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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K
(Mark One)
þANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
     X    
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Yearfiscal year ended December 31, 20162017

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

For the transition period from ___ to ___.

Commission File Numberfile number: 1-7908
ADAMS RESOURCES & ENERGY, INC.
(Exact name of registrantRegistrant as specifiedSpecified in its charter)Its Charter)
Delaware
DELAWARE74-175314717 South Briar Hollow Lane  Suite 10077027
Houston, Texas
(State or Other Jurisdiction of Incorporation)
Incorporation or Organization)
(I.R.S. Employer Identification No.)
17 SOUTH BRIAR HOLLOW LANE, SUITE 100, HOUSTON, TEXAS 77027
(Address of Principal executive offices)Executive Offices) (Zip Code)
(713) 881-3600
(ZipRegistrant’s Telephone Number, Including Area Code)

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

Title of each classEach ClassName of each exchange on which registeredEach Exchange On Which Registered
Common Stock, $.10$0.10 Par ValueNYSE MKT

Securities to be registered pursuant to Section 12(g) of the Act: None.

Indicate by check mark whetherif the Registrantregistrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES ___NO   Yes    X__oNo

þ
Indicate by check mark whetherif the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. YES ____ NO  Yes       Xo No þ

Indicate by check mark whether the Registrantregistrant (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 thesuch filing requirements for the past 90 days. YES   Yes X þ   NO ___ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site,Website, 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). Yesþ No o
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__þ

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, or an emerging growth company. See definitiondefinitions of ‟large“large accelerated filer”, ‟accelerated filer”filer,” “accelerated filer,” “smaller reporting company” and ‟smaller reporting“emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ____o Accelerated filer    Xþ

Non-accelerated filer ____o Smaller reporting company _____o Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined byin Rule 12b-2 of the Exchange Act). Yes oNo þ
YES ___NO      X

The aggregate market value of the company’s voting and non-voting common equityshares held by non-affiliates as of the close of business on June 30, 20162017 was $85,082,805$88,123,994 based on the closing price of $38.50$41.08 per one share of common stock as reported on the NYSE MKT for such date. A total ofThere were 4,217,596 shares of Common Stock were outstanding at March 1, 2017.2018.

DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held May 3, 20178, 2018 are incorporated by reference into Part III of this report.

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ADAMS RESOURCES & ENERGY, INC.
PART ITABLE OF CONTENTS

Forward-Looking Statements –Safe Harbor Provisions
Page
Number
PART I
Item 1 and 2.
Business and Properties.
3
Item 1A.
Risk Factors.
9
Item 1B.
Unresolved Staff Comments.
14
Item 3.
Legal Proceedings.
15
Item 4.
Mine Safety Disclosures.
15
PART II
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
15
Item 6.
Selected Financial Data.
17
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
19
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.
33
Item 8.
Financial Statements and Supplementary Data.
34
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
70
Item 9A.
Controls and Procedures.
70
Item 9B.
Other Information.
72
PART III
Item 10.
Directors, Executive Officers and Corporate Governance.
72
Item 11.
Executive Compensation.
72
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
72
Item 13.
Certain Relationships and Related Transactions, and Director Independence.
73
Item 14.
Principal Accountant Fees and Services.
73
PART IV
Item 15.
Exhibits, Financial Statement Schedules.
73
Item 16.
Form 10-K Summary.
74
Signatures
75










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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This annual report on Form 10-K for the year ended December 31, 20162017 (our “annual report”) contains certainvarious forward-looking statements coveredand information that are based on our beliefs, as well as assumptions made by the safe harbors provided under federal securities lawus and regulations.  To the extentinformation currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “would,” “will,” “believe,” “may,” “potential” and similar expressions and statements regarding our plans and objectives for future operations are not recitations of historical fact,intended to identify forward-looking statements. Although we believe that our expectations reflected in 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) Outlook, (e) Critical Accounting Policies and Use of Estimates, (f) Quantitative and Qualitative Disclosures about Market Risk, (g) Income Taxes, (h) Concentration of Credit Risk, (i) Price Risk Management Activities, and (j) 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 aare reasonable, basis in fact.  However, there can be no assurancewe cannot give any assurances that such expectationexpectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions as described in more detail under Part I, Item 1A of this annual report. If one or belief will actually resultmore of these risks or be achieved.

With the uncertainties of forward looking statements in mind, the reader should consider the risks discussed elsewhere in this report and other documents filed by the Company with the Securities and Exchange Commission (the ‟SEC”) from time to time and the important factors described under ‟Item 1A. Risk Factors” that could causematerialize, or if underlying assumptions prove incorrect, our actual results to differmay vary materially from those expressed inanticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statement made by or on behalfstatements. The forward-looking statements in this annual report speak only as of the Company.date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.

PART I

Items 1 and 2. BUSINESS AND PROPERTIES

Business and Properties.
Business Activities
General

Adams Resources & Energy, Inc. (‟(“AE”), is a publicly traded Delaware corporation organized in 1973, the common shares of which are listed on the NYSE MKT LLC (“NYSE MKT”) under the ticker symbol “AE”. We and itsour subsidiaries (collectively, the ‟Company”), are primarily engaged in the business of crude oil marketing, transportation and storage in various crude oil and natural gas basins in the lower 48 states of the United States (“U.S.”). We also conduct tank truck transportation of liquid chemicals and dry bulk and oilISO tank container storage and gas explorationtransportation primarily in the lower 48 states of the U.S. with deliveries into Canada and production.    The Company’sMexico, and with terminals in the Gulf Coast region of the U.S. Our headquarters are located in 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,Unless the context requires otherwise, references to “we,” “us,” “our,” the “Company” or “AE” are intended to mean the business and operations of Adams Resources & Energy, Inc. and its consolidated subsidiaries.

Historically, we have operated and reported in three business segments: (i) crude oil marketing, transportation and storage, (ii) tank truck transportation of liquid chemicals and dry bulk and ISO tank container storage and transportation, and (iii) upstream crude oil and natural gas exploration and production. We exited the upstream crude oil and natural gas exploration and production business during 2017 with the sale of our upstream crude oil and natural gas exploration and production assets.

For detailed financial information regarding our business segments, see Note 8 in the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

2017 Developments

Subsidiary Bankruptcy, Deconsolidation and Sale

On April 21, 2017, one of our wholly owned subsidiaries, Adams Resources Exploration Corporation (“AREC”), filed a voluntary petition in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”) seeking relief under Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code”), Case No. 17-10866 (KG). AREC operated its business and managed its properties as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and order of the Bankruptcy Court. AE was the primary creditor in the Chapter 11 process.

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During the second quarter of 2017, we recorded a non-cash charge of approximately $1.6 million associated with the deconsolidation of AREC, which reflected the excess of the net assets of AREC over its estimated fair value based on an expected sales transaction price of approximately $5.0 million, net of estimated transaction costs. During the third quarter of 2017, Bankruptcy Court approval was obtained on three asset purchase and sales agreements with three unaffiliated parties, and AREC closed on the sales of substantially all of its assets.

In October 2017, AREC submitted its liquidation plan to the Bankruptcy Court for approval. In connection with the sales of these assets and submission of the liquidation plan, we recognized an additional loss of $1.9 million during the third quarter of 2017, which represents the difference between the proceeds we expect to be paid upon settlement of the bankruptcy, net of anticipated remaining closing costs identified as part of the liquidation plan, and the book value of our cost method investment. In December 2017, we received proceeds of approximately $2.8 million from AREC related to the settlement of a portion of the bankruptcy process. We obtained approval of a confirmed plan in December 2017, and we expect the case to be dismissed during the first half of 2018. We anticipate receiving an additional $0.4 million in 2018 when the bankruptcy case is dismissed.

