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, ~~2012~~2015

~~_____~~ __

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

Commission File Number 1-7908

ADAMS RESOURCES & ENERGY, INC.

(Exact name of registrant as specified in its charter)

Delaware	74-1753147	17 South Briar Hollow Lane ~~Ste~~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~~___NO X 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 ~~29, 2012~~30, 2015 was ~~$88,231,036~~$89,541,323 based on the closing price of ~~$41.92~~$44.60 per one share of common stock as reported on the NYSE ~~AMEX Exchange~~MKT for such date. A total of 4,217,596 shares of Common Stock were outstanding at March 1, ~~2013.~~2016.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held May ~~15, 2013~~18, 2016 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, ~~2012~~2015 contains certain forward-looking statements covered by the safe harbors provided under ~~Federal~~federal securities law and regulations. To the extent such statements are not recitations of historical ~~fact,~~fact; such 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”~~(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 ~~marketing~~ crude oil ~~and natural gas, as well as~~marketing, tank truck transportation of liquid chemicals, and oil and gas exploration and production. The Company’s headquarters are located in ~~23,450~~27,932 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, ~~2012~~2015 are set forth in Note (8) to the Consolidated Financial Statements included elsewhere herein.

Marketing Segment ~~Subsidiaries~~Subsidiary

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 ~~176~~207 tractor-trailer rigs and maintains over 55120 pipeline inventory locations or injection stations. Gulfmark has the ability to barge oil from ~~three~~four oil storage facilities along the intercoastal waterway of Texas and Louisiana and maintains ~~230,000~~400,000 barrels of storage capacity at the dock facilities in order to access waterborne markets for its products. During ~~2012,~~2015, Gulfmark purchased approximately ~~89,200~~106,400 barrels per day of crude oil at the ~~wellhead or lease~~field (wellhead) level. Gulfmark delivers physical supplies to refiner customers or enters into commodity exchange transactions ~~with third parties~~ when the cost ~~of the~~to exchange is less than the alternate cost ~~incurred in transporting~~to transport or ~~storing~~store the crude oil. During ~~2012,~~2015, Gulfmark had sales to ~~three~~two customers that comprised ~~20.2 percent, 17.9~~24.4 percent and ~~16.8~~13.8 percent, respectively, of total Company wide revenues. Management believes ~~that~~alternative market outlets for its commodity sales are readily available and a loss of any of these customers would not have a material adverse effect on the Company’s operations. See ~~also~~discussion under ‟Concentration of Credit Risk” in Note ~~3 of Notes~~(3) to Consolidated Financial Statements.

Adams Resources Marketing, Ltd. (‟ARM”), a subsidiary of ARE, operates as a wholesale purchaser, distributor and marketer of natural gas. ARM’s focus is on the purchase of natural gas at the producer level. During 2012, ARM purchased approximately 123,000 million british thermal units (‟mmbtu’s”) of natural gas per day at the wellhead and pipeline pooling points. Business is concentrated among approximately fifty independent producers with the primary production areas being the Louisiana and Texas Gulf Coast and the offshore Gulf of Mexico region. ARM provides value added services to its customers by providing access to common carrier pipelines while handling daily volume balancing requirements and risk management services.

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 ~~300~~324 truck tractors of which 15293 are Company owned with 31 independent owner-operator ~~units~~units. The Company also owns and ~~owns 462~~operates 580 tank trailers. In addition, STC operates truck terminals in Houston, Corpus Christi, and Nederland, Texas as well as Baton Rouge (St. Gabriel), Louisiana, St. Rose, Louisiana and Mobile (Saraland), Alabama. Transportation operations are headquartered at a terminal facility situated on 2226.5 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 ~~484~~513 producing wells of which 3826 are Company operated.

Producing Wells--The following table sets forth the Company’s gross and net productive wells as of December 31, ~~2012.~~2015. 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				Oil Wells				Gas Wells				Total Wells
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Texas		155		9.53		190		12.83		345		22.36		242		7.49		164		11.35		406		18.84
Other		91		3.96		48		5.01		139		8.97		82		1.11		25		.61		107		1.72
		246		13.49		238		17.84		484		31.33		324		8.60		189		11.96		513		20.56

Acreage--The following table sets forth the Company’s gross and net developed and undeveloped acreage as of December 31, 2012. 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 130,541 10,908 200,232 16,436
Kansas 150 8 17,772 888
Other 8,281 1,086 1,701 674
138,972 12,002 219,705 17,998

Drilling Activity--The following table sets forth the Company’s drilling activity for each of the three years ended December 31, ~~2012.~~2015. All drilling activity was onshore in Texas, Louisiana ~~Arkansas~~ and Kansas.

	2012				2011				2010				2015				2014				2013
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Exploratory wells drilled
- Productive		-		-		-		-		-		-		-		-		-		-		-		-
- Dry		-		-		8		.87		12		.67		1		.10		4		.40		3		.38

Development wells drilled
- Productive		109		2.40		75		2.10		41		1.77		13		.16		46		.83		77		1.40
- Dry		-		-		3		.18		-		-		-		-		3		.43		-		-
		109		2.40		86		3.15		53		2.44		14		.26		53		1.66		80		1.78

Production and Reserve Information--The Company’s estimated net quantities of proved oil and natural gas reserves, establish future net cash flows before income taxes and the standardized measure of discounted future net cash flows, calculated at a 10% discount rate, for the three years ended December 31, ~~2012,~~2015, are presented in the table below (in thousands):

	December 31,						As of December 31,
	2012		2011		2010		2015		2014		2013
Crude oil (thousands of barrels)		307		292		267		226		318		368
Natural gas (thousands of mcf)		8,837		9,661		7,794		4,835		5,611		6,286
Standardized measure of discounted future
net cash flows from oil and natural gas reserves	$	16,355	$	20,931	$	16,672
Future net cash flows before income taxes							$	8,413	$	41,396	$	45,169
Standardized measure of oil and gas reserves							$	3,527	$	15,744	$	17,836

The estimated value of oil and natural gas reserves and future net revenues ~~from~~derived therefrom are highly dependent upon oil and ~~natural~~ gas ~~reserves was made by~~commodity price assumptions. In such estimates, the Company’s independent petroleum ~~engineers. The reserve value estimates provided at each of December 31, 2012, 2011 and 2010 are based on~~engineers assumed market prices ~~of $93.85, $95.85 and $76.14 per barrel for crude oil and $3.51, $4.69 and $5.26 per mcf for natural gas, respectively.~~ as presented in the table below (in thousands):

	2015		2014		2013
Assumed market price
Crude oil per barrel	$	45.83	$	89.60	$	94.99
Natural gas per thousand cubic feet (mcf)	$	2.62	$	5.42	$	4.69

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~~prices reported in the reserve disclosures for natural gas ~~for 2012 includes~~include the value of associated natural gas liquids.

Oil and gas reserve values and future net cash flow estimates are very sensitive to pricing assumptions and will vary accordingly.

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, ~~2012~~2015 was as follows:

Years Ended Crude Oil Natural
December 31,

(barrels)

Gas (mcf)

2012 98,100 2,608,000
2011 61,500 1,895,000
2010 54,000 1,365,000

Years Ended	Crude Oil		Natural
December 31,	(barrels)		Gas (mcf)
2015		99,500		889,000
2014		127,300		1,133,000
2013		102,300		1,608,000

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

	Years Ended December 31,						Years Ended December 31,
	2012		2011		2010		2015		2014		2013
Average oil and condensate
sales price per barrel(1)	$	84.39	$	93.23	$	77.09	$	28.94	$	63.64	$	79.15
Average natural gas
sales price per mcf	$	2.94	$	4.39	$	5.02	$	2.46	$	4.65	$	3.75
Average production cost, per equivalent
barrel, charged to expense	$	13.14	$	16.79	$	13.99	$	24.64	$	21.42	$	15.54

(1) Average oil and condensate prices include the value of associated natural gas liquids.

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.

Investment

In December 2015 the Company formed a new wholly owned subsidiary Adams Resources Medical Management, Inc. (ARMM) and in January 2016 ARMM acquired a 30% member interest in Bencap LLC (Bencap) for a $2,200,000 cash payment. Bencap provides medical insurance brokerage and medical claims auditing services to employers utilizing ERISA governed employee benefit plans. The Company will account for this investment on the equity method of accounting.

Environmental Compliance and Regulation

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

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

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

-	The Clean Water Act of 1972, as amended.

-	Federal Oil Pollution Act of 1990, as amended.

-	The Clean Air Act of 1970, as amended.

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

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

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

-	Texas Clean Air Act.

-	Texas Solid Waste Disposal Act.

-	Texas Water Code.

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

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

Louisiana Office of Conservation--This agency has primary statutory responsibility for regulation and conservation of oil, gas, and other natural resources in the State of Louisiana. Their objectives are to (i) regulate the exploration and production of oil, natural gas and other hydrocarbons, (ii) control and allocate energy supplies and distribution 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.

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, ~~2012,~~2015, the Company is unaware of any unresolved environmental issues for which additional accounting accruals are necessary.

Employees

At December 31, ~~2012,~~2015, the Company employed ~~925~~809 persons, 1510 of whom were employed in the exploration and production of oil and gas, ~~441~~348 in the marketing of crude oil, ~~and natural gas and, 448~~433 in transportation operations, and 2118 in administrative capacities. None of the Company’s employees are represented by a union. Management believes its employee relations are satisfactory.

Federal and State Taxation

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

Available Information

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, ~~Ste~~Suite 100

Houston, Texas 77027

Item 1A. RISK FACTORS

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:

·	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.

The current market environment is such that the Company has been adversely effected by the sudden and significant declines in the commodity price for hydrocarbons.

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, or a prolonged period of low commodity prices, future earnings will be reduced. Since the Company has noneither 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.

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.~~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~~

Potentially escalating diesel fuel prices could have an adverse effect on the ~~Company.~~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~~During periods of high prices, the Company attempts to recoup rising diesel fuel costs through the pricing of its ~~services,~~services; however 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~~.

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

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

·	~~economic conditions in the United States and worldwide;~~

·	~~governmental regulations and taxation;~~

·	~~impact of energy conservation efforts;~~

·	~~the price and availability of alternative fuel sources;~~

·	~~weather conditions;~~

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

·	~~market uncertainty.~~

Revenues are generated under contracts that must be renegotiated periodically.

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

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

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

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

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

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

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

Transportation of hazardous materials and the 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.

910

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.

1011

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.

1112

The Company is subject to risks associated with climate change.

Potential climate change and efforts to regulate ‟greenhouse gas” (‟~~GHG’s”~~GHG”) 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

AREC is named 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. AREC is currently involved in three 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 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 except all the larger defendants have settled their claims in the LePetit Chateau Deluxe matter. 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 these items. As of December 31, 2015 and 2014, the Company has accrued $500,000 of future legal and/or settlement costs for these matters.

From time to time as incident to its operations, the Company ~~may become~~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 ~~and~~or other items of general liability as ~~would be~~are typical for the industry. ~~Management~~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, ~~is presently unaware~~management will estimate the monetary value of ~~any claims against~~ the ~~Company that are either outside~~claim and make appropriate accruals or disclosure as provided in 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.appropriate accounting literature guidelines.

Item 4. MINE SAFETY DISCLOSURES

Not Applicable.

1214

PART II

Item 5.

MARKET FOR THE REGISTRANT’S COMMON STOCK, RELATED ~~SECURITY HOLDER~~STOCKHOLDER MATTERS, AND ISSUER ~~REPURCHASE~~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, ~~2011.~~2014.

	American Stock Exchange				American Stock Exchange
	High		Low		High		Low
2012
2015
First Quarter	$	75.13	$	29.20	$	73.28	$	47.31
Second Quarter		74.73		27.85		70.00		39.00
Third Quarter		47.33		30.00		48.60		38.88
Fourth Quarter		36.20		28.10		46.86		33.55

2011
2014
First Quarter	$	31.30	$	22.46	$	90.28	$	57.19
Second Quarter		30.50		22.51		81.50		56.08
Third Quarter		29.07		18.73		79.61		44.26
Fourth Quarter		29.50		18.90		50.54		38.58

~~At March 1, 2013 there were approximately 219 shareholders of record of the Company’s common stock and the closing stock price was $39.92 per share.~~ The Company has no securities authorized for issuance under equity compensation plans. The Company made no repurchases of its stock during ~~2012~~2015 and ~~2011.~~2014.

OnDuring each of March, June, September and December ~~17, 2012,~~2015 and 2014, respectively, the Company paid ~~an annual~~to its common shareholders a quarterly cash dividend of ~~$.62~~$.22 per common share to common stockholders of record on December 3, 2012. On December 15, 2011, the Company paid an annual cash dividend of $.57 per common share to common stockholders of record on December 1, 2011. Such dividends totaled $2,614,954 and $2,404,000 for 2012 and 2011, respectively.as follows:

1315

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, ~~2007~~2010 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.

	12/07	12/08	12/09	12/10	12/11	12/12	12/10	12/11	12/12	12/13	12/14	12/15

Adams Resources & Energy, Inc.	100.00	68.35	90.70	102.34	125.26	153.78	100.00	122.39	150.26	296.69	219.60	171.98
S&P 500	100.00	63.00	79.67	91.67	93.61	108.59	100.00	102.11	118.45	156.82	178.29	180.75
S&P Integrated Oil & Gas	100.00	78.21	77.20	91.75	105.30	107.63	100.00	114.77	117.30	142.56	132.96	114.53

1416

Item 6. SELECTED FINANCIAL DATA

SELECTED FINANCIAL DATA

	Years Ended December 31,															Years Ended December 31,
	2012			2011			2010			2009			2008			2015			2014			2013			2012			2011
	(In thousands, except per share data)															(In thousands, except per share data)
Revenues:
Marketing	$	3,297,827		$	2,967,427		$	2,015,893		$	1,784,832		$	3,861,117		$	1,875,885		$	4,050,497		$	3,863,057		$	3,292,948		$	2,961,176
Transportation		67,183			63,501			56,867			44,895			67,747			63,331			68,968			68,783			67,183			63,501
Oil and natural gas		15,954			14,060			11,021			8,650			17,248			5,063			13,361			14,129			15,954			14,060
	$	3,380,964		$	3,044,988		$	2,083,781		$	1,838,377		$	3,946,112		$	1,944,279		$	4,132,826		$	3,945,969		$	3,376,085		$	3,038,737
Operating earnings (loss):
Marketing	$	47,166		$	51,384		$	16,603		$	18,153		$	(2,298	)	$	22,895		$	20,854		$	40,369		$	46,145		$	49,237
Transportation		10,253			8,521			6,623			2,128			4,245			3,701			4,750			5,180			10,253			8,521
Oil and gas operations		(5,804	)		(16,794	)		(1,757	)		(3,625	)		(3,348	)		(19,016	)		(10,038	)		(2,113	)		(5,835	)		(16,797	)
Oil and gas property sale		2,203			2,923			-			-			-			-			2,528			-			2,203			2,923
General and administrative		(9,769	)		(9,713	)		(9,044	)		(9,589	)		(9,667	)		(9,939	)		(8,613	)		(9,060	)		(8,810	)		(8,678	)
		44,049			36,321			12,425			7,067			(11,068	)		(2,359	)		9,481			34,376			43,956			35,206
Other income (expense):
Interest income		190			237			191			125			1,103			327			301			198			190			237
Interest expense		(10	)		(8	)		(36	)		(25	)		(187	)		(13	)		(2	)		(24	)		(10	)		(8	)
Earnings (loss) from continuing operations
before income taxes		44,229			36,550			12,580			7,167			(10,152	)		(2,045	)		9,780			34,550			44,136			35,435

