposits	160,000	170,000
Materials and supplies	609,000	616,000
Cash deposits and other	4,487,000	4,199,000
Revenue Recognition [Abstract]
Increase in the entity's reported revenue	1,602,626,000	1,381,352,000	1,812,561,000
Statement of Cash Flows [Abstract]
Interest paid	24,000	10,000	8,000
Income taxes paid	9,949,000	12,650,000	5,597,000
Proceeds from income tax refunds	4,000	10,000	2,743,000
Non-cash investing activities for property and equipment	1,507,000	2,419,000	4,070,000
Earnings Per Share [Abstract]
Weighted average number of shares outstanding (in shares)	4,217,596	4,217,596	4,217,596
Fair Value Forward Hydrocarbon Commodity Contracts at gross valuation [Abstract]
Number of contracts held	1	3
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Current Assets [Member]
Fair Value Forward Hydrocarbon Commodity Contracts at gross valuation [Abstract]
Asset Derivatives	449,000	354,000
Liability Derivatives	0	0
Less Counterparty Offsets	(54,000)	(270,000)
As Reported Fair Value Contracts	395,000	84,000
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Other Assets [Member]
Fair Value Forward Hydrocarbon Commodity Contracts at gross valuation [Abstract]
Asset Derivatives	0	0
Liability Derivatives	0	0
Less Counterparty Offsets	0	0
As Reported Fair Value Contracts	0	0
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Current Liabilities [Member]
Fair Value Forward Hydrocarbon Commodity Contracts at gross valuation [Abstract]
Asset Derivatives	0	0
Liability Derivatives	54,000	381,000
Less Counterparty Offsets	(54,000)	(270,000)
As Reported Fair Value Contracts	0	111,000
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Other Liabilities [Member]
Fair Value Forward Hydrocarbon Commodity Contracts at gross valuation [Abstract]
Asset Derivatives	0	0
Liability Derivatives	0	0
Less Counterparty Offsets	0	0
As Reported Fair Value Contracts	0	0
Commodity Contract [Member] | Jan 2014 to Feb 2014 [Member]
Fair Value Forward Hydrocarbon Commodity Contracts at gross valuation [Abstract]
Volume committed per day under commodity purchase and sale contract (in barrels)	175
Commodity Contract [Member] | Jan 2013 [Member]
Fair Value Forward Hydrocarbon Commodity Contracts at gross valuation [Abstract]
Volume committed per day under commodity purchase and sale contract (in barrels)		900
Commodity Contract [Member] | Feb 2013 to June 2013 [Member]
Fair Value Forward Hydrocarbon Commodity Contracts at gross valuation [Abstract]
Volume committed per day under commodity purchase and sale contract (in barrels)		200
Commodity Put Option [Member]
Fair Value Forward Hydrocarbon Commodity Contracts at gross valuation [Abstract]
Number of contracts held	1
Volume of crude oil committed under commodity put option (in barrels)	100,000
Wells Fargo Bank [Member]
Letter of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity	60,000,000
Standby letters of credit issued	14,600,000	21,900,000
Covenant terms	Such restrictions included the maintenance of a combined 1.1 to 1.0 current ratio and the maintenance of positive net earnings excluding inventory valuation changes, as defined, among other restrictions. The Company is currently in compliance with all such financial covenants.
Current ratio	1.1
Minimum [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, useful life	3 years
Maximum [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, useful life	20 years
Producing Oil and Gas Properties [Member]
Fair value measurements for producing oil and gas properties that were subject to fair value impairment [Abstract]
Impairment valuation loss	1,373,000	4,699,000	7,105,000
Proceeds from sale of oil and gas properties		3,049,000	6,200,000
Pre-tax gain on sale of oil and gas properties		1,728,000	2,708,000
Producing Oil and Gas Properties Impaired in 2013 [Member]
Fair value measurements for producing oil and gas properties that were subject to fair value impairment [Abstract]
Net book value at January 1	13,180,000
Property additions	5,661,000
Depletion taken	(3,727,000)
Impairment valuation loss	(1,373,000)
Net book at December 31	13,741,000
Producing Oil and Gas Properties Impaired in 2012 [Member]
Fair value measurements for producing oil and gas properties that were subject to fair value impairment [Abstract]
Net book value at January 1		11,073,000
Property additions		13,083,000
Depletion taken		(6,371,000)
Impairment valuation loss		(4,699,000)
Net book at December 31		13,086,000
Non-Producing Oil and Gas Properties [Member]
Fair value measurements for producing oil and gas properties that were subject to fair value impairment [Abstract]
Impairment valuation loss	1,257,000	856,000	7,644,000
Capitalized costs for non producing oil and gas leasehold interests specified as percentage of total costs (in hundredths)	5.00%
Proceeds from sale of oil and gas properties		578,000	329,000
Pre-tax gain on sale of oil and gas properties		475,000	125,000
South Texas Project acreage [Member]
Fair value measurements for producing oil and gas properties that were subject to fair value impairment [Abstract]
Total Non-producing Leasehold Costs	4,217,000	3,263,000
West Texas Project [Member]
Fair value measurements for producing oil and gas properties that were subject to fair value impairment [Abstract]
Total Non-producing Leasehold Costs	116,000	180,000
Napoleonville, Louisiana acreage [Member]
Fair value measurements for producing oil and gas properties that were subject to fair value impairment [Abstract]
Total Non-producing Leasehold Costs	162,000	323,000
Other acreage areas [Member]
Fair value measurements for producing oil and gas properties that were subject to fair value impairment [Abstract]
Net book value at January 1	329,000	475,000
Property additions	304,000	810,000
Property sale	0	(100,000)
Impairment valuation loss	(222,000)	(856,000)
Net book at December 31	411,000	329,000
Total Non-producing Leasehold Costs	$ 411,000	$ 329,000
Onshore leasehold [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, useful life	3 years