In connection with the bankruptcy filing, AREC entered into a Debtor in Possession Credit and Security Agreement (“DIP Credit Agreement”) with AE dated as of April 25, 2017, in an aggregate amount of up to $1.25 million. AREC borrowed approximately $0.4 million under the DIP Credit Agreement, and the amount was repaid during the third quarter of 2017 with proceeds from the sales of the assets. See Note 3 in the Notes to Consolidated Financial Statements for further information.

Voluntary Early Retirement Program

In August 2017, we implemented a voluntary early retirement program for certain employees, which resulted in an increase in personnel expenses of approximately $1.4 million. Of this amount, approximately $1.0 million was included in general and administrative expenses and $0.4 million was included in operating expenses.

Impairment of Investment in Unconsolidated Affiliate

During the third quarter of 2017, we completed a review of our investment in VestaCare, Inc. (“VestaCare”) and determined that there was an other than temporary impairment as the current projected operating results and identifiable assets of each industry segment forVestaCare did not support the three years ended December 31, 2016 are set forthcarrying value of our investment. As such, we recognized a pre-tax impairment charge of $2.5 million during the third quarter of 2017 related to our investment in VestaCare. See Note (8)7 in the Notes to the Consolidated Financial Statements.Statements for further information.
Business Segments

Marketing Segment Subsidiary

Our marketing segment consists of the operations of our wholly owned subsidiary, Gulfmark Energy, Inc. (‟(“Gulfmark”), a subsidiary. Our crude oil marketing activities generate revenue from the sale and delivery of AE, purchasescrude oil purchased either directly from producers or from others on the open market. We purchase crude oil and arrangesarrange sales and deliveries to refiners and other customers. Activity is concentratedcustomers, primarily onshore in Texas, Oklahoma, North Dakota, Michigan and Louisiana. Gulfmark operates 156Our marketing activities includes a fleet of approximately 144 tractor-trailer rigs, the majority of which we own and maintainsoperate, used to transport crude oil. We also maintain over 120164 pipeline inventory locations or injection stations. Gulfmark hasWe have the ability to barge crude oil from four crude oil storage facilities along the intercoastal waterwayIntercoastal Waterway of Texas and Louisiana, and maintainswe maintain approximately 425,000 barrels of storage capacity at the dock facilities in order to access waterborne markets for itsour products. During 2016, Gulfmark purchased approximately 72,900 barrels per day


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The following table shows the age of our owned and leased tractors and trailers within our marketing segment at December 31, 2017:
 
Tractors (1)
 Trailers
    
Model Year:   
201816
 —
20174
 —
201519
 3
201439
 23
201359
 41
20127
 14
2011—
 75
2008 and earlier—
 45
Total144
 201
____________________
(1)Includes 15 tractors that we lease from a third party under a capital lease agreement. See Note 13 in the Notes to Consolidated Financial Statements for further information.

We purchase crude oil at the field (wellhead) level. Gulfmark deliversVolume and price information were as follows for the periods indicated:
 Year Ended December 31,
 2017 2016 2015
Field level purchase volumes – per day (1)
     
Crude oil – barrels67,447
 72,900
 106,400
      
Average purchase price     
Crude oil – per barrel$49.88 $39.30 $45.41
____________________
(1)Reflects the volume purchased from third parties at the field level of operations.

Field level purchase volumes depict our day-to-day operations of acquiring crude oil at the wellhead, transporting crude oil, and delivering it to market sales points. We held crude oil inventory at a weighted average composite price as follows at the dates indicated (in barrels):
 December 31,
 2017 2016 2015
   Average   Average   Average
 Barrels Price Barrels Price Barrels Price
            
Crude oil inventory198,011
 $61.57 255,146
 $51.22 261,718
 $29.31

We deliver physical supplies to refinerrefinery customers or entersenter into commodity exchange transactions from time to time to protect from a decline in inventory valuation. During 2016, Gulfmarkthe year ended December 31, 2017, we had sales to four customers that comprised 18.222.8 percent, 16.517.1 percent, 15.910.8 percent and 10.610.7 percent, respectively, of total Company wideconsolidated revenues. Management believesWe believe alternative market outlets for itsour commodity sales are readily available and a loss of any of these customers would not have a material adverse effect on the Company’sour operations. See discussion under ‟Concentration of Credit Risk”Note 14 in Note (3)the Notes to Consolidated Financial Statements.Statements for further information regarding credit risk.


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Operating results for theour marketing segment are sensitive to a number of factors. SuchThese 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

Our transportation segment consists of the operations of our wholly owned subsidiary, Service Transport Company (‟(“STC”), a subsidiary of AE,. STC transports liquid chemicals and, to a lesser extent, dry bulk on a ‟for“for hire” basis throughout the continental United StatesU.S., Canada and Canada.into Mexico. STC also provides ISO tank container storage and transportation for customers. Transportation service isservices are provided to over 400 customers under multiple load contracts in addition to loads covered under STC’s standard price list.
The following table shows the age of our owned and leased tractors and trailers within our transportation segment at December 31, 2017:
 
Tractors (1)
 Trailers
    
Model Year:   
201630
 52
201538
 30
20141
 35
2013102
 —
201270
 30
20113
 —
2008 and earlier—
 384
Total244
 531
____________________
(1)Excludes 35 independent contractor tractors.

Miles traveled was as follows for the periods indicated (in thousands):
 Year Ended December 31,
 2017 2016 2015
      
Mileage21,835
 22,611
 25,205

STC operates 308 truck tractors of which 259 are Company owned with 49 independent owner-operator units.  The Company also owns and operates 558 tank trailers.  In addition, STC operates truck terminals in Houston, Corpus Christi, and Nederland, Texas, as well asand Baton Rouge (St. Gabriel), Louisiana, St. Rose, Louisiana and Mobile (Saraland), Alabama. Transportation operations are headquartered at a terminal facility situated on 26.5 Company-owned acres that we own 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 that we own and includes an office building, maintenance bays and tank cleaning facilities. Pursuant to regulatory requirements, STC holds a Hazardous Materials Certificate of Registration issued by the United StatesU.S. Department of Transportation (‟(“DOT”).

STC is a recognized certified partner with the American Chemistry Council’s Responsible Care Management System;System (“RCMS”); the scope of this RCMS certification 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.   The American Chemistry Responsible Care Partners©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 AE, is in the exploration and development of domestic oil and natural gas properties primarily in the Permian Basin of West Texas and the Haynesville Shale. AREC’s offices are maintained in Houston and the Company holds an interest in 470 producing wells of which 6 are Company operated.  The Company is currently considering strategic alternatives related to the oil and gas exploration and development subsidiary.

Producing Wells--The following table sets forth the Company’s gross and net productive wells as of December 31, 2016. 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 WellsGas WellsTotal Wells
 GrossNetGrossNetGrossNet
Permian Basin1783.15551.092334.24
Haynesville Shale--922.46922.46
Other952.20504.601456.80
 2735.351978.1547013.50

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Drilling Activity--The following table sets forth the Company’s drilling activity for each of the three years ended December 31, 2016.  All drilling activity was onshoreInvestments in Texas, Louisiana, Arkansas, North Dakota, Wyoming and Kansas.Unconsolidated Affiliates

 201620152014
 GrossNetGrossNetGrossNet
Exploratory wells drilled      
- Productive------
- Dry--1.104.40
Development wells drilled      
- Productive7.1313.1646.83
- Dry----3.43
 7.1314.26531.66

Production and Reserve Information--The Company’s estimated net quantities of proved oil and natural gas reserves, estimated 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, 2016, are presented in the table below (in thousands):

  As of December 31, 
  2016  2015  2014 
Crude oil (thousands of barrels)  187   226   318 
Natural gas (thousands of mcf)  4,214   4,835   5,611 
Future net cash flows before income taxes $5,479  $8,413  $41,396 
Standardized measure of oil and gas reserves $2,260  $3,527  $15,744 

The estimated value of oil and natural gas reserves and future net revenues derived therefrom are highly dependent upon oil and gas commodity price assumptions.  In such estimates, the Company’s independent petroleum engineers assumed market prices as presented in the table below (in thousands):

  2016  2015  2014 
Assumed market price         
Crude oil per barrel $38.34  $45.83  $89.60 
Natural gas per thousand cubic feet (mcf) $2.56  $2.62  $5.42 

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 prices reported in the reserve disclosures for natural gas 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.
4
The Company’s net oil and natural gas production for the three years ended December 31, 2016 was as follows:

Years EndedCrude OilNaturalCrude Oil Equivalent
December 31,(barrels)Gas (mcf)Per day (barrels)
201676,700662,000511
201599,500889,000678
2014127,3001,133,000865

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, 
  2016  2015  2014 
Average oil and condensate         
sales price per barrel(1)
 $24.95  $28.94  $63.64 
Average natural gas            
sales price per mcf $2.26  $2.46  $4.65 
Average production cost, per equivalent            
barrel, charged to expense $18.70  $24.64  $21.42 

(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 $2.2 million cash payment.  Bencap provides medical insurance brokerage and medical claims auditing services to employers utilizing ERISA governed employee benefit plans.  The Company has accounted for this investment under the equity method of accounting.