Income tax (provision) benefit		(16,697	)		(13,107	)		(4,028	)		(2,585	)		4,844			770			(3,561	)		(12,429	)		(16,664	)		(12,717	)

Earnings (loss) from continuing
Operations		27,532			23,443			8,552			4,582			(5,308	)		(1,275	)		6,219			22,121			27,472			22,718
Earnings (loss) from discontinued
operations, net of taxes		259			(512	)		79			(433	)		(264	)		-			304			(511	)		319			213

Net earnings (loss)	$	27,791		$	22,931		$	8,631		$	4,149		$	(5,572	)	$	(1,275	)	$	6,523		$	21,610		$	27,791		$	22,931

Earnings (Loss) Per Share
From continuing operations		6.53			5.56			2.03			1.08			(1.26	)	$	(.30	)	$	1.48		$	5.24		$	6.51		$	5.39
From discontinued operations		.06			(.12	)		.02			(.10	)		(.06	)		-			.07			(.12	)		.08			(.05	)

Basic and diluted earnings (loss) per share	$	6.59		$	5.44		$	2.05		$	.98		$	(1.32	)
Basic and diluted earnings per share																$	(.30	)	$	1.55		$	5.12		$	6.59		$	5.34

Dividends per common share	$	.62		$	.57		$	.54		$	.50		$	.50			.88		$	.88		$	.66		$	.62		$	.57

Financial Position
Cash	$	47,239		$	37,066		$	29,032		$	16,806		$	18,208		$	91,877		$	80,184		$	60,733		$	47,239		$	37,066
Net working capital		58,474			48,871			39,978			38,372			41,559			96,340			82,342			79,561			58,474			48,871
Total assets		419,501			378,840			301,305			249,401			210,926			243,215			340,814			448,082			419,501			378,840
Long-term debt		-			-			-			-			-			-			-			-			-			-
Shareholders’ equity		135,858			110,682			90,155			83,801			81,761			152,510			157,497			154,685			135,858			110,682
Dividends on common shares		2,615			2,404			2,277			2,109			2,109			3,712			3,711			2,783			2,615			2,404

Notes:

-	In 2014, 2012 and 2011, certain oil and natural gas producing properties were sold for $4.1 million, $3.6 million and $6.6 million producing net gains of $2.5 million, $2.2 million and $2.9 million, respectively.

-	The 2012 and 2011 oil and gas operating losses primarily resulted from property impairments totaling $4.7 million and $14.8 million, respectively, recorded as a result of declining natural gas prices.

The 2015, 2014, 2013, 2012 and 2011 oil and gas operating losses include property impairments totaling $12.1 million, $8.0 million, $2.6 million, $4.7 million and $14.8 million, respectively. These impairments were recorded following declining crude oil prices in 2015 following crude oil price declines in 2014, unfavorable drilling results in 2013 and declining natural gas prices in 2012 and 2011.

1517

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

Results of Operations

- Marketing

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

2012

2011

2010

Revenues
Crude oil $ 3,292,948 $ 2,961,176 $ 2,005,301
Natural gas 4,879 6,251 10,592
Total $ 3,297,827 $ 2,967,427 $ 2,015,893

Operating Earnings (loss)
Crude oil $ 46,145 $ 49,237 $ 13,530
Natural gas 1,021 2,147 3,073
Total $ 47,166 $ 51,384 $ 16,603

Depreciation
Crude oil $ 5,945 $ 3,724 $ 2,320
Natural gas 31 3 44
Total $ 5,976 $ 3,727 $ 2,364

Fleet diesel fuel costs $ 11,617 $ 9,982 $ 6,001

	2015		2014		2013

Revenues	$	1,875,885	$	4,050,497	$	3,863,057

Operating earnings	$	22,895	$	20,854	$	40,369

Depreciation	$	11,097	$	9,626	$	7,682

Driver commissions	$	22,262	$	21,744	$	19,478

Insurance	$	8,732	$	7,446	$	7,659

Fuel	$	9,928	$	14,851	$	13,808

Supplemental volume and price ~~information is:~~information:

	2012		2011		2010		2015		2014		2013
Field Level Purchases per day (1)
Crude Oil – barrels		89,200		81,600		69,000		106,400		117,100		106,000
Natural Gas – mmbtu’s		123,000		208,000		258,000

Average Purchase Price
Crude Oil – per barrel	$	99.66	$	96.77	$	77.20	$	45.41	$	89.40	$	99.57
Natural Gas – per mmbtu	$	2.58	$	3.93	$	4.28

___________________

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

~~Crude~~Beginning in late 2011, crude oil ~~revenues increased in 2012 relative to 2011 and in 2011 relative to 2010 because of increased field level~~ purchase volumes and ~~generally higher average crude oil prices as shown in the table above. Volume increases primarily resulted from~~hence revenues started to increase following new ~~well~~ production established by the Company’s customer base, primarily in the Eagle Ford shale ~~trend~~ of South ~~Texas beginning~~Texas. This trend continued into late 2014 supported by a relatively high market price for crude oil in ~~2011, while~~the $90 per barrel range. Beginning in November 2014, crude oil prices ~~fluctuated upwards with general market conditions.~~began to decline significantly and the Company’s average crude oil purchase price dropped to $54 per barrel by December 2014 from $90 per barrel in September 2014. Declining prices continued into 2015 curtailing new drilling efforts. The combination of reduced prices and volumes caused revenues to fall 54 percent in 2015 relative to 2014.

-	~~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 2012,~~from 2013 through 2015, the net impact yielded inventory ~~liquidation~~valuation losses ~~totaling $1,596,000 as prices trended down from $98 per barrel~~ in ~~the beginning~~each of the year to average $95 per barrel at year-end. In contrast, crude oil prices were as generally rising during 2011 and 2010 producing inventory valuation gains of $3,021,000 and $2,272,000, respectively. As of December 31, 2012, the Company held 245,623 barrels of crude oil inventory at an average price of $95.35 per barrel.years presented.

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~~subject to 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 the following reconciliation from a GAAP to a non-GAAP measure (in thousands):

	2012		2011			2010			2015		2014			2013

As reported segment operating earnings	$	46,145	$	49,237		$	13,530		$	22,895	$	20,854		$	40,369
Add (less) -
Inventory liquidation (gains) losses		1,596		(3,021	)		(2,272	)		5,357		14,247			3,824
Derivative valuation (gains) losses		2,001		149			(1,049	)		188		(312	)		193

Field level operating earnings(1)	$	49,742	$	46,365		$	10,209		$	28,440	$	34,789		$	44,386

(1)	Such designation is unique to the Company and is not comparable to any similar measures developed by industry participants. The Company utilizes such data to evaluate the profitability of its operations.

The Company held crude oil inventory at a weighted average composite price in barrels as follows:

	As of December 31,
	2015				2014
			Average				Average
	Barrels		Price		Barrels		Price
Crude oil inventory		261,718	$	29.31		292,355	$	46.11

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.~~points. Comparative ~~crude oil~~ field level operating earnings ~~increased~~decreased in ~~2012~~2015 relative to ~~2011~~2014 and in ~~2011~~2014 relative to 2010 with the noted volume additions and overall improved unit margins for the comparative periods. Unit margins first 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, although they diminished2013 as competition and additional industry infrastructure development progressed in the region.

-	~~Natural Gas Marketing~~

~~Natural gas sales are reported net of underlying natural gas purchase costs~~ The year 2015 also experienced volume declines and ~~thus reflect gross margin. As shown~~added margin pressure as crude oil prices continued to decline. Previously, a key factor in unit margins was the value difference between crude oil supplies in the table above, gross margins were reduced during 2011 and again in 2012 as average field level purchase volumes were off over 50 percent during the periods presented. The Company’s primary source of natural gas supply is the non-shale areas of Texas, Louisiana and the Gulf of Mexico and these volumes declined because the Company’s suppliers curtailed drilling activity due to suppressed natural gas prices. In addition, developmentmid-continent region of the ~~nation’s natural gas infrastructure including more diverse areas of production, expanded pipeline and storage capacity, and increased price transparency with~~United States versus crude oil supply costs in the ~~development~~eastern region of the ~~Intercontinental Exchange (ICE) have~~United States. The Company was able to capture some of this value difference by shipping crude oil from the Texas Gulf Coast to points east. Due to competitive pressures during 2014, the opportunity for the Company to capture this location-based unit value difference evaporated which reduced earnings. Further, depreciation charges increased as new equipment was added and driver commissions increased in 2014 and 2015 as a result of driver shortages in 2014 and longer hauls in 2015, necessitated by the competition to retain volumes. An adverse claims experience increased insurance costs in 2015 but this experience cycle is not expected to recur in 2016. Initially in 2015, operating earnings benefited from reduced fuel costs but this advantage has been largely lost as competitive pressures necessitated passing such savings back to suppliers in the form of higher purchase ~~opportunities and per unit margins.~~prices.

Historically, prices received for crude oil ~~and natural gas~~ have been volatile and unpredictable with price volatility expected to continue. See ~~discussion under Item~~‟Item 1A, Risk ~~Factors.~~Factors – Fluctuations in oil and gas prices could have an adverse effect on the Company”.

~~Transportation~~

- Transportation

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

	2012					2011					2010					2015					2014					2013
	Amount		Change(1)			Amount		Change(1)			Amount		Change(1)			Amount		Change(1)			Amount		Change(1)			Amount		Change(1)

Revenues	$	67,183		6	%	$	63,501		12	%	$	56,867		27	%	$	63,331		(8.2	)%	$	68,968		.3	%	$	68,783		2	%

Operating earnings	$	10,253		20	%	$	8,521		29	%	$	6,623		211	%	$	3,701		(22.1	)%	$	4,750		(8.3	)%	$	5,180		(49	)%

Depreciation	$	5,921		51	%	$	3,912		(9	)%	$	4,288		8	%	$	7,554		1.9	%	$	7,416		4.5	%	$	7,099		20	%

Driver commissions																$	13,265		(1.2	)%	$	13,428		2.1	%	$	13,152		3	%

Insurance																$	4,543		(18.5	)%	$	5,574		(6.1	)%	$	5,937		20	%

Diesel fuel																$	8,134		(39.7	)%	$	13,487		(9.0	)%	$	14,813		2	%

Maintenance Expense																$	6,365		3.6	%	$	6,143		12.4	%	$	5,464		24.6	%

Mileage																	25,205		(4.2	)%		26,314		(3.4	)%		27,243		3.4	%

______________

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

The Company’s revenue rate structure includes a component for fuel costs such that fuel cost fluctuations are largely passed through to the customer over time. To illustrate, a calculation of revenues net of fuel cost is presented below (in thousands):

	2015			2014				2013
Total transportation revenue	$	63,331		$	68,968		$	68,783
Diesel fuel cost		(8,134	)		(13,487	)		(14,813	)
Revenues net of fuel	$	55,197		$	55,481		$	53,970

Revenues net of fuel costs appear relatively flat while reported mileage as shown above has been decreasing from 2013 to 2015. This apparent paradox results because of rate increases necessitated by higher driver and equipment costs in the more recent years.

The operating ~~results improved~~earnings trend line has declined since 2013. This is caused by two primary factors. First and most recently, mileage is reduced reflecting a drop off in demand originating in the third quarter of 2015. Second, maintenance expense and depreciation following new equipment additions has steadily increased. Partially offsetting these higher costs is reduced insurance expense for 2015 resulting from favorable claims experience. The net result is still an adverse impact on operating earnings and management is working to reverse this situation. The demand problem is being addressed with increased marketing efforts. The cost problem is being addressed through sales of older inefficient equipment, a revamp of the approach to equipment maintenance and certain personnel layoffs that occurred in January 2016.

Equipment additions and retirement for the transportation ~~segment in both 2012 and 2011 due to increased customer demand.~~ fleet were as follows:

	2015	2014	2013
New truck-tractors purchased	60 units	40 units	-
Truck-tractors retired	-	40 units	-
New trailers purchased	12 units	30 units	35 units
Trailers retired	-	-	17 units

The ~~Company also benefitted in 2012 and 2011 from $2.6 million and $1.2 million in gains, respectively, from the~~ sale of ~~used~~retired equipment ~~following the purchase~~produced gains of ~~new truck replacements.~~ $16,000 and $432,000 in 2015 and 2014, respectively.

The Company’s predominate customers ~~predominately consist of~~are the domestic petrochemical ~~industry and demand for their products has substantially recovered from the slow-down occurring in 2009. Serving~~industry. Contributing to ~~improve~~ customer demand ~~was a recovering United States economy,~~is low natural gas prices (a basic feedstock cost for the petrochemical industry) and ~~improved~~high export demand for petrochemicals. In addition, during the previous economic downturn, the trucking industry reduced capacity by retiring older units without replacement. With demand improvement, industry capacity has been strained allowing rate increasesLower natural gas prices beginning in 2011 stimulated and ~~improved overall profitability.~~provided an opportunity for increased profitability and this was evident in 2011 and 2012 results. However, increased operating expenses and an industry wide shortage of qualified drivers ~~has~~ affected the Company by suppressing ~~current year~~ revenues and results of ~~operations.~~operations during the heavy demand cycle of 2014 and early 2015. More recently, the United States economy appears to have weakened with demand slackening. In addition, the recent strengthening of the U.S. dollar relative to foreign currency may weaken demand for U.S. sourced petrochemical products. As transportation revenues increase or decrease, operating earnings will typically increase or decrease at an accelerated rate. This ~~trend exists~~occurs because the fixed cost components of the Company’s operation do not vary with changing revenues. As currently configured, operating earnings ~~project at~~achieve break-even levels when annual revenues average approximately ~~$54~~$60 million. Above that level, operating earnings will grow and below that level, losses result.

Transportation segment depreciation increased for 2012 as older fully depreciated tractor units were replaced with new model year vehicles. 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. For 2011 relative to 2010, increased depreciation expense on new tractor models was offset by certain in-service trailers becoming fully depreciated during the period.

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~~selected expenses were as follows (in thousands):

2012

2011

2010

Amount
Change(1)
Amount
Change(1)
Amount
Change(1)

Revenues $ 15,954 13 % $ 14,060 28 % $ 11,021 27 %

Operating earnings (loss)(2)
(3,601 ) (74 )% (13,871 ) 689 % (1,757 ) 51 %

Depreciation and depletion 8,817 7 % 8,246 77 % 4,662 28 %

Producing property impairments 4,699 (34 )% 7,105 651 % 946 (30 )%

	2015						2014						2013
	Amount			Change(1)			Amount			Change(1)			Amount			Change(1)
Revenues	$	5,063			(62.1	)%	$	13,361			(5.4	)%	$	14,129			(11	)%

Operating earnings (loss)(2)		(19,016	)		153.2	%		(7,510	)		255.4	%		(2,113	)		42	%

Depreciation and depletion		5,066			(33.1	)%		7,573			1.1	%		7,494			(15	)%

Dry hole expense		817			(21.0	)%		1,034			343.8	%		233			441.9	%

Prospect impairments		1,758			(56.1	)%		4,008			218.9	%		1,257			46.8	%

Producing property impairments		10,324			158.0	%		4,001			191.4	%		1,373			(71	)%

______________

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

(2)	Includes gains from property sales of ~~$2.2 million and $2.9~~$2.5 million in ~~2012 and 2011, respectively.~~2014.