XML

Oil and Gas Producing Activities (Unaudited) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Property acquisition costs [Abstract]
Unproved	$ 1,444,000	$ 1,965,000	$ 3,591,000
Proved	0	0	0
Exploration costs [Abstract]
Expensed	1,619,000	1,151,000	9,166,000
Capitalized	0	0	0
Development costs	10,160,000	20,219,000	12,133,000
Total costs incurred	13,223,000	23,335,000	24,890,000
Capitalized costs relating to oil and gas producing activities [Abstract]
Unproved oil and gas properties	7,578,000	8,349,000
Proved oil and gas properties	91,369,000	82,083,000
Gross capitalized cost	98,947,000	90,432,000
Accumulated depreciation, depletion and amortization	(64,169,000)	(57,833,000)
Net capitalized cost	34,778,000	32,599,000
Components of proved oil and gas reserves [Abstract]
Period of average estimated price of proved reserves	12 months
Standardized measure of discounted future net cash flows [Abstract]
Future gross revenues	64,495,000	59,793,000	73,626,000
Future costs [Abstract]
Lease operating expenses	(19,207,000)	(16,357,000)	(19,788,000)
Development costs	(119,000)	(299,000)	(2,198,000)
Future net cash flows before income taxes	45,169,000	43,137,000	51,640,000
Discount at 10% per annum	(17,729,000)	(17,976,000)	(19,439,000)
Discounted future net cash flows before income taxes	27,440,000	25,161,000	32,201,000
Future income taxes, net of discount at 10% per annum	(9,604,000)	(8,806,000)	(11,270,000)
Standardized measure of discounted future net cash flows	17,836,000	16,355,000	20,931,000
Effect of income taxes and discounting on the standardized measure of discounted future net cash flows [Abstract]
Future net cash flows before income taxes	45,169,000	43,137,000	51,640,000
Future income taxes	(15,809,000)	(15,098,000)	(18,074,000)
Future net cash flows	29,360,000	28,039,000	33,566,000
Discount at 10% per annum	(11,524,000)	(11,684,000)	(12,635,000)
Standardized measure of discounted future net cash flows	17,836,000	16,355,000	20,931,000
Principal sources of changes in the standardized measure of discounted future net flows [Abstract]
Beginning of year	16,355,000	20,931,000	16,672,000
Sale of oil and gas reserves	0	(3,802,000)	(7,429,000)
Net change in prices and production costs	9,341,000	(5,313,000)	791,000
New field discoveries and extensions, net of future production costs	9,767,000	9,513,000	18,769,000
Sales of oil and gas produced, net of production costs	(8,373,000)	(8,953,000)	(7,723,000)
Net change due to revisions in quantity estimates	(3,624,000)	(940,000)	(1,739,000)
Accretion of discount	1,797,000	1,944,000	1,678,000
Production rate changes and other	(6,629,000)	511,000	2,204,000
Net change in income taxes	(798,000)	2,464,000	(2,292,000)
End of year	17,836,000	16,355,000	20,931,000
Results of operations for oil and gas producing activities [Abstract]
Revenues	14,129,000	15,954,000	14,060,000
Costs and expenses [Abstract]
Production	(5,756,000)	(7,091,000)	(6,337,000)
Producing property impairment	(1,373,000)	(4,699,000)	(7,105,000)
Exploration	(1,619,000)	(1,151,000)	(9,166,000)
Oil and natural gas property sale gain	0	2,203,000	2,923,000
Depreciation, depletion and amortization	(7,494,000)	(8,848,000)	(8,249,000)
Operating income (loss) before income taxes	(2,113,000)	(3,632,000)	(13,874,000)
Income tax (expense) benefit	739,000	1,271,000	4,854,000
Operating income (loss)	$ (1,374,000)	$ (2,361,000)	$ (9,020,000)
Crude Oil [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average sales prices	94.99	93.85	95.85
Natural Gas [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average sales prices	4.69	3.51	4.69
Oil [Member]
Total proved reserves [Abstract]
Beginning of year	307,000	292,000	267,000
Revisions of previous estimates	(17,000)	29,000	(24,000)
Oil and gas reserves sold	0	(54,000)	(26,000)
Extensions, discoveries and other reserve additions	180,000	138,000	137,000
Production	(102,000)	(98,000)	(62,000)
End of year	368,000	307,000	292,000
Components of proved oil and gas reserves [Abstract]
Proved developed reserves	367,000	306,000	277,000
Proved undeveloped reserves	1,000	1,000	15,000
Total proved reserves	368,000	307,000	292,000
Natural Gas [Member]
Total proved reserves [Abstract]
Beginning of year	8,837,000	9,661,000	7,794,000
Revisions of previous estimates	(1,438,000)	(507,000)	(520,000)
Oil and gas reserves sold	(28,000)	(104,000)	(2,148,000)
Extensions, discoveries and other reserve additions	523,000	2,395,000	6,430,000
Production	(1,608,000)	(2,608,000)	(1,895,000)
End of year	6,286,000	8,837,000	9,661,000
Components of proved oil and gas reserves [Abstract]
Proved developed reserves	6,157,000	8,708,000	9,433,000
Proved undeveloped reserves	129,000	129,000	228,000
Total proved reserves	6,286,000	8,837,000	9,661,000