During the third quarter of 2016, the Company completed a review of its equity method investment in Bencap and determined there was an other than temporary impairment.  Underlying this decision are the terms of the investment agreement where Bencap has the option to request borrowings up to $1.5 million (on or after December 5, 2016 but before October 31, 2018) that the Company must provide or forfeit its 30% member interest.  During the third quarter of 2016, management of the Company determined that it was unlikely to provide additional funding due to Bencap’s lower than projected revenue growth and operating losses since investment inception.  As a result, the Company recognized a net loss of $1.4 million from its investment in Bencap as of September 30, 2016.  This loss included a pre-tax impairment charge of $1.7 million and pre-tax losses from the equity method investment of $0.5 million. In February 2017, Bencap requested additional funding of approximately $0.5 million and the Company declined the additional funding request.

In April 2016 the Company, through its ARMM subsidiary, acquiredWe own an approximate 15%15 percent equity interest (less than 3%3 percent voting interest) in VestaCare, Inc., a California corporation (“VestaCare”), through Adams Resources Medical Management, Inc. (“ARMM”), a wholly owned subsidiary. We acquired our interest in VestaCare in April 2016 for a $2.5 million cash payment.payment, which we impaired during the third quarter of 2017. VestaCare provides an array of software as a service (“SaaS”)(SaaS) electronic payment technologies to medical providers, payers and patients including VestaCare’s most recent product offering, VestaPay™. VestaPay™ allows medical care providers to structure fully automated and dynamically updating electronic payment plans for their patients. The Company doesWe do not currently have any plans to pursue additional medical-related investments.


5
See Note 7 in the Notes to Consolidated Financial Statements for further information.

Environmental ComplianceCompetition

In all phases of our operations, we encounter strong competition from a number of entities. Many of these competitors possess financial resources substantially in excess of ours. We face competition principally in establishing trade credit, pricing of available materials and Regulationquality of service. Our marketing division competes with major crude oil companies and other large industrial concerns that own or control significant refining, midstream and marketing facilities. These major crude oil companies may offer their products to others on more favorable terms than those available to us.

The CompanySeasonality

In the trucking industry, revenue has historically followed a seasonal pattern for various commodities and customer businesses. Peak freight demand has historically occurred in the months of September, October and November. After the December holiday season and during the remaining winter months, freight volumes are typically lower as many customers reduce shipment levels. Operating expenses have historically been higher in the winter months primarily due to decreased fuel efficiency, increased cold weather-related maintenance costs of revenue equipment, and increased insurance claim costs attributable to adverse winter weather conditions. Revenue can also be impacted by weather, holidays and the number of business days that occur during a given period, as revenue is directly related to the available working days of shippers.

Although our marketing business is not materially affected by seasonality, certain aspects of our operations are impacted by seasonal changes, such as tropical weather conditions, energy demand in connection with heating and cooling requirements and the summer driving season.


Regulatory Matters

We are subject to an extensive variety of evolving 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 belowBelow is a non-exclusive listing of the environmental laws that potentially impact the Company’sour 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”),The Clean Water Act of 1972, as amended.
-The Clean Water Act of 1972,The Clean Air Act of 1970, as amended.
-Federal Oil Pollution Act of 1990,The Toxic Substances Control Act of 1976, as amended.
-The Clean Air Act of 1970, as amended.
The Emergency Planning and Community Right-to-Know Act.
-The Toxic Substances Control Act of 1976,The Occupational Safety and Health Act of 1970, as amended.
-The Emergency Planning and Community Right-to-KnowTexas Clean Air Act.
-The Occupational Safety and Health Act of 1970, as amended.
Texas Solid Waste Disposal Act.
-Texas Clean Air Act.
Texas Water Code.
-Texas Solid Waste Disposal Act.
Texas Oil Spill Prevention and Response Act of 1991, as amended.
-Texas Water Code.

-Texas Oil Spill Prevention and Response Act of 1991, as amended.
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Railroad Commission of Texas (‟(“RRC”)--The

The RRC regulates, among other things, the drilling and operation of crude oil and natural gas wells, the operation of crude oil and natural gas pipelines, the disposal of crude oil and natural gas production wastes, and certain storage of unrefinedcrude oil and natural gas. RRC regulations govern the generation, management and disposal of waste from suchthese crude oil and natural gas operations and provide for the clean upcleanup of contamination from crude oil and natural gas operations.

Louisiana Office of Conservation--This agency

The Louisiana Office of Conservation has primary statutory responsibility for regulation and conservation of crude oil, natural gas, and other natural resources in the State of Louisiana. Their objectives are to (i) regulate the exploration and production of crude 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

Many states are authorized by the United StatesU.S. 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.

Trucking Activities

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.
6

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’sOur marketing and transportation businesses operate truck fleets pursuant to the 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 by 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’sour tank wash facilities are subject to increasingly stringent local, state and federal environmental regulations.

The Company hasWe have implemented security procedures for drivers and terminal facilities. Satellite tracking transponders installed in the power units are used to communicate emergencies to the Companyus and to maintain constant information as to the unit’s location. If necessary, the Company’sour terminal personnel will notify local law enforcement agencies. In addition, the Company iswe are able to advise a customer of the status and location of their loads. Remote cameras and betterenhanced lighting coverage in the staging and parking areas have augmented terminal security. We have a focus on safety in the communities in which we operate, including leveraging camera technology to enhance driver behavior and awareness.


Regulatory Status and Potential Environmental Liability--The

Our 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 regardsWe regard compliance with applicable environmental regulations as a critical component of itsour overall operation, and devotesdevote significant attention to providing quality service and products to itsour customers, protecting the health and safety of itsour employees, and protecting the Company’sour facilities from damage. Management believes the Company hasWe believe we have obtained or applied for all permits and approvals required under existing environmental laws and regulations to operate itsour current business. Management has reported that the Company isWe are not subject to any pending or threatened environmental litigation or enforcement actions which could materially and adversely affect the Company’sour business.  The Company has,

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We have, where appropriate, implemented operating procedures at each of itsour facilities designed to assure compliance with environmental laws and regulation. However, given the nature of the Company’sour business, the Company iswe are subject to environmental risks, and the possibility remains that the Company’sour ownership of itsour facilities and itsour operations and activities could result in civil or criminal enforcement and public as well as private actions against the Company,us, which may necessitate or generate mandatory clean upcleanup 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.us. See “Item 1A. Risk Factors – Environmental liabilities and environmental regulations may have an adverse effect on the Company.” for further discussion. At December 31, 2016, the Company is unaware2017, we are not aware of any unresolved environmental issues for which additional accounting accruals are necessary.