~~Improved oil and gas segment revenues during 2012 and 2011 resulted from crude oil and natural gas volumes increases as~~As shown in the table below, declining crude oil, natural gas and natural gas liquid prices coupled with ~~such~~declining volumes acted to reduce revenues and earnings for the comparative years presented. The sales volume ~~changes resulting from recent drilling efforts. Active drilling, however, also served~~decrease followed normal production declines as persistently low prices curtailed the development of natural gas properties in 2013 and 2014 and curtailed crude oil properties in 2015. Contributing to ~~increase depreciation and depletion expenses as well as property impairment charges during 2012 and 2011. Operating earnings~~operating losses were ~~markedly reduced in 2011 due to increased charges for depreciation, depletion and producing~~ property impairments as ~~well as increased exploration~~shown above. Property impairments resulted in 2015 and ~~prospect impairment expenses as shown~~2014 following fourth quarter declines in ~~the second table below. Producing and non-producing property~~crude oil prices while impairments ~~increased significantly~~ in 2011 following a December 2011 decline in the current and forward price for natural gas. Natural gas prices remained at relatively low levels during 2012 resulting in additional impairment charges for the year.2013 followed adverse drilling results.

Comparative volumes and prices were as follows:

2012 2011 2010

Production Volumes
- Crude oil 98,100 bbls 61,500 bbls 54,000 bbls
- Natural gas 2,608,000 mcf 1,895,000 Mcf 1,365,000 mcf

Average Price
- Crude oil(1)
$ 84.39 bbls $ 93.23 bbls $ 77.09 bbls
- Natural gas $ 2.94 mcf $ 4.39 Mcf $ 5.02 mcf

~~___________________________~~

	2015			2014			2013
Production Volumes
- Crude oil		50,000	Bbls		79,100	Bbls		84,400	Bbls
- Natural gas		889,000	Mcf		1,133,000	Mcf		1,608,000	Mcf
- Natural gas liquids		42,100	Bbls		45,900	Bbls		24,400	Bbls

Average Price
- Crude oil	$	46.51	Bbls	$	88.42	Bbl	$	88.70	Bbl
- Natural gas	$	2.46	Mcf	$	4.65	Mcf	$	3.75	Mcf
- Natural gas liquids	$	12.70	Bbls	$	28.83	Bbl	$	25.06	Bbl

~~(1)~~

~~Crude oil prices and volumes include the sale of associated natural gas liquids production.~~

During 2015, the Company participated in the drilling of 14 wells with one dry hole. No wells were in process as of December 31, 2015 and no drilling is currently planned for 2016.

~~Comparative exploration~~An independent evaluation of estimated oil and ~~prospect impairment~~gas reserves and the estimated future income derived therefrom is prepared on an annual basis. See also Note (11) to Consolidated Financial Statements. The following estimates of future net income from oil and gas properties before income taxes based on average prices during 2015 is presented in such report as of December 31, 2015 as follows (in thousands):

	As of
	December 31, 2015
Future net income before taxes
- Estimate for the year 2016	$	1,575
- Estimate for the year 2017		992
- Estimate for the year 2018		940
- Estimate for the year 2019		816
- Estimate for the year 2020		680
Thereafter		3,410
Total future net income before taxes	$	8,413

Net capitalized oil and gas property costs ~~were~~(remaining net book value) associated with the projected future net income stream as of December 31, 2015 was as follows (in thousands):

2012

2011

2010

Dry hole expense $ 43 $ 1,212 $ 1,894
Prospect impairment 856 7,644 1,277
Seismic and geological 252 310 62

Total $ 1,151 $ 9,166 $ 3,233

	As of
	December 31, 2015
Net capitalized cost of oil and gas properties	$	8,001

Capitalized oil and gas property costs are amortized against income as the underlying oil and gas reserves are produced (units-of-production method). Therefore as illustrated above, absent price increases, it is unlikely that the Company will report operating income from its oil and gas segment for the foreseeable future.

1922

During 2012, the Company participated in the drilling of 109 wells with no dry holes. Additionally, the Company had 34 wells in process on December 31, 2012 with ultimate evaluation anticipated during 2013. 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:

2012

2011

2010

(Eq. Bbls.) (Eq. Bbls.) (Eq. Bbls.)

Proved reserves – beginning of year 1,907,000 1,566,000 1,450,000
Estimated reserve additions 537,000 1,209,000 536,000
Production volumes (533,000 ) (377,000 ) (282,000 )
Producing properties sold (71,000 ) (385,000 ) -
Revisions of previous estimates (61,000 ) (106,000 ) (138,000 )

Proved reserves - end of year 1,779,000 1,907,000 1,566,000

For 2012 and for the three year period ended December 31, 2012, estimated reserve additions represented 101 percent and 191 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 2013 will be substantially reduced. The Company’s current drilling and exploration efforts are primarily focused as follows:

~~East Texas Project~~

In 2005, the Company joined with its partners in acquiring acreage in Nacogdoches and Shelby Counties, Texas. This was subsequently expanded to include acreage in Angelina County, due south of Nacogdoches County. This investment holds potential for development in the Haynesville/Bossier shale formations. A total of 97 wells have been drilled with 94 wells placed on production as of December 31, 2012. The Company’s interest in this project varies with an average 2.7 percent ownership in the properties and wells. Production is dry gas and due to low prices only those wells required to hold acreage by production will be drilled. The Company’s interest covers 154,000 gross acres. Approximately 64,000 is being held by production, another 65,000 acres is held by the production from non-owned shallow wells. The remaining acreage is either undeveloped or being held by contracts that delay termination of lease rights.

~~West Texas Project~~

In 2008 the Company participated with an approximate 7.5% working interest in the acquisition of 49,015 gross acres located in Irion and Crockett Counties, Texas for the purpose of developing the Wolfcamp Shale. In 2011 the Company sold a portion of its interest in anticipation of an aggressive horizontal drilling program on the acreage. A total of 135 wells have been drilled through December 31, 2012 with 102 wells on production and 33 wells being completed. Drilling is expected to continue but at a reduced rate in 2013 with 37 wells scheduled for drilling. Production from the Wolfcamp in this area is oil-rich with large amounts of gas and natural gas liquids.

~~South Texas Project~~

The goal of this investment is to extend the productive area of the Eagle Ford trend north in Fayette and Lavaca Counties, Texas. The first core well was productive with petrochemical data showing the project is on the gas-condensate window. Plans call for up to four additional horizontal wells being initiated during 2013. The Company holds a five percent working interest in this project which includes approximately 38,000 acres currently under lease.

Oil and gas property sales

~~In August 2012,~~During 2014, the Company sold ~~to a third party fifty percent~~its interest in certain Oklahoma and Texas properties for proceeds totaling $2,553,000 and half of its interest in certain ~~Kansas oil and gas properties. The~~South Texas (Lavaca County) properties ~~contained one producing well with insignificant production history. The sale was consummated to spur further development on the properties. Total~~for proceeds ~~from the sale were $578,000 and~~totaling $1,509,000. Combined, the Company recorded a $475,000 pre-tax gain on sale. The Company will continue to participate in the development of these Kansas properties. In October and December 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. Both properties had depleted substantially from their initial productive period, so the sales were consummated before the properties lost further value.

In January 2011, the Company completed the sale of its interest in certain producing oil and gas properties located in the on-shore Gulf Coast region of Texas. Proceeds from the sale totaled $6.2 million and the$2,528,000 pre-tax gain from ~~this transaction totaled $2,708,000. Sales negotiations were conducted by the third party operator of the properties and the transaction was completed with a separate third party investment entity.~~these transactions. The ~~Company’s proportionate~~Company retained an interest in the ~~transaction was approximately five percent and~~South Texas properties as development of such project continues, although the Company ~~elected~~chose to ~~participate in~~reduce its level of risk associated with the ~~sale due to attractive pricing. Also during~~development. The other Texas and Oklahoma properties were sold because they were nearing the ~~first quarter~~end of 2011, the Company sold a portion of its interest in certain non-producing oil and gas properties located in West Texas. Total proceeds from the sale were $329,000 and the Company recorded a $125,000 gain from this transaction. Proceeds from the sales were used for general working capital purposes and the Company is continuing with oil and gas exploration operations in the vicinity of the properties sold. In October 2011, the Company sold an interest in certain non-producing properties for $90,000 in proceeds and gain.their economic life.

General and administrative expense, interest income and income tax

General and administrative expenses were ~~generally consistent~~elevated in 2015 due to a $1.1 million lump sum payment made during the ~~periods presented with elevated costs in 2012~~first quarter of 2015 to the Company’s former President upon retirement and 2011 due to employee bonuses, consistent with increased corporate earnings. Interest income declined after 2008 as interest rates on overnight deposits dropped to near zero following the significant turmoil that occurred in the financial markets during that period.termination of his previous employment agreement. The provision for income taxes is based on ~~Federal~~federal and ~~State~~state tax rates and variations are consistent with taxable income in the respective accounting periods.

~~Outlook~~Discontinued operations

~~The short-term outlook indicates continued volume growth~~During 2012, the Company sold certain assets associated with its then petroleum refined products marketing business and ~~relative margin strength within~~discontinued that operation. In 2014, the ~~crude oil~~Company sold the warehouse and real estate used by the former operation for $664,000 in cash resulting in a pre-tax gain on sale of $533,000, with such gain reported in discontinued operations for 2014. In 2013, the Company completed an orderly wind-down and closure of its natural gas marketing operation. However, industry competitors and Company suppliers are aware of the present market opportunity and seek to capture such advantage which would reduce unit margins. Transportation operations continue to experience strong demand, in partbusiness due to low natural gas prices. The oil and gas segment should experience improved results for 2013 with stabilized prices and production from new well additions while depreciation, depletion and impairment charges reduce with less activity planned for 2013.

inadequate earnings. The Company ~~has the following major objectives for 2013:~~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.

-	~~Maintain marketing operating earnings at the $35 million level exclusive of inventory valuation gains or losses.~~

-	~~Maintain transportation operating earnings at the $7 million level.~~

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

Liquidity and Capital Resources

The Company’s liquidity ~~primarily~~ derives from net cash provided by operating activities and is dependent on the success of future operations. See discussion under ‟Item 1A. Risk Factors”. The most significant source of liquidity, over time, is the cash yield from annual net earnings factoring in the non-cash book expense items for depreciation, depletion, amortization and impairments. The Company has no debt and funds all of its capital projects from this annual stream of cash. In most annual periods, the cash inflow from this source exceeds capital spending outflows. Should cash inflow subside or turn negative, the Company will curtail its capital spending accordingly.

Cash provided from operating activities ~~which~~ was ~~$54,494,000, $55,815,000 and $36,928,000 for each of 2012, 2011 and 2010, respectively.~~ as follows (in thousands):

		2015				2014				2013
Net cash provided by operating activities		$	25,477			$	47,133			$	43,976

As of December 31, ~~2012~~2015 and ~~2011,~~2014, the Company had no bank debt or other forms of debenture obligations. Cash ~~and cash equivalents totaled $47,239,000 as of December 31, 2012, and such~~ balances are maintained in order to meet the timing of day-to-day cash ~~needs. Working~~needs and such amounts and working capital, the excess of current assets over current liabilities, ~~totaled $57,799,000~~were as ~~of December 31, 2012.~~ follows (in thousands):

	As of December 31,
	2015		2014
Cash	$	91,877	$	80,184

Working capital	$	96,340	$	82,342

The Company ~~heavily~~ 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. Cash balances were increased during 2015 due to cash generated from operations given that depreciation, depletion and impairments are a non-cash expense.

Capital expenditures during 2012 included $27,929,000 for marketing and transportation equipment additions, primarily consisting of truck-tractors, and $23,083,000 in property additions associated with oil and gas exploration and production activities. For 2013, the Company anticipates expending an additional approximately $12 million on oil and gas development and exploration projects. In addition, approximately $3 million will be expended during 2013 for the purchase of 35 trailers for the transportation segment and approximately $15 million will be expended by the crude oil marketing operation for the purchase of 46 truck-tractors, 60 trailers and the construction of a barge loading facility. These units will serve to replace older units and to increase the marketing fleet by 30 units. Funding for these 2013 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 $5,000,000 as of December 31, 2012 and such amounts will be~~are 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” reduce cash and accounts payable as of the balance sheet date. The Company also requires certain ~~counterparties~~customers to make similar early payments or to post cash collateral with the Company in order to support their ~~purchase~~purchases from the Company. ~~Such~~Early payments and cash collateral ~~held by the Company totaled $7,456,000~~received from customer’s increases cash and reduces accounts receivable as of ~~December 31, 2012.~~ the balance sheet date.

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 tofor the benefit of suppliers of crude ~~oil~~oil. Stand-by letters of credit are issued as needed and ~~natural gas (see Note (1) to Consolidated Financial Statements).~~are cancelled when the underlying purchase obligation is satisfied through cash payment when due. The issuance of stand-by letters of credit enables the Company to avoid posting cash collateral when procuring crude oil supply.

Early payments, collateral and ~~natural gas supply. As~~letters of credit amounts were as follows (in thousands):

	As of December 31,
	2015		2014
Early payments received	$	16,770	$	57,404

Cash collateral received	$	840	$	8,594

Prepayments to suppliers	$	167	$	7,872

Early payments to suppliers	$	11,645	$	35,500

Letters of credit outstanding	$	1,000	$	15,300

The necessity for early payments, collateral posting and letters of credit is substantially reduced as of December 31, ~~2012, letters of credit outstanding totaled $21.9 million. The issued stand-by letters of credit are cancelled as the underlying purchase obligations are satisfied by cash payment when due.~~ 2015, consistent with lower crude commodity prices.

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.

Quarterly dividends of $.22 per common share or $928,000 were paid during each quarter of 2015 and 2014 and during both the third and fourth quarters of 2013.

Capital projects

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 $9.9 million commitment for~~commitments totaling $12,393,000 associated with barge affreightment contracts, 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.

2224

~~Historically,~~A five year history of capital projects and planned 2016 spending is as follows (in thousands):

											Planned
	2011		2012		2013		2014		2015		2016

Crude oil marketing	$	13,554	$	12,391	$	11,343	$	13,598	$	2,126	$	-

Truck transportation		14,118		15,538		3,165		8,994		6,579		5,500

Oil and gas exploration		24,580		23,083		13,094		7,931		2,369		-

Medical management		-		-		-		-		-		5,000

	$	52,252	$	51,012	$	27,602	$	30,523	$	11,074	$	10,500

Marketing segment spending levels were consistent for 2011 through 2014 backed by crude oil prices remaining strong, in the $90 - $100 per barrel range. In late 2014, crude prices fell and spending was curtailed into 2015 and prospective 2016.

For transportation, the 2011 and 2012 period saw stepped up equipment replacements as customer demand increased following a cut back in such activity following the 2008 national recession. The year 2013 was stable then expenditures ramped up in 2014 to add capacity tracking with the petrochemical industry expansion efforts stimulated by abundant low prices of natural gas. In late 2015 however, demand for truck services weakened and only previously planned expenditures will occur in 2016 for this segment. The major project for 2016 is improvements to the existing Houston terminal facility.