XML

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2013

Summary of Significant Accounting Policies [Abstract]

Components of prepayments and other

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

	December 31,
	2013		2012
Cash collateral deposits for commodity purchases	$	13,705	$	5,000
Insurance premiums		2,490		1,872
Rents, license and other		584		840
	$	16,779	$	7,712

Fair value measurements for producing oil and gas properties that were subject to fair value impairment

Fair value measurements for producing oil and gas properties that were subject to fair value impairment for the years ended December 31, 2013 and 2012 summarized as follows (in thousands):

	Producing Properties Subject to Fair Value Impairment
	2013			2012
Net book value at January 1	$	13,180		$	11,073
Property additions		5,661			13,083
Depletion taken		(3,727	)		(6,371	)
Impairment valuation loss		(1,373	)		(4,699	)
Net book at December 31	$	13,741		$	13,086

Capitalized costs for non-producing oil and gas leasehold interests

 Capitalized costs for non-producing oil and gas leasehold interests currently represent approximately five percent of total oil and gas property costs and are categorized as follows (in thousands):

	December 31,		December 31,
	2013		2012
South Texas Project acreage	$	4,217	$	3,263
West Texas Project		116		180
Napoleonville Louisiana acreage		162		323
Other acreage areas		411		329
Total Non-producing Leasehold Costs	$	4,906	$	4,095

Capitalized cost activity on the other acreage areas

Capitalized cost activity on the ‟Other Acreage Areas” was as follows (in thousands):

	Leasehold Costs
	2013			2012
Net book value January 1	$	329		$	475
Property additions		304			810
Property sale		-			(100	)
Impairments		(222	)		(856	)
Net book value December 31	$	411		$	329

Components of cash deposits and other assets

 Components of cash deposits and other assets are as follows (in thousands):