Employees

At December 31, 2016, the Company2017, we employed 645575 persons. None of the Company’sour employees are represented by a union. Management believes itsWe believe our employee relations are satisfactory.
7

Federal and State Taxation

The Company isWe are subject to the provisions of the Internal Revenue Code of 1986, as amended (the ‟Code”“Code”). In accordance with the Code, the Company computes itswe computed our income tax provision based on a 35 percent tax rate.  The Company’s operations are,rate for the year ended December 31, 2017. On December 22, 2017, the Tax Cut and Jobs Act was enacted into law resulting in large part, conducteda reduction in the federal corporate income tax rate from 35 percent to 21 percent for years beginning in 2018. We conduct a significant amount of business 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 activitiesWe believe we 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 toWe electronically file periodic reports as well as other informationcertain documents with the SEC within established deadlines.  Any document filedU.S. Securities and Exchange Commission (“SEC”). We file annual reports on Form 10-K; quarterly reports on Form 10-Q; and current reports on Form 8-K (as appropriate); along with any related amendments and supplements thereto. You may read and copy any material we file 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. AdditionalYou may obtain information regarding the Public Reference Room can be obtained by calling the SEC at (800) SEC-0330. The Company’sIn addition, the 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.comwww.sec.gov, on which investors may access that contains reports and other information regarding registrants that file electronically with the SEC.

We also make available free of charge the annual reportour Annual Reports on Form 10-K, quarterly reportsQuarterly Reports on Form 10-Q, current reportsCurrent Reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, simultaneously with or as soon as is reasonably practicable after filing such materials with, 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 amendmentmaterials to, the Code of Business Ethics will be posted promptlySEC, and on the Company’s website.our website www.adamsresources.com. The information contained on our website, or accessible from the Company’sinformation about us on any other website, does not constitute a part of this report and is not incorporated by reference herein.  The Company will provide a printed copy ofinto this report.


Item 1A. Risk Factors.

An investment in our common stock involves certain risks.  If any of these aforementioned documents free of charge upon request by calling AE at (713) 881-3600 or by writing to:


Adams Resources & Energy, Inc.
ATTN:  Josh C. Anders
17 South Briar Hollow Lane, Suite 100
Houston, Texas 77027

Item 1A. RISK FACTORS

Fluctuations in oil and gas pricesthe following key risks were to occur, it could have ana material adverse effect on the Company.

The Company’s futureour financial condition, revenues,position, results of operations and future ratecash flows.  In any such circumstance and others described below, the trading price of growth are materially affected by oilour securities could decline and natural gas prices that historically have been volatile and are likely to continue to be volatile in the future.  Crude oil and natural gas prices depend on factors outside the controlyou could lose part or all of the Company.  These factors include:your investment.

·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.


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Economic developments could damage our operations and materially reduce our 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. SuchThese factors could contribute to a decline in the Company’sour stock price and corresponding market capitalization. ShouldIf commodity prices experience a period of rapid decline, or a prolonged period of low commodity prices, our future earnings will be reduced. Since the CompanyWe currently has neitherdo not have 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.  Shouldobligations. If the capital and credit markets experience volatility and the availability of funds become limited, the Company’sour 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’sour ability to secure supply and make profitable sales.

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

Customer demand for the Company’sour products and services is substantially dependent upon the general economic conditions for the United StatesU.S., 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’sour 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’sOur business is dependent on the ability to obtain trade and other credit.

The Company’sOur future development and growth depends, in part, on itsour 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. ShouldIf 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 Companyus, our suppliers and its suppliers andour customers to obtain funding. If the Company iswe are unable to obtain trade or other forms of credit on reasonable and competitive terms, the ability to continue itsour marketing and exploration businesses, pursue improvements, and continue future growth will be limited. There is no assuranceWe cannot assure you that the Companywe will be able to maintain future credit arrangements on commercially reasonable terms.

Fluctuations in crude oil and natural gas prices could have an adverse effect on us.

Our future financial condition, revenues, results of operations and future rate of growth are materially affected by crude oil and natural gas prices that historically have been volatile and are likely to continue to be volatile in the future. Crude oil and natural gas prices depend on factors outside of our control. These factors include:

supply and demand for crude oil and natural gas and expectations regarding supply and demand;
political conditions in other crude oil-producing countries, including the possibility of insurgency or war in such areas;
economic conditions in the U.S. 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.

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The financial soundness of customers could affect the Company’sour business and operating resultsresults.

Constraints in the financial markets and other macro-economic challenges that might affect the economy of the United StatesU.S. and other parts of the world could cause the Company’sour customers to experience cash flow concerns. As a result, if our 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.us. Any inability of current and/or potential customers to pay for services may adversely affect the Company’sour financial condition and results of operations.

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

The Company’sOur revenues are generated under contracts with various counterparties, and our 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’sour 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 suchthe counterparty. The Company seeksWe seek 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.
9

Potentially escalating diesel fuel prices could have an adverse effect on the Company.us.

As an integral part of the Company’sour marketing and transportation businesses, the Company operateswe operate approximately 415390 truck-tractors, and diesel fuel costs are a significant component of our operating expense.  Suchexpenses. These costs generally fluctuate with increasing and decreasing world crude oil prices. During periods of high prices, the Company attemptswe attempt to recoup rising diesel fuel costs through the pricing of itsour services; however to the extent suchthese costs escalate, our operating earnings will generally be adversely affected.

Revenues are generated under contracts that must be renegotiated periodically.

Substantially all of the Company’sour 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’sour control. SuchThese factors include sudden fluctuations in crude oil and natural 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 assurancewe offer. We cannot assure you that the costs and pricing of the Company’sour services can remain competitive in the marketplace or that the Companywe will be successful in renegotiating itsour contracts.

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

The Company’sOur crude oil marketing operationbusiness purchases initial production of crude oil at the wellhead under contracts requiring the Companyus to accept the actual volume produced. The resale of suchthis production is generally under contracts requiring a fixed volume to be delivered. The Company estimates itsWe estimate our anticipated supply and matches suchmatch that supply estimate for both volume and pricing formulas with committed sales volumes. Since actual wellhead volumes produced will never equal anticipated supply, the Company’sour 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.us.

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

The Company’sOur 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 Companyus to material liabilities for property damage, personal injuries, and/or environmental harms, including the costs of investigating and rectifying contaminated properties.


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Environmental laws and regulations govern many aspects of the Company’sour 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 Companyus to significant administrative, civil, and/or criminal fines and/or penalties.penalties, as well as potential injunctive relief. See discussion under Item 1 and 2. Business and Properties —Regulatory Matters, and in the sections that follow, for additional detail.


OperationsOur 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 Companyus to liability. The payment of any of these liabilities could reduce, or even eliminate, the funds available for other areas.

Consistent with the industry standard, the Company’sour 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. Obtaining insurance for the Company’sour line of business can become difficult and costly. Typically, when insurance cost escalates, the Companywe may reduce itsour 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’sour operation and financial condition could be materially adversely affected.
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ChangesWe could be adversely affected by changes in tax laws or regulations could adversely affect the Company.

The Internal Revenue Service, the United StatesU.S. Treasury Department, Congress and the states frequently review federal or state income tax legislation. The CompanyWe 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 us.

The Tax Cuts and Jobs Act, signed into law on December 22, 2017, is expected to have a favorable impact on our effective tax rate and net income as reported under generally accepted accounting principles in the Company.U.S. both in the first fiscal quarter of 2018 and subsequent reporting periods to which the Tax Cuts and Jobs Act is effective. However, given the many changes resulting from the Tax Cuts and Jobs Act, we are assessing the impact of the Tax Cuts and Jobs Act, and there can be no assurances that it will have a favorable impact. You should consult with your tax advisors with respect to the effect of the Tax Cuts and Jobs Act and any other regulatory or administrative developments and proposals and the potential effect on your investment in AE.


The Company’sOur 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’sOur 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 crude 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.

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

Exploration, drilling and completion may not result in any increases in reserves for various reasons.  Exploration, drilling and completion may be curtailed, delayed or cancelled as a result of:

·lack of favorable economics due to price volatility
·lack of acceptable prospective acreage;
·inadequate capital resources;
·weather;
·title problems;
·compliance with governmental regulations; and
·mechanical difficulties.