Oil and gas exploration capital spending was initially stimulated just prior to 2011 when natural gas prices exceeded $5 per mmbtu. Capital spending in 2011 and 2012 was focused on natural gas development, but falling prices stopped such development in 2013. In 2013 and 2014, exploration spending was active due to high crude prices as development concentrated on crude oil properties. When crude oil prices dropped in 2015, all such activity was no longer economical.

Medical management is a January 2016 initiative where the Company acquired a 30% member interest in Ben Cap LLC (Bencap) for $2,200,000. This investment evolved from the Company’s efforts to manage employee medical insurance costs. Bencap provides medical insurance brokerage and medical claims auditing services to employers utilizing ERISA governed employee benefit plans. Unlike the traditional approach to employee medical insurance, Bencap’s methodology audits and pays ~~an annual dividend~~claims based on a multiplier which takes into consideration a premium over Medicare rates and/or a premium over the ‟Cost-to-Charge Ratio” which medical facility providers must file with the Federal government. The Company has utilized the Bencap methodology over the past three years to process and pay medical claims for its employees, including all management personnel. The Company believes the Bencap approach provides self-insured employers the opportunity for substantial savings over conventional medical insurance without sacrificing the level of employee benefits. In fact, employee benefits may improve since the individual employee is no longer locked into a narrow list of providers. Bencap will primarily use this funding to expand its back-office and sales support functions as it seeks to compete 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. The most significant item affecting future increases or decreases in liquidity is earnings from operations and such earnings are dependent on the success of future operations (see Item 1A. Risk Factors in this annual report of Form 10-K).medical benefits marketplace.

Off-balance Sheet Arrangements and Contractual Cash Obligations

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~~enters into office space and certain lease and terminal access contracts in order to provide tank storage and dock access for its crude oil marketing business. Such storage and access contracts require certain minimum monthly payments for the term of the contracts. All ~~operating~~ lease commitments qualify for off-balance sheet treatment. The Company has no capital lease obligations. Rental expense ~~for the years ended December 31, 2012, 2011, and 2010~~ was ~~$8,110,000, $7,621,000 and $5,870,000, respectively.~~ as follows (in thousands):

	Year Ended December 31,
	2015		2014		2013

Rental expense	$	11,168	$	9,755	$	8,281

As of December 31, ~~2012,~~2015, rental ~~commitments~~obligations under long-term non-cancelable operating leases and terminal arrangements for the next five years and thereafter are payable ~~as follows: 2013 - $3,404,000; 2014 - $1,718,000; 2015 - $1,450,000; 2016 - $1,431,000; 2017 – $1,210,000 and $724,000 thereafter.~~

~~Contractual Cash Obligations~~

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

2013

2014

2015

2016

2017

Thereafter

Total

Lease payments $ 3,404 $ 1,718 $ 1,450 $ 1,431 $ 1,210 $ 724 $ 9,937

2016				2017				2018				2019				2020				Thereafter				Total
$	6,218			$	4,160			$	1,697			$	318			$	-			$	-			$	12,393

In addition to its lease obligations, the Company is also committed to purchase certain quantities of crude oil ~~and natural gas~~ in connection with its marketing activities. Such commodity purchase obligations are the basis for commodity sales, which generate the cash flow necessary to meet such purchase obligations. Approximate commodity purchase obligations as of December 31, ~~2012~~2015 are as follows (in thousands):

January Remaining

2013

2013

2014

2015

Thereafter

Total

Crude oil $ 256,953 $ 45 $ - $ - $ - $ 256,998
Natural gas 8,862 301 - - - 9,163
$ 265,815 $ 346 $ - $ - $ - $ 266,161

January		Remaining
2016		2016		2017		2018		Thereafter		Total
$	68,830	$	130	$	-	$	-	$	-	$	68,960

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 its employees. ~~During each of 2012, 2011 and 2010, insurance~~Insurance costs ~~were consistent with activity and totaled $11.9 million, $11.2 million and $10 million, respectively.~~ are as follows (in thousands):

		2015				2014				2013
Insurance costs		$	15,570			$	14,800			$	14,900

Insurance ~~cost~~rates may experience ~~rate~~ increases during ~~2013~~2016 subject to market ~~conditions. Since~~conditions and claims experience. Because the Company is generally unable to pass on such cost increases, any increase ~~will need to~~must 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~~competitors possess financial resources substantially in excess of those of the Company. The Company faces competition principally in establishing trade credit, pricing of available materials and quality of service, 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.

Outlook

Persistently low crude oil prices, coupled with declining oil production, are expected to adversely impact the Company’s crude oil marketing operation. The goal is to maintain at least 85 percent of 2015 supply volumes, but such effort may come at the expense of reduced unit margins. Demand for transportation services remains uncertain. The focus in transportation, therefore, is on both aggressive marketing and cost containment. For the oil and gas segment, the effort is to reduce cost and optimize cash flow as reserves are produced. In January 2016, the Company invested in an employer-oriented medical management services firm and development of this investment area continues.

The Company has the following major objectives for 2016:

-	Marketing—manage declining supply volumes and unit margins to maintain operating earnings at the $15 million level, exclusive of inventory valuation changes.

-	Transportation—increase truck utilization and improve cost efficiencies to maintain operating earnings at the $3 million level.

-	Oil and gas—curtail all exploration activity; maintain oil and gas production; reduce operating overhead.

-	Employer-oriented medical management services—develop earnings enhancement opportunities arising from employer and employee insurance coverage.

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 ~~2012, 2011~~2015, 2014 and ~~2010.~~2013.

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, ~~2012,~~2015, 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(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.

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

AREC is named 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. AREC is currently named as a defendant in three such suits. 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, 2015 and 2014, the Company has accrued $500,000 of future legal and/or settlement 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 ~~natural gas and refined products~~ marketing customers are invoiced ~~daily or~~ monthly based on contractually agreed upon terms. Revenue is recognized in the month in which the physical product is delivered to the customer. Where required, the Company also recognizes fair value or mark-to-market gains and losses related to its commodity activities. See discussion under ~~Revenue Recognition policy~~‟Revenue Recognition” 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 May ~~2011,~~2014, the ~~Financial Accounting Standards Board (‟FASB”) issued~~ FASB ~~Accounting Standards Update (ASU) No. 2011-04,~~amended the existing accounting standards for revenue recognition. The amendments are based on the principle that revenue should be recognized to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which ~~further amends~~ the ~~Fair Value Measurements and Disclosures topic~~entity expects to be entitled in exchange for those goods or services. The new guidance is effective for annual periods ending after December 15, 2017. Early adoption is permitted. The amendments may be applied retrospectively to each prior period presented or retrospectively with the cumulative effect recognized as of the Accounting Standards Codification. Among other provisions, ASU 2011-04 expands and modifies certain principles and requirements for measuring fair value and disclosing fair value measurement information. The Company adopted ASU 2011-04 effective January 1, 2012 anddate of initial application. Management is currently evaluating the ~~adoption~~impact of ~~ASU 2011-04 did not have a material impact~~these amendments on the Company’s ~~consolidated financial statements, but additional disclosures regarding fair value measurements resulted.~~Consolidated Financial Statements and the transition alternatives.

In ~~December 2011,~~August 2014, the FASB issued ~~ASU 2011-11. This update requires additional disclosures about~~guidance requiring management to perform interim and annual assessments of an entity’s ~~right~~ability to continue as a going concern within one year of ~~setoff~~the date the financial statements are issued. The standard also provides guidance on determining when and ~~related arrangements associated with its~~how to disclose going-concern uncertainties in the financial ~~and derivative instruments.~~statements. The ~~ASU requires a tabular presentation that reflects the gross, net and setoff amounts associated with such assets and liabilities among other requirements. The expanded disclosure requirements are~~new guidance is effective for the annual ~~reporting~~period ending after December 15, 2016, and interim periods ~~beginning on January 1, 2013. The Company’s~~thereafter, with early adoption permitted. Management does not expect the adoption of ~~ASU 2011-11~~this guidance to have an impact on the Consolidated Financial Statements.

In July 2015, the FASB amended the existing accounting standards for inventory to provide for the measurement of inventory at the lower of cost or ‟net realizable value,” as defined in the standard. The new guidance is effective for the annual period ending after December 15, 2016, and interim periods thereafter, with early adoption permitted. Management does not ~~expected~~expect the adoption of this guidance to ~~result in significant additional disclosures.~~have an impact on the Consolidated Financial Statements.

In November 2015, the FASB issued guidance to simplify the presentation of deferred taxes in the statement of financial position. The amendment requires that deferred tax assets and liabilities be classified as non-current in the balance sheet. The Company adopted this guidance on a prospective basis effective December 31, 2015.

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

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Interest Rate Risk

The Company had no long-term debt outstanding at December 31, ~~2012~~2015 and ~~2011.~~2014. 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, ~~2012.~~2015.

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, ~~2011~~2014 through December 31, ~~2012, natural gas price realizations~~2015, the Company’s crude oil monthly average wholesale purchase costs ranged from ~~a monthly~~an average low of ~~$1.99 per mmbtu to a monthly average high of $4.48 per mmbtu. Crude oil prices ranged from a monthly average low of $86.05~~$32.85 per barrel to a monthly average high of ~~$113.10~~$101.22 per barrel during the same period. A hypothetical ten percent additional adverse change in average ~~natural gas and crude oil~~hydrocarbon prices, assuming no changes in volume levels, would have reduced earnings by approximately ~~$3,937,000~~$1,273,000 and ~~$3,252,000~~$2,684,000 for the comparative years ended December 31, ~~2012~~2015 and ~~2011,~~2014, respectively.

2630

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	2832

FINANCIAL STATEMENTS:

Consolidated Balance Sheets as of December 31, ~~2012~~2015 and ~~2011~~2014	2933

Consolidated Statements of Operations for the Years Ended
December 31, ~~2012, 2011~~2015, 2014 and ~~2010~~2013	3034

Consolidated Statements of Shareholders’ Equity for the Years Ended
December 31, ~~2012, 2011~~2015, 2014 and ~~2010~~2013	3135

Consolidated Statements of Cash Flows for the Years Ended
December 31, ~~2012, 2011~~2015, 2014 and ~~2010~~2013	3236

Notes to Consolidated Financial Statements	3337

2731

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, ~~2012~~2015 and ~~2011,~~2014, and the related consolidated statements of operations, shareholders' equity, and cash flows for each of the three years in the period ended December 31, ~~2012.~~2015. 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 atas of December 31, ~~2012~~2015 and ~~2011,~~2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, ~~2012,~~2015, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the financial statements, the Company changed its method of accounting for deferred income taxes effective January 1, 2015 due to the adoption of FASB ASU 2015-17, Balance Sheet Classification of Deferred Taxes.

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, ~~2012,~~2015, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March ~~15, 2013,~~11, 2016, expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/ Deloitte & Touche LLP

Houston, Texas

March ~~15, 2013~~11, 2016

2832

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands)

	December 31,						December 31,
ASSETS	2012			2011			2015			2014
CURRENT ASSETS:
Cash and cash equivalents	$	47,239		$	37,066		$	91,877		$	80,184
Accounts receivable, net of allowance for doubtful accounts of
$206 and $357, respectively		239,319			225,393
$206 and $179, respectively								71,813			144,434
Inventories		28,222			18,464			7,671			13,481
Fair value contracts		418			2,064			-			936
Income tax receivable		1,199			480			2,587			970
Prepayments		8,092			10,651			2,589			10,940
Current assets of discontinued operations		67			10,847

Total current assets		324,556			304,965			176,537			250,945

PROPERTY AND EQUIPMENT:
Marketing		46,177			33,004			65,200			65,865
Transportation		59,101			54,359			70,732			63,239
Oil and gas (successful efforts method)		90,431			81,668			77,117			88,661
Other		1,406			2,772			187			186
		197,115			171,803			213,236			217,951

Less – Accumulated depreciation, depletion and amortization		(106,403	)		(102,946	)		(153,521	)		(133,080	)
		90,712			68,857			59,715			84,871
OTHER ASSETS:
Deferred income tax asset		34			473
Cash deposits and other		4,199			4,167			6,963			4,998
Long-term assets of discontinued operations		-			378
	$	419,501		$	378,840		$	243,215		$	340,814
LIABILITIES AND SHAREHOLDERS’ EQUITY

CURRENT LIABILITIES:
Accounts payable	$	258,310		$	243,615		$	74,117		$	160,743
Accounts payable – related party		42			58			40			51
Fair value contracts		412			681			195			943
Accrued and other liabilities		7,078			6,095			5,845			6,208
Current deferred income taxes		240			505			-			658
Current liabilities of discontinued operations		-			5,140
Total current liabilities		266,082			256,094			80,197			168,603

LONG-TERM DEBT		-			-			-			-

OTHER LIABILITIES:
Asset retirement obligations		1,886			1,568			2,469			2,464
Deferred taxes and other liabilities		15,675			10,496			8,039			12,250
		283,643			268,158			90,705			183,317
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
4,217,596 issued and outstanding for all periods presented								422			422
Contributed capital		11,693			11,693			11,693			11,693
Retained earnings		123,743			98,567			140,395			145,382
Total shareholders’ equity		135,858			110,682			152,510			157,497
	$	419,501		$	378,840		$	243,215		$	340,814

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

2933

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	Years Ended December 31,									Years Ended December 31,
	2012			2011			2010			2015			2014			2013
REVENUES:
Marketing	$	3,297,827		$	2,967,427		$	2,015,893		$	1,875,885		$	4,050,497		$	3,863,057
Transportation		67,183			63,501			56,867			63,331			68,968			68,783
Oil and natural gas		15,954			14,060			11,021			5,063			13,361			14,129
		3,380,964			3,044,988			2,083,781			1,944,279			4,132,826			3,945,969
COSTS AND EXPENSES:
Marketing		3,244,685			2,912,316			1,996,926			1,841,893			4,020,017			3,815,006
Transportation		51,009			51,068			45,956			52,076			56,802			56,504
Oil and natural gas operations		12,941			22,608			8,116			19,013			15,826			8,748
Oil and natural gas property sale (gain)		(2,203	)		(2,923	)		-			-			(2,528	)		-
General and administrative		9,769			9,713			9,044			9,939			8,613			9,060
Depreciation, depletion and amortization		20,714			15,885			11,314			23,717			24,615			22,275
		3,336,915			3,008,667			2,071,356			1,946,638			4,123,345			3,911,593

Operating Earnings		44,049			36,321			12,425
Operating (Loss) Earnings											(2,359	)		9,481			34,376

Other Income (Expense):
Interest income		190			237			191			327			301			198
Interest expense		(10	)		(8	)		(36	)		(13	)		(2	)		(24	)

Earnings from continuing operations before income taxes		44,229			36,550			12,580
Earnings (loss) from continuing operations
before income taxes											(2,045	)		9,780			34,550

Income Tax (Provision) Benefit:
Current		(11,319	)		(5,523	)		(371	)		(4,073	)		(9,712	)		(9,269	)
Deferred		(5,378	)		(7,584	)		(3,657	)		4,843			6,151			(3,160	)
		(16,697	)		(13,107	)		(4,028	)		770			(3,561	)		(12,429	)
Earnings from continuing operations		27,532			23,443			8,552
Earnings from discontinued operations net of tax
(provision) benefit of ($139), $276 and $(42), respectively		259			(512	)		79
Earnings (loss) from continuing operations											(1,275	)		6,219			22,121
Earnings (loss) from discontinued operations net of tax
(provision) benefit of zero, $(163) and $275 respectively											-			304			(511	)