	December 31,
	2013		2012
Insurance collateral deposits	$	3,718	$	3,413
State collateral deposits		160		170
Materials and supplies		609		616
	$	4,487	$	4,199

Derivatives reflected in the Consolidated Balance Sheet

None of the Company’s derivative instruments have been designated as hedging instruments and the estimated fair value of forward month commodity contracts (derivatives) is reflected in the accompanying Consolidated Balance Sheet as of December 31, 2013 as follows (in thousands):

	Balance Sheet Location and Amount
	Current			Other		Current			Other
	Assets			Assets		Liabilities			Liabilities
Asset Derivatives
- Fair Value Commodity
Contracts at Gross Valuation	$	449		$	-	$	-		$	-
Liability Derivatives
- Fair Value Commodity
Contracts at Gross Valuation		-			-		54			-
Less Counterparty Offsets		(54	)		-		(54	)		-
As Reported Fair Value Contracts	$	395		$	-	$	-		$	-

Forward month commodity contracts (derivatives) are reflected in the accompanying Consolidated Balance Sheet as of December 31, 2012 as follows (in thousands):

	Balance Sheet Location and Amount
	Current			Other		Current			Other
	Assets			Assets		Liabilities			Liabilities
Asset Derivatives
- Fair Value Commodity
Contracts at Gross Valuation	$	354		$	-	$	-		$	-
Liability Derivatives
- Fair Value Commodity
Contracts at Gross Valuation		-			-		381			-
Less Counterparty Offsets		(270	)		-		(270	)		-
As Reported Fair Value Contracts	$	84		$	-	$	111		$	-

Derivatives reflected in the Consolidated Statement of Operations

Forward month commodity contracts (derivatives) are reflected in the accompanying Consolidated Statement of Operations for the years ended December 31, 2013, 2012 and 2011 as follows (in thousands):

	Gain (Loss)
Location	2013			2012			2011
Revenues – marketing	$	(193	)	$	(1,365	)	$	119

Fair value assets and liabilities

As of December 31, 2013, the Company’s fair value assets and liabilities are summarized and categorized as follows (in thousands):

	Market Data Inputs
	Gross Level 1		Gross Level 2			Gross Level 3		Counterparty
	Quoted Prices		Observable			Unobservable		Offsets			Total
Derivatives
- Current assets	$	-	$	449		$	-	$	(54	)	$	395
- Current liabilities		-		(54	)		-		54			-
Net Value	$	-	$	395		$	-	$	-		$	395

As of December 31, 2012, the Company’s fair value assets and liabilities are summarized and categorized as follows (in thousands):

	Market Data Inputs
	Gross Level 1		Gross Level 2			Gross Level 3		Counterparty
	Quoted Prices		Observable			Unobservable		Offsets			Total
Derivatives
- Current assets	$	-	$	354		$	-	$	(270	)	$	84
- Current liabilities		-		(381	)		-		270			(111	)
Net Value	$	-	$	(27	)	$	-	$	-		$	(27	)

Factors impacting the change in the net value of the Company's fair value contracts

The following table illustrates the factors impacting the change in the net value of the Company’s fair value contracts for the year ended December 31, 2013 (in thousands):

	Level 1		Level 2
	Quoted Prices		Observable			Total
Net Fair Value January 1,	$	-	$	(27	)	$	(27	)
- Net realized (gains) losses		-		27			27
- Option deposit		-		615			615
- Net unrealized gains (losses)		-		(220	)		(220	)
Net Fair Value December 31,	$	-	$	395		$	395

The following table illustrates the factors impacting the change in the net value of the Company’s fair value contracts for the year ended December 31, 2012 (in thousands):

	Level 1		Level 2
	Quoted Prices		Observable			Total
Net Fair Value January 1,	$	-	$	1,338		$	1,338
- Net realized (gains) losses		-		(1,338	)		(1,338	)
- Net unrealized gains (losses)		-		(27	)		(27	)
Net Fair Value December 31,	$	-	$	(27	)	$	(27	)

Company's asset retirement obligations

 A summary of the Company’s asset retirement obligations is presented as follows (in thousands):

	2013			2012
Balance on January 1,	$	1,886		$	1,568
-Liabilities incurred		431			358
-Accretion of discount		85			63
-Liabilities settled		(138	)		(103	)
-Revisions to estimates		300			-
Balance on December 31,	$	2,564		$	1,886