Oil and gas segment operations project costs 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.
11

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

The Company transportsWe transport liquid combustible materials including petrochemicals, and suchthese materials may be a target for terrorist attacks. While the Company employswe employ a variety of security measures to mitigate risks, no assurance can be givenwe cannot assure you that such events will not occur.


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

The Company isWe are currently involved in certain administrative and civil legal proceedings as part of the ordinary course of itsour business. Moreover, as incidental to operations, the Companywe sometimes becomesbecome 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 we maintain insurance is maintained to mitigate these costs, there can be no assurancewe cannot assure you that costs associated with lawsuits or other legal proceedings will not exceed the limits of insurance policies. The Company’sOur results of operations could be adversely affected if a judgment, penalty or fine is not fully covered by insurance.

The Company is subjectClimate change legislation or regulations restricting emissions of “greenhouse gases” (“GHGs”) could result in increased operating costs and reduced demand for the crude oil and natural gas we produce, market and transport.

More stringent laws and regulations relating to risks associated with climate change.
Potential climate change and effortsGHGs may be adopted and could cause us to incur material expenses to comply with such laws and regulations. In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions; although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. The EPA also requires the reporting of GHG emissions from specified large GHG emission sources including onshore and offshore crude oil and natural gas production facilities and onshore crude oil and natural gas processing, transmission, storage and distribution facilities. Reporting of GHG emissions from such large facilities is required on an annual basis. We do not presently operate any such large GHG emission sources but, if we were to do so in the future, we would incur costs associated with evaluating and meeting this reporting obligation.

In May 2016, the EPA finalized rules to reduce methane emissions from new, modified or reconstructed sources in the crude oil and natural gas sector, although the rules are currently the subject of litigation and in June 2017, the EPA proposed a 2-year stay of the rules. The EPA announced in March 2016 that it also intends to reduce methane emissions for existing sources, but the EPA announced in March 2017 that it no longer intends to pursue regulation of methane emissions from existing sources. In November 2016, the Bureau of Land Management issued final rules to reduce methane emissions from venting, flaring, and leaks during crude oil and natural gas operations on public lands, although the present administration is proposing to delay the implementation dates applicable to requirements under these rules. Several states, are pursuing similar measures to regulate ‟greenhouse gas” (‟GHG”) emissions of methane from new and existing sources within the crude oil and natural gas source category.

In addition, the U.S. Congress has considered legislation to reduce emissions of GHGs, and many states and regions have already taken legal measures to reduce or measure GHG emission levels, often involving the potentialplanned development of GHG emission inventories and/or regional cap and trade programs. Most of these cap and trade programs require major sources of emissions or major producers of fuels to adversely affectacquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to reduce overall GHG emissions, and the Company’s business including negatively impactingcost of these allowances could escalate significantly over time. In the markets in which we currently operate, our operations are not affected by such GHG cap and trade programs. On an international level, almost 200 nations agreed in December 2015 to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets. Although the present administration has announced its intention to withdraw from the Paris accord, several states and local governments remain committed to its principles in their effectuation of policy and regulations. It is not possible at this time to predict how or when the U.S. might impose restrictions on GHGs as a result of the international climate change agreement. The adoption and implementation of any legislation or regulatory programs imposing GHG reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs it incurs in providing its products and services,to reduce emissions of GHGs associated with our operations including costs to operate and maintain itsour facilities, install new emission controls on itsour facilities, acquire allowances to authorize itsour GHG emissions, pay any taxes related to GHG emissions, administer and manage a GHG emissions program, pay higher insurance premiumsprogram. Such programs also could adversely affect demand for the crude oil and natural gas that we market and transport.


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We are subject to risks associated with climate change.
In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our operations have the potential to be adversely affected. Potential adverse effects could include disruption of our marketing and transportation activities, including, for example, damages to our facilities from powerful winds or accept greater riskfloods, or increases in our costs of loss in areas affected by adverse weather and coastal regionsoperation or reductions in the eventefficiency of rising sea levels.our operations, as well as potentially increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process related services provided by companies or suppliers with whom we have a business relationship. In addition, the demand for and consumption of itsour products and services (due to change in both costs and weather patterns), and the economic health of the regions in which the Company operates,we operate, could have a material adverse effect on the Company’sour business, financial condition, results of operations and cash flows. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.
The Company is subject
Cyber-attacks or other disruptions to risks relatedour information technology systems could lead to cybersecurity.reduced revenue, increased costs, liability claims, fines or harm to our competitive position.

The Company isWe are subject to cybersecurity risks and may incur increasing costs in connection with itsour efforts to enhance and ensure security and in response to actual or attempted cybersecurity attacks. Substantial aspects of the Company’sour business depend on the secure operation of itsour computer systems and websites. Security breaches could expose the Companyus to a risk of loss, misuse, or interruption of sensitive and critical information and functions, including itsour own proprietary information and that of itsour customers, suppliers and employees.  Such breaches could result in operational impacts, reputational harm, competitive disadvantage, litigation, regulatory enforcement actions, and liability. While the Company devoteswe devote substantial resources to maintaining adequate levels of cybersecurity, there can be no assurancewe cannot assure you that itwe will be able to prevent all of the rapidly evolving types of cyberattacks. Actual or anticipated attacks and risks may cause the Companyus to incur increasing costs for technology, personnel and services to enhance security or to respond to occurrences.

We have programs, processes and technologies in place to attempt to prevent, detect, contain, respond to and mitigate security-related threats and potential incidents. We undertake ongoing improvements to our systems, connected devices and information-sharing products in order to minimize vulnerabilities, in accordance with industry and regulatory standards; however, because the techniques used to obtain unauthorized access change frequently and can be difficult to detect and anticipating, identifying or preventing these intrusions or mitigating them if and when they occur is challenging and makes us more vulnerable to cyber-attacks than other companies not similarly situated.

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


Item 1B. UNRESOLVED STAFF COMMENTSUnresolved Staff Comments.

None.
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Item 3. LEGAL PROCEEDINGS

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 to 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.  In the LePetit Chateau Deluxe matter, the larger defendants have settled the case.  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, 2016 and 2015, the Company has accrued $0.5 million of future legal and/or settlement costs for these matters.

From time to time as incidentincidental to itsour operations, the Company becomeswe may become involved in various accidents, lawsuits and/or disputes. Primarily as an operator of an extensive trucking fleet, the Company iswe are a party to motor vehicle accidents, workerworkers’ compensation claims orand other items of general liability as arewould be typical for the industry. In addition,We are currently unaware of any claims against us that are either outside 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 applicabilityscope of insurance coverage.  Tocoverage or that may exceed the extent management believes that such event may impactlevel of insurance coverage and could potentially represent a material adverse effect on our financial position or results of operations.

See Note 13 in the financial condition of the Company, management will estimate the monetary value of the claim and make appropriate accruals or disclosures.Notes to Consolidated Financial Statements for further discussion.



Item 4. MINE SAFETY DISCLOSURESMine Safety Disclosures.

Not Applicable.applicable.

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PART II

Item 5.MARKET FOR THE REGISTRANT’S COMMON STOCK, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIESMarket for Registrant’s Common Stock, Related Stockholder Matters, and Issuer Purchases of Equity Securities.


The Company’sOur common stock is traded on the NYSE MKT under the ticker symbol ‟AE”“AE”. As of February 28, 2018, there were approximately 140 shareholders of record of our common shares. The following table sets forth thepresents high and low sales prices offor our common stock for the common stockperiods presented as reported by the NYSE MKT for each calendar quarter since January 1, 2015.