Net Earnings	$	27,791		$	22,931		$	8,631
Net Earnings (Loss)										$	(1,275	)	$	6,523		$	21,610

EARNINGS PER SHARE:
EARNINGS (LOSS) PER SHARE:
From continuing operations		6.53			5.55			2.03		$	(.30	)	$	1.48		$	5.24
From discontinued operations		.06			(.11	)		.02			-			.07			(.12	)
Basic and diluted net earnings per share	$	6.59		$	5.44		$	2.05		$	(.30	)	$	1.55		$	5.12

Dividends declared per common share										$	.88		$	.88		$	.66

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

3034

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(In thousands)

								Total										Total
	Common		Contributed		Retained			Shareholders’			Common		Contributed		Retained			Shareholders’
	Stock		Capital		Earnings			Equity			Stock		Capital		Earnings			Equity

BALANCE, January 1, 2010	$	422	$	11,693	$	71,686		$	83,801
BALANCE, January 1, 2013											$	422	$	11,693		123,743			135,858
Net earnings		-		-		8,631			8,631			-		-		21,610			21,610
Dividends paid on common stock		-		-		(2,277	)		(2,277	)		-		-		(2,783	)		(2,783	)
BALANCE, December 31, 2010	$	422	$	11,693	$	78,040		$	90,155
BALANCE, December 31, 2013											$	422	$	11,693	$	142,570		$	154,685
Net earnings		-		-		22,931			22,931			-		-		6,523			6,523
Dividends paid on common stock		-		-		(2,404	)		(2,404	)		-		-		(3,711	)		(3,711	)
BALANCE, December 31, 2011	$	422	$	11,693	$	98,567		$	110,682
Net earnings		-		-		27,791			27,791
BALANCE, December 31, 2014											$	422	$	11,693	$	145,382		$	157,497
Net earnings (loss)												-		-		(1,275	)		(1,275	)
Dividends paid on common stock		-		-		(2,615	)		(2,615	)		-		-		(3,712	)		(3,712	)
BALANCE, December 31, 2012	$	422	$	11,693	$	123,743		$	135,858
BALANCE, December 31, 2015											$	422	$	11,693	$	140,395		$	152,510

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

3135

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Years Ended December 31,									Years Ended December 31,
	2012			2011			2010			2015			2014			2013
CASH PROVIDED BY OPERATIONS:
Net earnings	$	27,791		$	22,931		$	8,631
Net earnings (loss)										$	(1,275	)	$	6,523		$	21,610
Adjustments to reconcile net earnings to net cash
from operating activities-
Depreciation, depletion and amortization		20,714			16,260			11,817			23,717			24,615			22,275
Property sale (gains) losses		(6,298	)		(4,394	)		94
Property sales (gains) oil and gas											-			(2,528	)		-
Property sale (gains) other											(535	)		(1,028	)		(683	)
Dry hole costs incurred		43			1,212			1,894			817			1,034			233
Impairment of oil and natural gas properties		5,555			14,749			2,224			12,082			8,009			2,630
Provision for doubtful accounts		(51	)		1,141			29			27			(73	)		46
Deferred income taxes		5,378			7,308			3,699			(4,843	)		(6,151	)		3,161
Net change in fair value contracts		1,377			(97	)		(1,036	)		188			402			(389	)
Decrease (increase) in accounts receivable		(4,820	)		(45,487	)		(34,257	)		72,594			99,749			(4,770	)
Decrease (increase) in inventories		(9,579	)		(5,598	)		669			5,810			14,135			606
Decrease (increase) in income tax receivable		(719	)		1,836			(145	)		(1,617	)		1,127			(898	)
Decrease (increase) in prepayments		2,559			(2,547	)		2,700			8,351			5,839			(8,687	)
Increase (decrease) in accounts payable		10,474			47,662			40,521			(87,404	)		(104,887	)		7,809
Increase (decrease) in accrued and other liabilities		1,227			1,378			(406	)		(166	)		448			(516	)
Other changes, net		843			(539	)		494			(2,269	)		(81	)		1,549
Net cash provided by operating activities		54,494			55,815			36,928			25,477			47,133			43,976

INVESTING ACTIVITIES:
Property and equipment additions		(51,012	)		(53,276	)		(22,421	)		(11,074	)		(30,523	)		(27,602	)
Insurance and state collateral (deposits) refunds		(582	)		(495	)		(151	)		283			(493	)		(1,179	)
Proceeds from property sales		6,342			8,394			147			719			7,045			1,082
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		(41,706	)		(45,377	)		(22,425	)		(10,072	)		(23,971	)		(27,699	)

FINANCING ACTIVITIES:
Dividend payments		(2,615	)		(2,404	)		(2,277	)		(3,712	)		(3,711	)		(2,783	)
Net cash (used in) financing activities		(2,615	)		(2,404	)		(2,277	)		(3,712	)		(3,711	)		(2,783	)

Increase (decrease) in cash and cash equivalents		10,173			8,034			12,226			11,693			19,451			13,494

Cash and cash equivalents at beginning of year		37,066			29,032			16,806			80,184			60,733			47,239

Cash and cash equivalents at end of year	$	47,239		$	37,066		$	29,032		$	91,877		$	80,184		$	60,733

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

3236

ADAMS RESOURCES & ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Summary of Significant Accounting Policies

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Adams Resources & Energy, Inc., a Delaware corporation ~~and~~(‟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, ~~2012 were~~2015 was evaluated through the date of issuance of these financial statements.

Nature of Operations

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. Its primary area of operation is within ~~a 1,000 mile radius~~the Gulf Coast region of ~~Houston, Texas.~~the United States.

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~~are the product of ~~crude oil, natural gas and refined products as well as from trucking services. Marketing business wholesale level~~ sales of crude oil and natural gas and the sale of trucking services. Marketing segment wholesale level sales of crude oil comprise in excess of 90 percent of total accounts receivable and under industry practices, such items are ‟settled” and paid in cash within 2520 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~~the sale 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

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. Due to declining crude oil prices, inventory valuation losses were as follows (in thousands):

		2015				2014
Inventory valuation loss		$	5,357			$	14,247

Prepayments

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

	December 31,				December 31,
	2012		2011		2015		2014
Cash collateral deposits for commodity purchases	$	5,000	$	6,521	$	167	$	7,872
Insurance premiums		1,872		2,033		1,609		2,316
Commodity imbalances and futures		353		1,452
Rents, license and other		867		645		813		752
					$	2,589	$	10,940
	$	8,092	$	10,651

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, ~~2012,~~2015 and 2014, the Company had no unevaluated or ~~suspended~~‟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 or denominator 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. The numerator for such calculation is actual production volumes for the period. 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 ~~undiscounted cash flow models indicate~~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. ~~The~~For properties requiring impairment, the fair value ~~of each oil and gas property~~ 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, 2012, 2011 and 2010, there were $4,699,000, $7,105,000 and $946,000, 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, 2012 and 2011 summarized as follows~~ ~~(in thousands):~~

Producing Properties
Subject to Fair
Value Impairment

2012

2011

Net book value at January 1 $ 11,073 $ 8,704
Property additions 13,083 16,465
Depletion taken (6,371 ) (6,633 )
Impairment valuation loss (4,699 ) (7,105 )
Net book at December 31 $ 13,086 $ 11,431

~~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~~area. Therefore, such data inputs are categorized as ‟unobservable or Level 3” inputs. (See ‟Fair Value Measurements” below). 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 including in oil and gas segment operating losses were as follows (in thousands):

	2015		2014		2013
Producing property impairments	$	10,324	$	4,001	$	1,373
Non-producing property impairments	$	1,758	$	4,008	$	1,257

Fair value measurements for producing oil and gas properties that were subject to fair value impairment ~~provisions on non-producing properties totaling $856,000, $7,644,000 and $1,277,000 were recorded~~ for the years ~~ending~~ended December 31, ~~2012, 2011~~2015 and ~~2010, respectively.~~ 2014 summarize as follows (in thousands):

	Producing Properties
	Subject to Fair
	Value Impairment
	2015			2014
Net book value at January 1	$	18,744		$	10,180
Property additions		2,117			469
Depletion taken		(4,454	)		(1,792	)
Impairment valuation loss		(10,324	)		(4,001	)
Net book value at December 31	$	6,083		$	4,856

Capitalized costs for non-producing oil and gas leasehold interests currently represent approximately ~~four~~three percent of ~~total~~remaining unamortized oil and gas property carrying costs and ~~are categorized~~categorize as follows (in thousands):

December 31, December 31,

2012

2011

South Texas Project acreage $ 3,263 $ 2,212
West Texas Project 180 288
Napoleonville Louisiana acreage 323 320
Other acreage areas 329 475

Total Non-producing Leasehold Costs $ 4,095 $ 3,295

	December 31,		December 31,
	2015		2014

Napoleonville Louisiana acreage	$	49	$	48
South Texas project acreage		-		357
Wyoming and other acreage		182		554
Total Non-producing Leasehold Costs	$	231	$	959

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. ~~The~~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 and fair value measurements on ~~the ‟Other Acreage Areas” was~~non-producing leasehold were as follows (in thousands):

Leasehold

Costs

Balance December 31, 2011 $ 475
Property additions 810
Property sale (100 )
Impairments (856 )

Balance December 31, 2012 $ 329

	Leasehold Costs
	2015			2014
Net book value January 1	$	959		$	4,906
Leasehold additions		106			865
Advanced royalty payment		529			-
In-process wells suspended		395			73
Property sales		-			(877	)
Impairments valuation loss		(1,758	)		(4,008	)
Net book value December 31	$	231		$	959

During ~~2012,~~2014, the Company sold ~~half~~substantially all of its ~~interest~~producing property interests in ~~certain non-producing Kansas oil and gas properties.~~Oklahoma. Proceeds ~~from the sale~~ totaled ~~$578,000~~$1,731,000 and the Company recorded a ~~$475,000~~$1,149,000 pre-tax gain from this sale. Also during ~~2012,~~2014 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 saleone-half of its interest in ~~certain producing oil and gas properties located in the on-shore Gulf Coast region~~sections of ~~Texas.~~a South Texas project interest. Proceeds ~~from the 2011 sale~~ totaled ~~$6.2 million~~$1,509,000 and the ~~pre-tax gain totaled $2,708,000. Also during 2011, the~~ Company ~~sold~~recorded a ~~portion of its interest in certain non-producing oil and gas properties located in West Texas for $329,000 with a $125,000~~$632,000 pre-tax gain from this ~~transaction.~~sale. Certain other oil and gas property interests were also sold in 2014 for proceeds totaling $822,000 and gains totaling $747,000.

~~During 2012 and 2011, the~~The Company sold certain used trucks and equipment from its marketing and transportation ~~segment~~segments and recorded net pre-tax gains ~~totaling $2,617,000 and $1,024,000, respectively. There were no transportation equipment sales during 2010.~~as follows (in thousands):

		2015				2014				2013
Sales of used trucks and equipment		$	535			$	1,028			$	683

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. This fair value measure relies on inputs from quoted prices for similar assets and is thus categorized as a ‟Level 2” valuation in the fair value hierarchy. Components of cash deposits and other assets are as follows (in thousands):

	December 31,				As of December 31,
	2012		2011		2015		2014
Insurance collateral deposits	$	3,413	$	3,331	$	6,531	$	4,536
State collateral deposits		170		168		140		155
Materials and supplies		616		668		292		307
	$	4,199	$	4,167	$	6,963	$	4,998

Revenue Recognition

~~Commodity~~Certain commodity purchase and sale contracts utilized by the Company’s marketing ~~businesses~~business generally qualify as derivative ~~instruments. Further, all natural gas contracts, as well as~~instruments with certain specifically identified crude oil contracts ~~are~~ designated as trading activities. From the time of contract origination, such trading activity contracts are marked-to-market and recorded on a net revenue basis in the accompanying 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 $1,381,352,000, $1,812,561,000 and $1,415,844,000 for the years ended December 31, 2012, 2011 and 2010, respectively.~~as follows (in thousands):

		2015				2014				2013
Revenue gross-up		$	480,111			$	1,272,034			$	1,602,626

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.

Sales of long-lived assets

Gains and losses from the sale or disposal of long-lived assets that do not meet the criteria for presentation as a discontinued operation are presented in the accompanying financial statements as a component of operating earnings.

3640

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 ~~and natural gas~~ purchases within the marketing segment. This facility is collateralized by the eligible accounts receivable within ~~those operations~~the segment and certain marketing and transportation equipment. Stand-by letters of credit issued ~~totaled $21.9 million and $38.9 million~~were as ~~of December 31, 2012 and 2011, respectively.~~ follows (in thousands):

	As of December 31,
	2015		2014
Stand-by letters of credit	$	1,000	$	15,300

The issued stand-by letters of credit are cancelled as the underlying purchase obligations are satisfied by cash payment when due. The letter of credit facility places certain restrictions on the Company’s Gulfmark Energy, Inc. ~~and Adams Resources Marketing, Ltd. subsidiaries.~~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 $10,000, $8,000 and $36,000 during the years ended December 31, 2012, 2011 and 2010, respectively. Income taxes paid during these same periods totaled $12,650,000, $5,597,000, and $532,000, respectively. In addition, State and Federal income tax refunds totaled $10,000 and $2,743,000 in 2012 and 2011, respectively. There were no tax refunds during 2010. Non-cash investing activities for property and equipment items included in accounts payable as of period end were $2,419,000, $4,070,000 and $2,868,000 as of December 31, 2012, 2011 and 2010, respectively. There were no significant non-cash financing activities in any of the periods reported. Statement of cash flow items include the following (in thousands):

	2015		2014		2013

Interest paid	$	13	$	2	$	24

Federal and state tax paid	$	6,197	$	8,169	$	9,949

State tax refund	$	-	$	18	$	4

Capitalized amounts included in property and equipment that were not included in amounts reported for cash additions in the Statements of Cash Flows for the applicable report dates were as follows (in thousands):

	As of December 31,
	2015		2014		2013

Property and equipment additions	$	1,707	$	1,137	$	1,507

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 ~~2012, 2011~~2015, 2014 and ~~2010.~~2013. There were no potentially dilutive securities outstanding 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~~forming the foundation for calculating depreciation, depletion and amortization and for estimating cash flows ~~to assess~~when assessing impairment triggers and ~~estimated~~when estimating 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~~such items and their respective tax basis ~~(see~~(See also Note 2)(2) to consolidated financial statements).