  American Stock Exchange 
  High  Low 
2016      
First Quarter $43.00  $30.00 
Second Quarter  44.27   35.25 
Third Quarter  39.47   29.64 
Fourth Quarter  44.00   35.17 
         
2015        
First Quarter $73.28  $47.31 
Second Quarter  70.00   39.00 
Third Quarter  48.60   38.88 
Fourth Quarter  46.86   33.55 

Currently,and the Company has no securities authorized for issuance under equity compensation plans.  The Company made no repurchasesamount, record date and payment date of its stock during 2016 and 2015.  Duringthe quarterly cash dividends we paid on each of March, June, September and December 2016 and 2015, respectively, the Company paidour common shares with respect to its common shareholders a quarterly cash dividendsuch periods.
     Cash Dividend History
 Price Ranges Per Record Payment
 High Low Share Date Date
2015         
1st Quarter$73.28 $47.31 $0.22 6/3/2015 6/17/2015
2nd Quarter$70.00 $39.00 $0.22 9/3/2015 9/17/2015
3rd Quarter$48.60 $38.88 $0.22 12/2/2015 12/16/2015
4th Quarter$46.86 $33.55 $0.22 3/11/2016 3/23/2016
          
2016         
1st Quarter$43.00 $30.00 $0.22 6/3/2016 6/17/2016
2nd Quarter$44.27 $35.25 $0.22 9/6/2016 9/19/2016
3rd Quarter$39.47 $29.64 $0.22 12/5/2016 12/19/2016
4th Quarter$44.00 $35.17 $0.22 3/10/2017 3/24/2017
          
2017         
1st Quarter$41.99 $34.23 $0.22 6/2/2017 6/16/2017
2nd Quarter$43.80 $35.64 $0.22 9/6/2017 9/20/2017
3rd Quarter$42.77 $32.80 $0.22 12/5/2017 12/19/2017
4th Quarter$50.59 $40.36 $0.22 3/9/2018 3/23/2018


Issuer Purchases of $.22 per common share.Equity Securities


None.


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Performance Graph

The following graph compares the total shareholder return performance of our common stock with the performance of: (i) the Standard & Poor’s 500 Stock Index (“S&P 500”) and (ii) the S&P 500 Integrated Oil and Gas Index. The graph shown belowassumes that $100 was invested in our common stock and each comparison index beginning on December 31, 2012 and that all dividends were reinvested on a quarterly basis on the ex-dividend dates. The graph 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, 2011 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.



 12/1112/1212/1312/1412/1512/16
       
Adams Resources & Energy, Inc.100.00122.77242.41179.43140.52148.54
S&P 500100.00116.00153.58174.60177.01198.18
S&P Integrated Oil & Gas100.00102.21124.21115.8599.80123.89

15
 December 31,
 2012 2013 2014 2015 2016 2017
            
Adams Resources & Energy, Inc.$100.00
 $197.45
 $146.15
 $114.46
 $120.99
 $135.74
S&P 500100.00
 132.39
 150.51
 152.59
 170.84
 208.14
S&P Integrated Oil & Gas100.00
 121.53
 113.35
 97.64
 121.21
 123.73

16

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Item 6. SELECTED FINANCIAL DATASelected Financial Data.

  SELECTED FINANCIAL DATA 
  Years Ended December 31, 
  2016  2015  2014  2013  2012 
  (In thousands, except per share data) 
Revenues:   
Marketing $1,043,775  $1,875,885  $4,050,497  $3,863,057  $3,292,948 
Transportation  52,355   63,331   68,968   68,783   67,183 
Oil and natural gas  3,410   5,063   13,361   14,129   15,954 
  $1,099,540  $1,944,279  $4,132,826  $3,945,969  $3,376,085 
Operating earnings (loss):                    
Marketing $17,045  $22,895  $20,854  $40,369  $46,145 
Transportation  (48)  3,701   4,750   5,180   10,253 
Oil and natural gas operations  (220)  (6,934)  (2,029)  518   (1,136)
Oil and natural gas property impairments  (313)  (12,082)  (8,009)  (2,631)  (4,699)
Oil and natural gas property sale (1)
  -   -   2,528   -   2,203 
General and administrative  (10,410)  (9,939)  (8,613)  (9,060)  (8,810)
   6,054   (2,359)  9,481   34,376   43,956 
Other income (expense):                    
Interest income  582   327   301   198   190 
Interest expense  (2)  (13)  (2)  (24)  (10)
Earnings (loss) from continuing operations                    
before income taxes and equity investment  6,634   (2,045)  9,780   34,550   44,136 
                     
Income tax (provision) benefit  (2,691)  770   (3,561)  (12,429)  (16,664)
                     
Earnings (loss) before equity investment                    
and discontinued operations  3,943   (1,275)  6,219   22,121   27,472 
Earnings (loss) from discontinued                    
operations, net of taxes  -   -   304   (511)  319 
Earnings (loss) from equity                    
investments, net of taxes  (1,430)  -   -   -   - 
                     
Net earnings (loss) $2,513  $(1,275) $6,523  $21,610  $27,791 
                     
Earnings (Loss) Per Share                    
From continuing operations $.94  $(.30) $1.48  $5.24  $6.51 
From discontinued operations  -   -   .07   (.12)  .08 
From equity investments  (.34)  -   -   -   - 
Basic and diluted earnings per share $.60  $(.30) $1.55  $5.12  $6.59 
                     
Dividends per common share  .88   .88  $.88  $.66  $.62 
                     
Financial Position                    
Cash $87,342  $91,877  $80,184  $60,733  $47,239 
Net working capital  106,444   96,340   82,342   79,561   58,474 
Total assets  246,872   243,215   340,814   448,082   419,501 
Long-term debt  -   -   -   -   - 
Shareholders’ equity  151,312   152,510   157,497   154,685   135,858 
Dividends on common shares  3,711   3,712   3,711   2,783   2,615 

Notes:The following table presents our selected historical consolidated financial data. This information has been derived from and should be read in conjunction with our audited financial statements included under Part II, Item 8 of this annual report, which presents our audited balance sheets as of December 31, 2017 and 2016 and related consolidated statements of operations, cash flows and shareholders’ equity for the three years ended December 31, 2017, 2016 and 2015, respectively. As presented in the table, amounts are in thousands (except per share data).
 Year Ended December 31,
 2017 2016 2015 2014 2013
Statements of operations data:         
Revenues:         
Marketing$1,267,275
 $1,043,775
 $1,875,885
 $4,050,497
 $3,863,057
Transportation53,358
 52,355
 63,331
 68,968
 68,783
Oil and natural gas1,427
 3,410
 5,063
 13,361
 14,129
Total revenues1,322,060
 1,099,540
 1,944,279
 4,132,826
 3,945,969
          
Costs and expenses:         
Marketing1,247,763
 1,016,733
 1,841,893
 4,020,017
 3,815,006
Transportation48,538
 45,154
 52,076
 56,802
 56,504
Oil and natural gas948
 2,084
 6,931
 7,817
 6,117
Oil and natural gas property impairments (1)
3
 313
 12,082
 8,009
 2,631
Oil and natural gas property sale (2)
—
 —
 —
 (2,528) —
General and administrative9,707
 10,410
 9,939
 8,613
 9,060
Depreciation, depletion and amortization13,599
 18,792
 23,717
 24,615
 22,275
          
Operating earnings (losses)1,502
 6,054
 (2,359) 9,481
 34,376
          
Loss on deconsolidation of subsidiary (3)
(3,505) —
 —
 —
 —
Impairment of investment in unconsolidated         
affiliate (4)
(2,500) —
 —
 —
 —
Interest income (expense)1,076
 580
 314
 299
 174
          
Earnings (losses) from continuing operations(3,427) 6,634
 (2,045) 9,780
 34,550
          
Income tax (provision) benefit2,945
 (2,691) 770
 (3,561) (12,429)
          
Earnings (losses) before investment in         
unconsolidated affiliate         
and discontinued operations(482) 3,943
 (1,275) 6,219
 22,121
          
Discontinued operations, net of taxes—
 —
 —
 304
 (511)
Losses from investment in unconsolidated         
affiliate, net of tax (5)
—
 (1,430) —
 —
 —
Net (losses) earnings$(482) $2,513
 $(1,275) $6,523
 $21,610
          