Use of Derivative Instruments

The Company’s marketing segment is involved in the purchase and sale of crude ~~oil and natural gas.~~oil. The Company seeks to make a profit by procuring ~~these commodities~~this commodity as ~~they are~~it is produced and then delivering ~~these materials~~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~~Some 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 ~~and natural gas~~ wholesale distribution businesses. None of the Company’s derivative instruments have been designated as hedging instruments. 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~~The estimated fair value of forward month commodity contracts (derivatives) is reflected in the accompanying Consolidated Balance Sheet as of December 31, ~~2012~~2015 as follows (in thousands):

	Balance Sheet Location and Amount										Balance Sheet Location and Amount
	Current			Other		Current			Other		Current		Other		Current		Other
	Assets			Assets		Liabilities			Liabilities		Assets		Assets		Liabilities		Liabilities
Asset Derivatives
- Fair Value Commodity
Contracts at Gross Valuation	$	688		$	-	$	-		$	-	$	-	$	-	$	-	$	-
Liability Derivatives
- Fair Value Commodity
Contracts at Gross Valuation		-			-		682			-		-		-		195		-
Less Counterparty Offsets		(270	)		-		(270	)		-		-		-		-		-
As Reported Fair Value Contracts	$	418		$	-	$	412		$	-	$	-	$	-	$	195	$	-

As of December 31, ~~2012, twenty-four commodity purchase and sales contracts comprise all of~~2015, one contract comprised the Company’s derivative valuations. ~~Such contracts encompass the~~The purchase and sale ofcontract encompass approximately ~~900~~65 barrels of crude oil per day and 172,000 mmbtu of natural gas per day during January 2013 with crude oil volumes continuing at the rate of 200 barrels per day through June 2013 together with natural gas volumes of 1,000 mmbtu and 41,000 mmbtudiesel fuel per day in each of January, February ~~2013~~ and March ~~2013, respectively.~~2016.

~~Forward~~The estimated fair value of forward month commodity contracts (derivatives) ~~are~~is reflected in the accompanying Consolidated Balance Sheet as of December 31, ~~2011~~2014 as follows (in thousands):

	Balance Sheet Location and Amount										Balance Sheet Location and Amount
	Current			Other		Current			Other		Current			Other		Current			Other
	Assets			Assets		Liabilities			Liabilities		Assets			Assets		Liabilities			Liabilities
Asset Derivatives
- Fair Value Commodity
Contracts at Gross Valuation	$	3,500		$	-	$	-		$	-	$	1,332		$	-	$	-		$	-
Liability Derivatives
- Fair Value Commodity
Contracts at Gross Valuation		-			-		2,117			-		-			-		1,339			-
Less Counterparty Offsets		(1,436	)		-		(1,436	)		-		(396	)		-		(396	)		-
As Reported Fair Value Contracts	$	2,064		$	-	$	681		$	-	$	936		$	-	$	943		$	-

As of December 31, ~~2011, thirteen~~2014, three commodity purchase and ~~sales~~sale contracts comprised ~~substantially all of~~ the Company’s derivative valuations. ~~Such~~These contracts ~~encompassed the purchase and sale of~~encompass approximately ~~2,800, 6,100, 5,800, 5,700 and 1,800~~294 barrels per day of crude oil ~~per day in each of~~for January and February ~~March, April and May 2012, respectively, and continuing at 1,800~~2015 plus 129 barrels per day ~~for June 2012~~of crude oil from March 2015 through December ~~2012.~~2015.

The Company only enters into commodity contracts with creditworthy counterparties or obtains collateral support for such activities. As of December 31, ~~2012~~2015 and ~~2011,~~2014, 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, ~~2012, 2011~~2015, 2014 and ~~2010~~2013 as follows (in thousands):

	Gain (Loss)							Gain (Loss)
Location	2012			2011		2010		2015			2014		2013
Revenues – marketing	$	(1,377	)	$	97	$	1,036	$	(188	)	$	312	$	(193	)

Fair Value Measurements

The carrying amount reported in the ~~balance sheet~~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, ~~the Intercontinental Exchange ‟ICE”,~~ published price data and indices, third party price survey data and broker provided forward price statistics.

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

As of December 31, ~~2012,~~2015, the Company’s fair value assets and liabilities are summarized and categorized as follows (in thousands):

	Market Data Inputs													Market Data Inputs
	Gross Level 1		Gross Level 2			Gross Level 3		Counterparty						Gross Level 1		Gross Level 2			Gross Level 3		Counterparty
	Quoted Prices		Observable			Unobservable		Offsets			Total			Quoted Prices		Observable			Unobservable		Offsets		Total
Derivatives
- Current assets	$	299	$	389		$	-	$	(270	)	$	418		$	-	$	-		$	-	$	-	$	-
- Current liabilities		-		(682	)		-		270			(412	)		-		(195	)		-		-		(195	)
Net Value	$	299	$	(293	)	$	-	$	-		$	6		$	-	$	(195	)	$	-	$	-	$	(195	)

As of December 31, ~~2011,~~2014, the Company’s fair value assets and liabilities are summarized and categorized as follows (in thousands):

	Market Data Inputs														Market Data Inputs
	Gross Level 1			Gross Level 2			Gross Level 3		Counterparty						Gross Level 1		Gross Level 2			Gross Level 3		Counterparty
	Quoted Prices			Observable			Unobservable		Offsets			Total			Quoted Prices		Observable			Unobservable		Offsets			Total
Derivatives
- Current assets	$	1,455		$	2,045		$	-	$	(1,436	)	$	2,064		$	-	$	1,332		$	-	$	(396	)	$	936
- Current liabilities		(675	)		(1,442	)		-		1,436			(681	)		-		(1,339	)		-		396			(943	)
Net Value	$	780		$	603		$	-	$	-		$	1,383		$	-	$	(7	)	$	-	$	-		$	(7	)

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, ~~2012~~2015 and ~~2011,~~2014, 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, ~~2012~~2015 (in thousands):

	Level 1			Level 2						Level 1		Level 2
	Quoted Prices			Observable			Total			Quoted Prices		Observable			Total
Net Fair Value January 1,	$	780		$	603		$	1,383
Net Fair Value January 1										$	-	$	(7	)	$	(7	)
- Net realized (gains) losses		(780	)		(603	)		(1,383	)		-		7			7
- Net unrealized gains (losses)		299			(293	)		6			-		(195	)		(195	)
Net Fair Value December 31,	$	299		$	(293	)	$	6
Net Fair Value December 31										$	-	$	(195	)	$	(195	)

The following table illustrates the factors impacting the change in the net value of the Company’s fair value contracts for the year ended December 31, ~~2011~~2014 (in thousands):

	Level 1			Level 2						Level 1		Level 2
	Quoted Prices			Observable			Total			Quoted Prices		Observable			Total
Net Fair Value January 1,	$	(118	)	$	1,404		$	1,286
Net Fair Value January 1										$	-	$	395		$	395
- Net realized (gains) losses		118			(1,404	)		(1,286	)		-		220			220
- Option deposit											-		(714	)		(714	)
- Option gain											-		99			99
- Net unrealized gains (losses)		780			603			1,383			-		(7	)		(7	)
Net Fair Value December 31,	$	780		$	603		$	1,383
Net Fair Value December 31										$	-	$	(7	)	$	(7	)

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):

	2012			2011			2015			2014
Balance on January 1,	$	1,568		$	1,390
Balance on January 1							$	2,464		$	2,564
-Liabilities incurred		358			164			39			111
-Accretion of discount		63			82			93			94
-Liabilities settled		(103	)		(68	)		(127	)		(305	)
-Revisions to estimates		-			-
Balance on December 31,	$	1,886		$	1,568
Balance on December 31							$	2,469		$	2,464

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 May ~~2011,~~2014, the ~~Financial Accounting Standards Board (‟FASB”) issued~~ FASB ~~Accounting Standards Update (ASU) No. 2011-04,~~amended the existing accounting standards for revenue recognition. The amendments are based on the principle that revenue should be recognized to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which ~~further amends~~ the ~~Fair Value Measurements and Disclosures topic~~entity expects to be entitled in exchange for those goods or services. The new guidance is effective for the annual period ending after December 15, 2017. Early adoption is not permitted. The amendments may be applied retrospectively to each prior period presented or retrospectively with the cumulative effect recognized as of the Accounting Standards Codification. Among other provisions, ASU 2011-04 expands and modifies certain principles and requirements for measuring fair value and disclosing fair value measurement information. The Company adopted ASU 2011-04 effective January 1, 2012 anddate of initial application. Management is currently evaluating the ~~adoption~~impact of ~~ASU 2011-04 did not have a material impact~~these amendments on the Company’s consolidated financial statements ~~but additional disclosures regarding fair value measurements resulted.~~and the transition alternatives.

In ~~December 2011,~~August 2014, the FASB issued ~~ASU 2011-11. This update requires additional disclosures about~~guidance requiring management to perform interim and annual assessments of an entity’s ~~right~~ability to continue as a going concern within one year of ~~setoff~~the date the financial statements are issued. The standard also provides guidance on determining when and ~~related arrangements associated with its~~how to disclose going-concern uncertainties in the financial ~~and derivative instruments.~~statements. The ~~ASU requires a tabular presentation that reflects the gross, net and setoff amounts associated with such assets and liabilities among other requirements. The expanded disclosure requirements are~~new guidance is effective for the annual ~~reporting~~period ending after December 15, 2016, and interim periods ~~beginning~~thereafter, with early adoption permitted. Management does not expect the adoption of this guidance to have an impact on the Consolidated Financial Statements.

In July 2015, the FASB amended the existing accounting standards for inventory to provide for the measurement of inventory at the lower of cost of ‟net realizable value,” as defined in the standard. The new guidance is effective for the annual period ending after December 15, 2016, and interim periods thereafter, with early adoption permitted. Management does not expect the adoption of this guidance to have an impact on the consolidated financial statements.

In November 2015, the FASB issued guidance to simplify the presentation of deferred taxes in the statement of financial position. The amendment requires that deferred tax assets and liabilities be classified as non-current in the balance sheet. The Company adjusted this guidance on a prospective basis effective January 1, ~~2013. The Company’s adoption of ASU 2011-11 is not expected to result in significant additional disclosures.~~2015.

(2) Income Taxes

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

	Years ended December 31,									Years ended December 31,
	2012			2011			2010			2015			2014			2013
Current:
Federal	$	(10,282	)	$	(4,336	)	$	350		$	(3,883	)	$	(8,626	)	$	(8,102	)
State		(1,176	)		(1,187	)		(721	)		(190	)		(1,249	)		(892	)
		(11,458	)		(5,523	)		(371	)		(4,073	)		(9,875	)		(8,994	)
Deferred:
Federal		(4,940	)		(7,407	)		(3,688	)		5,011			5,878			(2,682	)
State		(438	)		99			(11	)		(168	)		273			(478	)
		(5,378	)		(7,308	)		(3,699	)		4,843			6,151			(3,160	)

	$	(16,836	)	$	(12,831	)	$	(4,070	)	$	770		$	(3,724	)	$	(12,154	)

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

	Years ended December 31,									Years ended December 31,
	2012			2011			2010			2015		2014			2013
From continuing operations	$	(16,697	)	$	(13,107	)	$	(4,028	)	$	770	$	(3,561	)	$	(12,429	)
From discontinued operations		(139	)		276			(42	)		-		(163	)		275
	$	(16,836	)	$	(12,831	)	$	(4,070	)	$	770	$	(3,724	)	$	(12,154	)

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

	Years ended December 31,									Years ended December 31,
	2012			2011			2010			2015			2014			2013
Statutory federal income tax (provision) benefit	$	(15,619	)	$	(12,517	)	$	(4,445	)	$	716		$	(3,587	)	$	(11,819	)
State income tax (provision) benefit		(1,049	)		(707	)		(476	)		(233	)		(634	)		(891	)
Federal statutory depletion		36			393			534			144			549			522
Foreign investment write-off		-			-			201
Other		(204	)		-			116			143			(52	)		34
	$	(16,836	)	$	(12,831	)	$	(4,070	)	$	770		$	(3,724	)	$	(12,154	)

Deferred income taxes reflect the net difference between the financial statement carrying amounts and the underlying income tax basis in such items. Effective January 1, 2015 the Company adopted on a prospective basis an FASB guidance requiring that deferred tax assets and liabilities be classified as non-current in the balance sheet. The components of the federal deferred tax asset (liability) are as follows (in thousands):

Years Ended December 31,

2012

2011

Current deferred tax asset (liability)
Allowance for doubtful accounts $ 581 $ 772
Prepaid insurance (815 ) (793 )
Fair value contracts (6 ) (484 )

Net current deferred liability (240 ) (505 )

Long-term deferred tax asset (liability)
Property (15,957 ) (10,579 )
Uniform capitalization 552 471
Other (221 ) 160
Net long-term deferred tax liability (15,626 ) (9,948 )

Net deferred tax liability $ (15,866 ) $ (10,453 )

	Years Ended December 31,
	2015			2014
Current deferred tax asset (liability)
Allowance for doubtful accounts	$	-		$	62
Prepaid and other insurance		-			(719	)
Fair value contracts		-			(1	)
Net current deferred liability		-			(658	)

Long-term deferred tax asset (liability)
Prepaid and other insurance		(1,243	)		-
Property		(7,408	)		(12,673	)
Uniform capitalization		704			661
Other		(51	)		(170	)
Net long-term deferred tax liability		(7,998	)		(12,182	)
Net deferred tax liability	$	(7,998	)	$	(12,840	)

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~~federal and major states of operations are as follows:

	Earliest Open
	Tax Year

Federal	~~2009~~ 2012
Texas	~~2008~~ 2011
Louisiana	~~2009~~ 2012
Michigan	~~2009~~ 2011

(3) Concentration of Credit Risk

Credit risk ~~represents~~encompasses the amount of loss absorbed should the ~~Company would absorb if its~~Company’s customers ~~failed~~fail to perform pursuant to contractual terms. ~~Management of~~Managing 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.~~exposure. Accounts receivable associated with crude oil ~~and natural gas~~ marketing activities comprise approximately 9590 percent of the Company’s total receivables and industry practice requires payment for such sales to occur within 2520 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. An allowance for doubtful accounts is provided where appropriate. An analysis of the changes in the allowance for doubtful accounts is presented as follows (in thousands):

	2015			2014			2013
Balance, beginning of year	$	179		$	252		$	206
Provisions for bad debts		116			50			147
Less: Write-offs and recoveries		(89	)		(123	)		(101	)
Balance, end of year	$	206		$	179		$	252

The Company’s largest customers consist of large multinational integrated oil companies and ~~utilities.~~independent domestic refiners of crude oil. In addition, the Company transacts business with independent oil producers, major chemical concerns, crude oil ~~and natural gas~~ trading companies and a variety of commercial energy users. Within this group of customers, the Company generally derives approximately 50 percent of its revenues from ~~two~~three to ~~three~~five 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.~~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.~~operations as shown below:

The Company had accounts receivable from three customers that comprised 22.1 percent, 21.4 percent and 11.4 percent, respectively of total accounts receivables at December 31, 2012. Three customers comprised 20.2 percent, 17.9 percent and 16.8 percent, respectively, of total revenues during 2012. The Company had accounts receivable from two customers that comprised 24.5 percent and 21.5 percent, respectively, of total accounts receivable at December 31, 2011. Four customers comprised 18.2 percent, 15.4 percent, 13.4 percent, and 11.3 percent, respectively, of total revenues during 2011. The Company had accounts receivable from four customers that comprised 22.4 percent, 16.2 percent, 13.7 percent and 10.6 percent, respectively, of total accounts receivable at December 31, 2010. Five customers comprised 35.8 percent, 20.2 percent, 17.9 percent, 13 percent and 11 percent, respectively, of total revenues during 2010.