Earnings (losses) per share:         
From continuing operations$(0.11) $0.94
 $(0.30) $1.48
 $5.24
From investment in unconsolidated         
affiliate—
 (0.34) —
 —
 —
From discontinued operations—
 —
 —
 0.07
 (0.12)
Basic and diluted earnings per share$(0.11) $0.60
 $(0.30) $1.55
 $5.12
          
Dividends per common share$0.88
 $0.88
 $0.88
 $0.88
 $0.66
          

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 December 31,
 2017 2016 2015 2014 2013
Balance sheet data: 
         
Cash$109,393
 $87,342
 $91,877
 $80,184
 $60,733
Total assets282,704
 246,872
 243,215
 340,814
 448,082
Long-term debt—
 —
 —
 —
 —
Shareholders’ equity147,119
 151,312
 152,510
 157,497
 154,685
Dividends on common shares3,711
 3,711
 3,712
 3,711
 2,783
________________________
(1)InDuring 2015, we recognized an impairment of $10.3 million on producing properties, and an impairment of $1.8 million on non-producing properties.
(2)During 2014, and 2012,we sold certain crude oil and natural gas producing properties were sold for $4.1 million, and $3.6 million, producing a net gainsgain of $2.5 millionmillion.
(3)During 2017, we recognized an impairment related to the bankruptcy, deconsolidation and $2.2 million, respectively.sale of our upstream crude oil and natural gas exploration and production subsidiary.
(4)During 2017, we recognized an impairment on our medical investment in VestaCare.
(5)During 2016, we recognized losses and an impairment on our medical investment in Bencap LLC (“Bencap”). We have no other medical-related investments, and we currently do not have any plans to pursue additional medical-related investments.


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16
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSManagement’s Discussion and Analysis of Financial Condition and Results of Operations.

The following information should be read in conjunction with our Consolidated Financial Statements and accompanying notes included under Part II, Item 8 of this annual report. Our financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the United States (“U.S.”).

Overview of Business

Adams Resources & Energy, Inc. (“AE”), a Delaware corporation organized in 1973, and its subsidiaries are primarily engaged in the business of crude oil marketing, transportation and storage in various crude oil and natural gas basins in the lower 48 states of the U.S. We also conduct tank truck transportation of liquid chemicals and dry bulk and ISO tank container storage and transportation primarily in the lower 48 states of the U.S. with deliveries into Canada and Mexico, and with terminals in the Gulf Coast region of the U.S.

Historically, we have operated and reported in three business segments: (i) crude oil marketing, transportation and storage, (ii) tank truck transportation of liquid chemicals and dry bulk and ISO tank container storage and transportation, and (iii) upstream crude oil and natural gas exploration and production. We exited the upstream crude oil and natural gas exploration and production business during 2017 with the sale of our upstream crude oil and natural gas exploration and production assets.

2017 Developments

Subsidiary Bankruptcy, Deconsolidation and Sale

On April 21, 2017, one of our wholly owned subsidiaries, AREC, filed a voluntary petition in the U.S. Bankruptcy Court seeking relief under Chapter 11 of Title 11 of the Bankruptcy Code. AREC operated its business and managed its properties as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and order of the Bankruptcy Court. AE was the primary creditor in the Chapter 11 process.

During the second quarter of 2017, we recorded a non-cash charge of approximately $1.6 million associated with the deconsolidation of AREC, which reflected the excess of the net assets of AREC over its estimated fair value based on an expected sales transaction price of approximately $5.0 million, net of estimated transaction costs. During the third quarter of 2017, Bankruptcy Court approval was obtained on three asset purchase and sales agreements with three unaffiliated parties, and AREC closed on the sales of substantially all of its assets.

In October 2017, AREC submitted its liquidation plan to the Bankruptcy Court for approval. In connection with the sales of these assets and submission of the liquidation plan, we recognized an additional loss of $1.9 million during the third quarter of 2017, which represents the difference between the proceeds we expect to be paid upon settlement of the bankruptcy, net of anticipated remaining closing costs identified as part of the liquidation plan, and the book value of our cost method investment. In December 2017, we received proceeds of approximately $2.8 million from AREC related to the settlement of a portion of the bankruptcy process. We obtained approval of a confirmed plan in December 2017, and we expect the case to be dismissed during the first half of 2018. We anticipate receiving an additional $0.4 million in 2018 when the bankruptcy case is dismissed.

In connection with the bankruptcy filing, AREC entered into the DIP Credit Agreement with AE, which was repaid during the third quarter of 2017 with proceeds from the sales of the assets. See Note 3 in the Notes to Consolidated Financial Statements for further information.


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Voluntary Early Retirement Program

In August 2017, we implemented a voluntary early retirement program for certain employees, which resulted in an increase in personnel expenses of approximately $1.4 million. Of this amount, approximately $1.0 million was included in general and administrative expenses and $0.4 million was included in operating expenses.

Impairment of Investment in Unconsolidated Affiliate

During the third quarter of 2017, we completed a review of our investment in VestaCare and determined that there was an other than temporary impairment as the current projected operating results of VestaCare did not support the carrying value of our investment. As such, we recognized a pre-tax impairment charge of $2.5 million during the third quarter of 2017 related to our investment in VestaCare. See Note 7 in the Notes to Consolidated Financial Statements for further information.


Results of Operations

-  Marketing

CrudeOur crude oil marketing segment revenues, operating earnings and selected costs were as follows (infor the periods indicated (in thousands):

  2016  2015  2014 
          
Revenues $1,043,775  $1,875,885  $4,050,497 
             
Operating earnings $17,045  $22,895  $20,854 
             
Depreciation $9,997  $11,097  $9,626 
             
Driver commissions $14,933  $22,262  $21,744 
             
Insurance $7,442  $8,732  $7,446 
             
Fuel $5,397  $9,928  $14,851 

Supplemental volume
 Year Ended December 31,
 2017 2016 
Change (1)
 2015 
Change (1)
          
Revenues$1,267,275
 $1,043,775
 21.4% $1,875,885
 (44.4%)
Operating earnings11,700
 17,045
 (31.4%) 22,895
 (25.6%)
Depreciation and amortization7,812
 9,997
 (21.9%) 11,097
 (9.9%)
Driver commissions13,058
 14,933
 (12.6%) 22,262
 (32.9%)
Insurance4,509
 7,442
 (39.4%) 8,732
 (14.8%)
Fuel5,278
 5,397
 (2.2%) 9,928
 (45.6%)
____________________
(1)Represents the percentage increase (decrease) from the prior year.

Volume and price information:information were as follows for the periods indicated:
 Year Ended December 31,
 2017 2016 2015
Field level purchase volumes – per day (1)
     
Crude oil – barrels67,447
 72,900
 106,400
      
Average purchase price     
Crude oil – per barrel$49.88
 $39.30
 $45.41
____________________
(1)Reflects the volume purchased from third parties at the field level of operations.


2017 compared to 2016
  2016  2015  2014 
Field Level Purchases per day (1)
         
Crude Oil – barrels  72,900   106,400   117,100 
             
Average Purchase Price            
Crude Oil – per barrel $39.30  $45.41  $89.40 

. Crude oil marketing revenues increased by $223.5 million during the year ended December 31, 2017 as compared to 2016 primarily as a result of an increase in the market price of crude oil, which increased revenues by approximately $329.7 million, partially offset by lower crude oil volumes, which decreased revenues by approximately $106.2 million. The average crude oil price received was $39.30 for 2016, which increased to $49.88 for 2017.
(1)  Reflects

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Our marketing operating earnings for the volume purchased from third parties atyear ended December 31, 2017 decreased by $5.3 million as compared to 2016, primarily as a result of declines in crude oil volumes, including declines as a result of the field leveleffects of operations.Hurricane Harvey, which affected the Gulf Coast area in late August and early September 2017, as well as a narrowing of margins during 2017. Operating earnings were also impacted by inventory valuation changes (as shown in the table below) and the implementation in August 2017 of a voluntary early retirement program for certain employees, which resulted in an increase in personnel expenses of approximately $0.4 million. During the latter part of 2017, volumes began increasing as activity in certain marketing areas increased primarily as a result of increased wellhead purchases.