An allowance for doubtful accounts is provided where appropriate and accounts receivable presented herein are net of allowances for doubtful accounts of $206,000 and $357,000 at December 31, 2012 and 2011, respectively. As reflected in the table below, during 2011 the Company’s provision for bad debt was elevated as a result of deteriorating collectability primarily attributable to diesel fuel sales to the construction industry.

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

2012

2011

2010

Balance, beginning of year $ 357 $ 180 $ 347
Provisions for bad debts - 276 28
Less: Write-offs and recoveries (151 ) (99 ) (195 )
Balance, end of year $ 206 $ 357 $ 180

Individual customer sales									Individual customer receivables in excess
in excess of 10% of revenues									of 10% of total receivables as of December 31,
2015			2014			2013			2015			2014			2013
	24.4	%		20.3	%		18.5	%		20.3	%		16.6	%		16.0	%
	13.8	%		14.0	%		17.7	%		16.5	%		16.6	%		15.8	%
	-			-			15.8	%		12.7	%		10.4	%		12.7	%
	-			-			10.4	%		-			-			-

(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 $645,000, $597,000 and $565,000 in 2012, 2011 and 2010, respectively.~~ No other pension or retirement plans are maintained by the Company. The Company’s 401K plan contributory expenses were as follows (in thousands):

		2015				2014				2013
Contributory expenses		$	768			$	691			$	674

(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.~~Corporation (‟AREC”). Mr. Adams and ~~such~~the affiliates ~~participate~~participated on terms similar to those afforded other non-affiliated working interest owners. ~~In recent years,~~While the affiliates have generally maintained their existing property interest, they have not participated in any such ~~related party~~ transactions ~~generally result~~originating after the ~~Company has first identified oil and gas prospects~~death of ~~interest. Typically the available dollar commitment to participate~~Mr. Adams in such transactions is greater than the amount management is comfortable putting at risk. In such event, the Company first determines the percentage of the transaction it wants to obtain, which allows a related party to participate in the investment to the extent there is excess available. In those instances where there was no excess availability there has been no related party participation. Similarly, related parties are not required to participate, nor is the Company obligated to offer any such participation to a related or other party. When such related party transactions occur, they are individually reviewed and approved by the Audit Committee comprised of the independent directors on the Company’s Board of Directors. During 2012 and 2011, the Company’s investment commitments totaled approximately $22.7 million and $24.6 million, respectively, in those oil and gas projects where a related party was also participating in such investments. As of December 31, 2012 and 2011, the Company owed a combined net total of $42,000 and $58,000, respectively, to these related parties.October 2013. In connection with the operation of certain of these 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, $145,000 and $160,000 for the years ended December 31, 2012, 2011, and 2010, 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~~administrative services. ~~For the years ended December 31, 2012, 2011 and 2010, the affiliated entities charged~~In addition the Company $64,000, $42,000 and $43,000, respectively, of expense reimbursement and the Company charged the affiliates $98,000, $118,000 and $117,000, respectively, for such expense reimbursements. In January 2012, the company relocatedleases its ~~primary~~corporate office ~~lease~~ space ~~to a building operated by~~from an affiliated ~~entity. Estimated annual rental expense, including pro-rata building operating expense are $480,000 per year under~~entity based on a ~~seven year lease term. The~~ lease rental rate ~~was~~ determined by an independent appraisal. ~~Rental expense paid~~

Activities with affiliates were as follows (in thousands):

	2015		2014		2013
Overhead recoveries	$	97	$	151	$	152
Affiliate billings to Company	$	68	$	65	$	69
Company billings to affiliate	$	35	$	42	$	99
Rentals paid to affiliate	$	618	$	607	$	481

Additionally, in 2014, the Company engaged a professional services firm controlled by Townes Pressler, a member of the Company’s Board of Directors, to ~~the related party for 2012 totaled $442,000.~~conduct a crude oil supply availability study. Total study costs, all of which occurred in 2014 were $70,420.

(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~~enters into office space and 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. The Company has no capital lease arrangements. Rental expense ~~for the years ended December 31, 2012, 2011, and 2010 was $8,110,000, $7,621,000 and $5,870,000, respectively.~~ is as follows (in thousands):

	Years ended December 31,
	2015		2014		2013
Rental expense	$	11,168	$	9,755	$	8,281

At December 31, ~~2012, commitments~~2015, rental obligations under long-term non-cancelable operating leases and terminal arrangements for the next five years and thereafter are payable as ~~follows: 2013 - $3,404,000; 2014 - $1,718,000; 2015 - $1,450,000; 2016 - $1,431,000; 2017 $1,210,000; and $724,000 thereafter.~~follows (in thousands):

2016				2017				2018				2019				2020				Thereafter				Total
$	6,218			$	4,160			$	1,697			$	318			$	-			$	-			$	12,393

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 $1,545,000 and $1,285,000~~ as ~~of December 31, 2012 and 2011, respectively.~~follows (in thousands):

~~Effective January 1, 2012, the~~

	As of December 31,
	2015		2014		2013
Estimated expenses and liabilities	$	2,086	$	2,585	$	1,796

The Company ~~began~~maintains a self-insurance program for managing employee medical claims. ~~On a monthly basis, the Company establishes a~~A liability for expected claims ~~incurred.~~incurred is established on a monthly basis. As claims are paid, the liability is relieved. ~~As of December 31, 2012, accrued medical claims totaled $506,000 and the~~The Company ~~has purchased~~also maintains third party insurance stop-loss coverage for annual individual medical claims exceeding $100,000. In addition, the Company maintains $1$2 million of umbrella insurance coverage for aggregate medical claims exceeding approximately $4.5 million for the calendar ~~year~~years 2015 and 2014. Medical accrual amounts are as follows (in thousands):

	As of December 31,
	2015		2014		2013
Accrued medical claims	$	1,107	$	1,057	$	1,129

AREC is named 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. AREC is currently involved in three 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 and ~~$2 million~~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 except all the larger defendants have settled their claims in the LePetit Chateau Deluxe matter. The plaintiffs in each of ~~umbrella coverage~~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 these items. As of December 31, 2015 and 2014 the Company has accrued $500,000 of future legal and/or settlement costs for ~~2013.~~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

Pursuant to arranging operating lease financing for certain tank trailers, individual subsidiaries of the Company may guarantee the lessor a minimum residual equipment sales value upon the expiration of a lease and sale of the underlying equipment. The Company believes performance under these guarantees to be remote. Aggregate guaranteed residual values under operating leases as of December 31, 2012 are as follows ~~(in thousands):~~

2013

2014

2015

Thereafter

Total

Equipment residual values $ 216 $ - $ - $ - $ 216

In connection with certain contracts for the purchase and resale of branded motor fuels within the Company’s discontinued refined products marketing business (See Note (9), the Company received certain price discounts from its suppliers toward the purchase of gasoline and diesel fuel. Such discounts were passed through to the Company’s customers as an incentive to offset a portion of the costs associated with offering branded motor fuels for sale to the general public. Under the terms of the supply contracts, the Company and its customers are not obligated to return the price discounts, provided the gasoline service station offering such product for sale remains as a branded station for periods ranging from three to ten years. The Company had a number of customers and stations operating under such arrangements, and the former customers are contractually obligated to remain a branded dealer for the required periods of time. Should the customer seek to void such contracts, the Company would be obligated to return a portion of discounts received to its suppliers. As of December 31, 2012, the maximum potential obligation is approximately $1,385,000. Management of the Company believes such customers will adhere to their branding obligations and no such refunds will result. In addition, this branding obligation was assumed by the purchaser of the Company’s refined products contracts.

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

ARE ~~frequently~~ issues parent guarantees of commitments ~~resulting from~~associated with 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~~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, ~~2012,~~2015, parental guaranteed obligations are approximately as follows (in thousands):

	2016		2017		2018		2019		Thereafter		Total
Commodity purchases	$	15,855		-		-		-		-	$	15,855
Letters of credit		1,000		-		-		-		-		1,000
	$	16,855	$	-	$	-	$	-	$	-	$	16,855

2013

2014

2015

2016

Thereafter

Total

Lease payments $ 47 $ - $ - - - 47
Equipment residual values 216 - - - - 216
Commodity purchases 61,492 - - - - 61,942
Letters of credit 21,996 - - - - 21,996
$ 84,201 $ - $ - $ - $ - $ 84,201
Presently, neither ARE nor any of its subsidiaries has any other types of guarantees outstanding that require liability recognition.

(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, 2012-
Marketing
- Crude oil $ 3,292,948 $ 46,145 $ 5,945 $ 12,391
- Natural gas 4,879 1,021 31 -
Marketing Total 3,297,827 47,166 5,976 12,391
Transportation 67,183 10,253 5,921 15,538
Oil and gas 15,954 (3,601 )(1) 8,817 23,083
$ 3,380,964 $ 53,818 $ 20,714 $ 51,012
Year ended December 31, 2011-
Marketing
- Crude oil $ 2,961,176 $ 49,237 $ 3,724 $ 13,554
- Natural gas 6,251 2,147 3 64
Marketing Total 2,967,427 51,384 3,727 13,618
Transportation 63,501 8,521 3,912 14,118
Oil and gas 14,060 (13,871 )(1) 8,246 24,580
$ 3,044,988 $ 46,034 $ 15,885 $ 52,316
Year ended December 31, 2010-
Marketing
- Crude oil $ 2,005,301 $ 13,530 $ 2,320 $ 6,051
- Natural gas 10,592 3,073 44 115
Marketing Total 2,015,893 16,603 2,364 6,166
Transportation 56,867 6,623 4,288 4,410
Oil and gas 11,021 (1,757 ) 4,662 11,699
$ 2,083,781 $ 21,469 $ 11,314 $ 22,275

			Segment Operating			Depreciation Depletion and		Property and Equipment
	Revenues		Earnings (loss)			Amortization		Additions
Year ended December 31, 2015-
Marketing	$	1,875,885	$	22,895	(1)	$	11,097	$	2,126
Transportation		63,331		3,701			7,554		6,579
Oil and gas		5,063		(19,016	)(2)		5,066		2,369
	$	1,944,279	$	7,580		$	23,717	$	11,074
Year ended December 31, 2014-
Marketing	$	4,050,497	$	20,854	(1)	$	9,626	$	13,598
Transportation		68,968		4,750			7,416		8,994
Oil and gas		13,361		(7,510	)(2)		7,573		7,931
	$	4,132,826	$	18,094		$	24,615	$	30,523
Year ended December 31, 2013-
Marketing	$	3,863,057	$	40,369	(1)	$	7,682	$	11,343
Transportation		68,783		5,180			7,099		3,165
Oil and gas		14,129		(2,113	)(2)		7,494		13,094
	$	3,945,969	$	43,436		$	22,275	$	27,602

__________________________________

~~(1)~~

(1) Marketing segment operating earnings included inventory liquidation and valuation losses totaling $5,357,000, $14,247,000 and $3,824,000 for 2015, 2014 and 2013, respectively.

(2) Oil and gas segment operating earnings include gains on property sales totaling ~~$2,203,000~~$2,528,000 during 2014 and ~~$2,923,000 during 2012~~property impairments totaling $12,082,000, $8,009,000 and ~~2011,~~$2,630,000 for 2015, 2014 and 2013, 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,									Years Ended December 31,
	2012			2011			2010			2015			2014			2013
Segment operating earnings	$	53,818		$	46,034		$	21,469		$	7,580		$	18,094		$	43,436
- General and administrative expenses		(9,769	)		(9,713	)		(9,044	)		(9,939	)		(8,613	)		(9,060	)
Operating earnings		44,049			36,321			12,425
Operating earnings (loss)											(2,359	)		9,481			34,376
- Interest income		190			237			191			327			301			198
- Interest expense		(10	)		(8	)		(36	)		(13	)		(2	)		(24	)
Earnings from continuing operations before
Earnings (loss) from continuing operations before
income taxes and discontinued operations	$	44,229		$	36,550		$	12,580		$	(2,045	)	$	9,780		$	34,550

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

Years Ended December 31,

2012

2011

2010

Marketing
- Crude oil $ 277,920 $ 253,817 $ 184,299
- Natural gas 11,764 12,246 19,948
Marketing Total 289,684 266,063 204,247
Transportation 38,940 27,221 17,378
Oil and gas 35,788 29,105 32,563
Other 55,089 56,451 47,117
$ 419,501 $ 378,840 $ 301,305

	Years Ended December 31,
	2015		2014		2013
Marketing	$	96,723	$	189,332	$	306,693
Transportation		35,010		37,643		34,406
Oil and gas		8,930		25,888		37,093
Cash and other		102,552		87,951		69,890
	$	243,215	$	340,814	$	448,082

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,~~In 2014, the Company sold for $664,000 in cash the warehouse and real estate used by its former petroleum refined products marketing operation to yield a pre-tax gain of $553,000 with such gain reported in discontinued operations for 2014. In 2013 the Company completed ~~the sale of contracts, inventory~~an orderly wind-down and ~~certain equipment associated with the refined products segment~~closure of its natural gas marketing ~~business.~~segment. Revenues from this segment included in net earnings from discontinued operations totaled ~~$25,717,000, $169,412,000 and $128,189,000 for the years ended~~ December 31, 2012, 2011, and 2010, respectively. This business 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 is conducting an orderly wind-down of the operation which primarily consists 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$2,377,000 for the year ended December 31, ~~2012. Retained accounts receivable~~2013. All obligations from these ventures were satisfied and ~~payable obligations were substantially collected or satisfied as~~no further events are anticipated.

(10) Subsequent Event

On January 14, 2016 the Company’s wholly owned subsidiary Adams Resources Medical Management acquired a 30% member interest in Bencap LLC (Bencap) for a $2,200,000 cash payment. Bencap provides medical insurance brokerage and medical claims auditing services to employers utilizing ERISA governed employee benefit plans. The Company will account for this investment on the equity method of ~~the date of this report.~~

accounting.

~~(10)~~(11) Quarterly Financial Data (Unaudited) -

Selected quarterly financial data and earnings per share of the Company are presented below for the years ended December 31, ~~2012~~2015 and ~~2011~~2014 (in thousands, except per share data):

				Earnings from															Earnings (Loss) from
				Continuing Operations				Net Earnings				Dividends							Continuing Operations						Net Earnings (Loss)						Dividends
		Revenues		Amount		Per Share		Amount		Per Share		Amount		Per Share			Revenues		Amount			Per Share			Amount			Per Share			Amount		Per Share

	2012 -															2015 -
March 31	March 31	$	877,489	$	6,050	$	1.43	$	6,575	$	1.56	$	-	$	-	March 31	$	555,573	$	3,097		$	.73		$	3,097		$	.73		$	928	$	.22
June 30	June 30		831,474		5,497		1.31		5,386		1.28		-		-	June 30		600,558		4,340			1.03			4,340			1.03			928		.22
September 30	September 30		795,525		8,337		1.98		8,263		1.96		-		-	September 30		439,893		(308	)		(.07	)		(308	)		(.07	)		928		.22
December 31	December 31		876,476		7,648		1.81		7,567		1.79		2,615		.62	December 31		348,255		(8,404	)		(1.99	)		(8,404	)		(1.99	)		928		.22
Total	Total	$	3,380,964	$	27,532	$	6.53	$	27,791	$	6.59	$	2,615	$	.62	Total	$	1,944,279	$	(1,275	)	$	(.30	)	$	(1,275	)	$	(.30	)	$	3,712	$	.88

	2011 -															2014 -
March 31	March 31	$	663,846	$	5,778	$	1.37	$	5,583	$	1.32	$	-	$	-	March 31	$	949,189	$	5,363		$	1.27		$	5,363		$	1.27		$	928	$	.22
June 30	June 30		777,538		3,355		.79		3,589		.85		-		-	June 30		1,159,931		3,975			.94			3,975			.94			928		.22
September 30	September 30		755,995		9,266		2.20		9,026		2.14		-		-	September 30		1,173,970		3,855			.92			3,855			.92			928		.22
December 31	December 31		847,609		5,044		1.19		4,733		1.13		2,404		.57	December 31		849,736		(6,974	)		(1.65	)		(6,670	)		(1.58	)		927		.22
Total	Total	$	3,044,988	$	23,443	$	5.55	$	22,931	$	5.44	$	2,404	$	.57	Total	$	4,132,826	$	6,219		$	1.48		$	6,523		$	1.55		$	3,711	$	.88

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

~~(11)~~(12) 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,						For the year Ended December 31,
	2012		2011		2010		2015		2014		2013
Property acquisition costs
Unproved	$	1,965	$	3,591	$	2,295	$	348	$	1,144	$	1,444
Proved		-		-		-		-		-		-
Exploration costs
Expensed		1,151		9,166		3,233		1,667		5,054		1,619
Capitalized		-		-		-		-		-		-
Development costs		20,219		12,133		6,233		370		1,745		10,160
Total costs incurred	$	23,335	$	24,890	$	11,761	$	2,385	$	7,943	$	13,223

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

December 31,

2012

2011

Unproved oil and gas properties $ 8,349 $ 7,291
Proved oil and gas properties 82,083 74,376
90,432 81,667
Accumulated depreciation, depletion
and amortization (57,833 ) (55,061 )
Net capitalized cost $ 32,599 $ 26,606

	As of December 31,
	2015			2014
Unproved oil and gas properties	$	231		$	3,104
Proved oil and gas properties		76,886			85,557
		77,117			88,661
Accumulated depreciation, depletion
and amortization		(69,116	)		(64,682	)
Net capitalized cost	$	8,001		$	23,979

Estimated Oil and Natural Gas Reserves -

The following information regarding estimates of the Company’s proved oil and gas reserves, substantially all located onshore in Texas and ~~the south central region of the United States,~~Louisiana, 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,

2012

2011

2010

Natural Natural Natural
Gas Oil Gas Oil Gas Oil

(Mcf’s)

(Bbls.)

(Mcf’s)

(Bbls.)

(Mcf’s)

(Bbls.)

Total proved reserves-
Beginning of year 9,661 292 7,794 267 7,248 242
Revisions of previous estimates (507 ) 29 (520 ) (24 ) (832 ) -
Oil and gas reserves sold (104 ) (54 ) (2,148 ) (26 ) - -
Extensions, discoveries and
other reserve additions 2,395 138 6,430 137 2,743 79
Production (2,608 ) (98 ) (1,895 ) (62 ) (1,365 ) (54 )
End of year 8,837 307 9,661 292 7,794 267

	Years Ended December 31,
	2015						2014						2013
	Natural						Natural						Natural
	Gas			Oil			Gas			Oil			Gas			Oil
	(Mcf’s)			(Bbls.)			(Mcf’s)			(Bbls.)			(Mcf’s)			(Bbls.)
Total proved reserves-
Beginning of year		5,611			318			6,286			368			8,837			307
Revisions of previous estimates		27			(2	)		724			6			(1,438	)		(17	)
Oil and gas reserves sold		-			(3	)		(558	)		(11	)		(28	)		-
Extensions, discoveries and
other reserve additions		86			13			292			82			523			180
Production		(889	)		(100	)		(1,133	)		(127	)		(1,608	)		(102	)
End of year		4,835			226			5,611			318			6,286			368

The components of proved oil and gas reserves for the three years ended December 31, ~~2012~~2015 is presented below. All reserves are in the United States (in thousands):

Years Ended December 31,

2012

2011

2010

Natural Natural Natural
Gas Oil Gas Oil Gas Oil

(Mcf’s)

(Bbls.)

(Mcf’s)

(Bbls.)

(Mcf’s)

(Bbls.)

Proved developed reserves 8,708 306 9,433 277 7,134 240
Proved undeveloped reserves 129 1 228 15 660 27
Total proved reserves 8,837 307 9,661 292 7,794 267

	Years Ended December 31,
	2015				2014				2013
	Natural				Natural				Natural
	Gas		Oil		Gas		Oil		Gas		Oil
	(Mcf’s)		(Bbls.)		(Mcf’s)		(Bbls.)		(Mcf’s)		(Bbls.)
Proved developed reserves		4,813		223		5,482		299		6,157		367
Proved undeveloped reserves		22		3		129		19		129		1
Total proved reserves		4,835		226		5,611		318		6,286		368

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.~~AREC. 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~~employed third party petroleum consultant, Ryder Scott Company, to prepare its oil and gas reserve data estimates as of December 31, ~~2012, 2011~~2015, 2014 and ~~2010.~~2013. 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,									Years Ended December 31,
	2012			2011			2010			2015			2014			2013
Future gross revenues	$	59,793		$	73,626		$	61,311		$	23,040		$	58,885		$	64,495
Future costs -
Lease operating expenses		(16,357	)		(19,788	)		(17,288	)		(14,524	)		(16,421	)		(19,207	)
Development costs		(299	)		(2,198	)		(1,596	)		(103	)		(1,068	)		(119	)
Future net cash flows before income taxes		43,137			51,640			42,427			8,413			41,396			45,169
Discount at 10% per annum		(17,976	)		(19,439	)		(16,777	)		(2,987	)		(17,175	)		(17,729	)
Discounted future net cash flows
before income taxes		25,161			32,201			25,650			5,426			24,221			27,440
Future income taxes, net of discount at
10% per annum		(8,806	)		(11,270	)		(8,978	)		(1,899	)		(8,477	)		(9,604	)
Standardized measure of discounted
future net cash flows	$	16,355		$	20,931		$	16,672		$	3,527		$	15,744		$	17,836

The ~~reserve estimates provided at December 31, 2012, 2011 and 2010 are based on aggregate prices~~estimated value of ~~$93.85, $95.85 and $76.14 per barrel for crude~~ oil and ~~$3.51, $4.69 and $5.26 per mcf for~~ natural gas ~~respectively.~~ reserves and future net revenues, derived therefrom are highly dependent upon oil and gas commodity price assumptions. For such estimates, the Company’s independent petroleum engineers assumed market prices as presented in the table below:

	Years ended December 31,
	2015		2014		2013
Market price
Crude oil per barrel	$	45.83	$	89.60	$	94.99
Natural gas per thousand cubic feet (mcf)	$	2.62	$	5.42	$	4.69

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~~prices reported in the reserve ~~disclosure~~disclosures for natural gas ~~for 2012 includes~~include the value of associated natural gas liquids. Oil and gas reserve values and future net cash flow estimates are very sensitive to pricing assumptions and will vary accordingly.

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,
	2015			2014			2013
Future net cash flows before income taxes	$	8,413		$	41,396		$	45,169
Future income taxes		(2,945	)		(14,489	)		(15,809	)
Future net cash flows		5,468			26,907			29,360
Discount at 10% per annum		(1,941	)		(11,163	)		(11,524	)
Standardized measure of discounted
future net cash flows	$	3,527		$	15,744		$	17,836

5055

Years ended December 31,

2012

2011

2010

Future net cash flows before income taxes $ 43,137 $ 51,640 $ 42,427
Future income taxes (15,098 ) (18,074 ) (14,849 )
Future net cash flows 28,039 33,566 27,578
Discount at 10% per annum (11,684 ) (12,635 ) (10,906 )
Standardized measure of discounted
future net cash flows $ 16,355 $ 20,931 $ 16,672

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

	Years Ended December 31,									Years Ended December 31,
	2012			2011			2010			2015			2014			2013
Beginning of year	$	20,931		$	16,672		$	9,305		$	15,744		$	17,836		$	16,355
Sale of oil and gas reserves		(3,802	)		(7,429	)		-			(54	)		(981	)		-
Net change in prices and production costs		(5,313	)		791			9,435			(17,622	)		(72	)		9,341
New field discoveries and extensions, net of future
production costs		9,513			18,769			9,068			292			4,456			9,767
Sales of oil and gas produced, net of production costs		(8,953	)		(7,723	)		(7,084	)		1,038			(6,590	)		(8,373	)
Net change due to revisions in quantity estimates		(940	)		(1,739	)		(1,369	)		38			2,460			(3,624	)
Accretion of discount		1,944			1,678			1,072			1,116			1,773			1,797
Production rate changes and other		511			2,204			213			(3,603	)		(4,265	)		(6,629	)
Net change in income taxes		2,464			(2,292	)		(3,968	)		6,578			1,127			(798	)
End of year	$	16,355		$	20,931		$	16,672		$	3,527		$	15,744		$	17,836

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,									Years Ended December 31,
	2012			2011			2010			2015				2014			2013
Revenues	$	15,954		$	14,060		$	11,021		$	5,063			$	13,361		$	14,129
Costs and expenses -
Production		(7,091	)		(6,337	)		(3,937	)		(7,022	)			(6,771	)		(5,756	)
Producing property impairment		(4,699	)		(7,105	)		(946	)		(10,324	)	��		(4,001	)		(1,373	)
Exploration		(1,151	)		(9,166	)		(3,233	)		(1,667	)			(5,054	)		(1,619	)
Oil and natural gas property sale gain		2,203			2,923			-			-				2,528			-
Depreciation, depletion and amortization		(8,817	)		(8,246	)		(4,662	)		(5,066	)			(7,573	)		(7,494	)
Operating income (loss) before income taxes		(3,601	)		(13,871	)		(1,757	)		(19,016	)			(7,510	)		(2,113	)
Income tax (expense) benefit		1,060			4,854			615
Income tax benefit											6,656				2,628			739
Operating income (loss)	$	(2,541	)	$	(9,017	)	$	(1,142	)	$	(12,360	)		$	(4,882	)	$	(1,374	)

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 ~~SEC~~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 ~~13d-15(f)~~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, ~~2012.~~2015. In making this assessment, management used the criteria described in Internal Control – Integrated Framework (2013) 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, ~~2012.~~2015.

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

Changes in Internal Control over Financial Reporting

There have not been any changes in the Company’s internal control over financial reporting during the fiscal quarter ended December 31, ~~2012~~2015 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

5357

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and ~~Shareholders~~Stockholders 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, ~~2012,~~2015, based on criteria established in Internal Control — Integrated Framework (2013) 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~~the assessed 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, ~~2012,~~2015, based on the criteria established in Internal Control — Integrated Framework (2013) 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, ~~2012~~2015 of the Company and our report dated March ~~15, 2013~~11, 2016 expressed an unqualified opinion on those financial statements.

/s/Deloitte & Touche LLP

Houston, Texas

March ~~15, 2013~~11, 2016

5458

Item 9B. OTHER INFORMATION

None.

5559

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 ~~15, 2013,~~11, 2016, 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 ~~15, 2013,~~11, 2016, 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 ~~15, 2013,~~11, 2016, 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 ~~PARTY~~ TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by Item 13 is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Shareholders to be held Wednesday May ~~15, 2013,~~11, 2016, 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 ~~15, 2013,~~11, 2016, 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.

5660

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, ~~2012~~2015 and ~~2011~~2014

Consolidated Statements of Operations for the Years Ended

December 31, ~~2012, 2011~~2015, 2014 and ~~2010~~2013

Consolidated Statements of Shareholders’ Equity for the Years Ended

December 31, ~~2012, 2011~~2015, 2014 and ~~2010~~2013

Consolidated Statements of Cash Flows for the Years Ended

December 31, ~~2012, 2011~~2015, 2014 and ~~2010~~2013

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.~~

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.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)+~~10.1

- ~~Employment agreement~~

Form of ~~Frank T. Webster, President,~~Indemnification Agreement for directors and executive officers. (Incorporated by reference to Exhibit 10.1 of the Current Report on Form8-K filed on May 15, 2015).

10.2

Retirement Agreement, dated ~~May 12, 2004~~February 26, 2015, by and between Adams Resources & Energy, Inc. and Frank T. ‟Chip” Webster (Incorporated by reference to Exhibit 10.1 toof the ~~Company’s Quarterly~~Current Report ~~on Form 10-Q for the period ended September 30, 2004).~~

~~10.1(b)+~~

- Tenth Amendment to Employment Agreement of Frank T. Webster, President, by and between Adams Resources & Energy, Inc. and Frank T. Webster effective September 22, 2012 (Incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on September 24, 2012).

~~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)~~February 26, 2015).

~~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)+~~

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

~~10.1(g)+~~

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

~~10.1(h)+~~

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

~~10.1(i)+~~

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

~~10.1(j)+~~

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

5861

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

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, 2015 and 2014, (ii) the Consolidated Balance Sheets – December 31, 2015 and December 31, 2014, (iii) the Consolidated Statements of Cash Flows – Year Ended December 31, 2015 and 2014 and (iv) Notes to Consolidated Financial Statements.

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.

5962

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~~Thomas S. Smith
Richard B. Abshire,	~~Frank T. Webster~~Thomas S. Smith
Vice President and Chief Financial Officer	Chief Executive Officer
(Principal Financial Officer and Principal Accounting Officer)	(~~PPrincipal~~Principal Executive Officer)

Date: March ~~15, 2013~~11, 2016

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~~Thomas S. Smith Thomas S. Smith, Director	By /s/ Townes G. Pressler Townes G. Pressler, Director
(Chairman)

By /s/ Murray E. Brasseux	By /s/ E. C. Reinauer, Jr.
~~Frank T. Webster,~~Murray E. Brasseux, Director	E. C. Reinauer, Jr., Director



By /s/ Larry E. Bell	By /s/ ~~Townes G. Pressler~~Michelle A. Earley
Larry E. Bell, Director	~~Townes G. Pressler,~~Michelle A. Earley, Director



By ~~/s/ K. S. Adams, Jr.~~
~~K. S. Adams, Jr., Director~~
~~(Chairman)~~

6063

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	- Form of Indemnification Agreement for directors and executive officers. (Incorporated by
	Reference to Exhibit 10.1 of the Current Report on Form 8-K filed on May 15, 2015).

10.2	- Retirement Agreement, dated February 26, 2015, by and between Adams Resources & Energy, Inc. and Frank T. ‟Chip” Webster (Incorporated by reference to Exhibit 10.1 of the
	Current Report on Form 8-K filed on February 26, 2015).
	Report on Form 8-K filed on February 26, 2015).

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.

**- ~~Filed herewith~~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, 2015 and 2014, (ii) the Consolidated Balance Sheets – December 31, 2015 and December 31, 2014, (iii) the Consolidated Statements of Cash Flows – Year Ended December 31, 2015 and 2014 and (iv) Notes to Consolidated Financial Statements.

	Developed Acreage				Undeveloped Acreage
	Gross		Net		Gross		Net
Texas		130,541		10,908		200,232		16,436
Kansas		150		8		17,772		888
Other		8,281		1,086		1,701		674
		138,972		12,002		219,705		17,998

	Leasehold
	Costs
Balance December 31, 2011	$	475
Property additions		810
Property sale		(100	)
Impairments		(856	)

Balance December 31, 2012	$	329