BeginningDriver commissions decreased by $1.9 million during the year ended December 31, 2017 as compared to 2016, primarily as a result of the decrease in November 2014,crude oil marketing volumes in 2017. Insurance costs decreased by $2.9 million during the year ended December 31, 2017 as compared to 2016, primarily as a result of favorable driver safety performance and reduced mileage during 2017 as compared to 2016. Fuel costs decreased by $0.1 million during the year ended December 31, 2017 as compared to 2016 consistent with decreased marketing volumes and lower crude oil prices beganduring 2016, offset by an increase in the price of diesel fuel during 2017 as compared to decline significantly2016.

2016 compared to 2015. Crude oil marketing revenues decreased by $832.1 million during the year ended December 31, 2016 as compared to 2015, primarily as a result of lower crude oil volumes, which decreased revenues by approximately $475.5 million and a decrease in the Company’smarket price of crude oil, which decreased revenues by approximately $356.6 million. The average crude oil purchase price droppedreceived was $45.41 for 2015, which decreased to $54 per barrel by December 2014 from $90 per barrel in September 2014.  Crude$39.30 for 2016. Lower crude oil prices remained low during 2015 and 2016 leading toresulted in curtailed drilling efforts in most areas. The combinationCrude marketing volumes decreased as a result of reduced prices and volumes caused revenues to fall 44 percentlower wellhead purchases in 2016 relativeas compared to 2015.

-Field Level Operating Earnings (Non GAAP Measure)


Two significant factors affecting comparative crude oilOur marketing segment operating earnings arefor the year ended December 31, 2016 decreased by $5.9 million as compared to 2015, primarily as a result of declines in crude oil volumes and a decrease in the market price of crude oil. Volume declines resulted from a decrease in wellhead purchases, partially offset by inventory valuation changes (as shown in the table below).

Driver commissions decreased by $7.3 million during the year ended December 31, 2016 as compared to 2015, primarily as a result of the decrease in crude oil marketing volumes. Insurance costs decreased by $1.3 million during the year ended December 31, 2016 as compared to 2015, primarily as a result of favorable driver safety performance during 2016 as compared to 2015. Fuel costs decreased by $4.5 million during the year ended December 31, 2016 as compared to 2015 consistent with decreased marketing volumes and lower crude oil prices during 2016 as compared to 2015.

Field Level Operating Earnings (Non-GAAP Financial Measure). Inventory valuations and forward commodity contract (derivatives or mark-to-market) valuations.valuations are two significant factors affecting comparative crude oil marketing segment operating earnings. As a purchaser and shipper of crude oil, the Company holdswe hold 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.  During periods of increasing crude oil prices, the Company recognizeswe recognize inventory liquidation gains while during periods of falling prices, the Company recognizeswe recognize inventory liquidation and valuation losses.
17

Crude oil marketing operating earnings are alsocan be affected by the valuations of the Company’sour forward month commodity contracts (derivative instruments) as of the various report dates.  Such. These non-cash valuations are calculated and recorded at each period end based on the underlying data existing as of such date. The CompanyWe generally entersenter 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 subject to fair value treatment.  The valuation of derivative instruments at period end requires the recognition of ‟mark-to-market”non-cash “mark-to-market” gains and losses.

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The impact on crude oil segment operating earnings of inventory liquidations and derivative valuations on our marketing segment operating earnings is summarized in the following reconciliation from a GAAP to aof our non-GAAP financial measure (infor the periods indicated (in thousands):

  2016  2015  2014 
          
As reported segment operating earnings $17,045  $22,895  $20,854 
Add (less) -            
Inventory liquidation (gains)  (8,243)  -   - 
Inventory valuation losses  -   5,357   14,247 
Derivative valuation (gains) losses  (243)  188   (312)
             
Field level operating earnings(1)
 $8,559  $28,440  $34,789 

 Year Ended December 31,
 2017 2016 2015
      
As reported segment operating earnings (1)
$11,700
 $17,045
 $22,895
Add (subtract):     
Inventory liquidation gains(3,372) (8,243) —
Inventory valuation losses—
 —
 5,357
Derivative valuation (gains) losses27
 (243) 188
Field level operating earnings (2)
$8,355
 $8,559
 $28,440
____________________
(1)
Such designation
(1)Segment operating earnings included inventory liquidation gains of $3.3 million and $8.2 million for the years ended December 31, 2017 and 2016, respectively, and inventory valuation losses of $5.4 million for the year ended December 31, 2015.
(2)The use of field level operating earnings is (a) unique to the Companyus, (b) not a substitute for a GAAP measure and is(c) may not be comparable to any similar measures developed by industry participants. The Company utilizes suchWe utilize this data to evaluate the profitability of itsour operations.

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

  As of December 31, 
  2016  2015 
     Average     Average 
  Barrels  Price  Barrels  Price 
Crude oil inventory  255,146  $51.22   261,718  $29.31 
                 

Field level operating earnings and field level purchase volumes (see earlier table) depict the Company’sour day-to-day operation of acquiring crude oil at the wellhead, transporting the material,product and delivering itthe product to market sales points. Comparative fieldField level operating earnings decreased during the year ended December 31, 2017 as compared to 2016, primarily due to increased personnel costs related to the voluntary early retirement program, partially offset by increased volumes and the effects of a newly negotiated barge contract, which reduced operating expenses, beginning in the third quarter of 2017.

Field level operating earnings decreased during the year ended December 31, 2016 relativeas compared to 2015 as competition and additional industry infrastructure development progressed in the region. Previously, aA key factor in unit margins wasis the value difference between crude oil supplies in the mid-continent region of the United StatesU.S. versus crude oil supply costs in the eastern region of the United States. The Company wasU.S. We have been 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,other locations.

We held crude oil inventory at a weighted average composite price as follows at the opportunity for the Company to capture this location-based unit value difference was eliminated.  An adverse claims experience increased insurance costs in 2015 but this experience cycle did not occur in 2016.dates indicated (in barrels):
 December 31,
 2017 2016 2015
   Average   Average   Average
 Barrels Price Barrels Price Barrels Price
            
Crude oil inventory198,011
 $61.57
 255,146
 $51.22
 261,718
 $29.31


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


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-Transportation

TheOur transportation segment revenues, and operating earnings (losses) and selected costs were as follows (infor the periods indicated (in thousands):

  2016  2015  2014 
  Amount  
Change(1)
  Amount  
Change(1)
  Amount  
Change(1)
 
                   
Revenues $52,355   (17.3)% $63,331   (8.2)% $68,968   .3%
                         
Operating earnings (loss) $(48)  (101.3)% $3,701   (22.1)% $4,750   (8.3)%
                         
Depreciation $7,249   (4.0)% $7,554   1.9% $7,416   4.5%
                         
Driver commissions $11,227   (15.4)% $13,265   (1.2)% $13,428   2.1%
                         
Insurance $4,952   9.0% $4,543   (18.5)% $5,574   (6.1)%
                         
Diesel fuel $5,688   (30.1)% $8,134   (39.7)% $13,487   (9.0)%
                         
Maintenance Expense $5,410   (15.0)% $6,365   3.6% $6,143   12.4%
                         
Mileage (000s)  22,611   (10.3)%  25,205   (4.2)%  26,314   (3.4)%
______________
 Year Ended December 31,
 2017 2016 
Change (1)
 2015 
Change (1)
          
Revenues$53,358
 $52,355
 1.9% $63,331
 (17.3%)
Operating earnings (losses)$(544) $(48) 1033.3% $3,701
 (101.3%)
Depreciation and amortization$5,364
 $7,249
 (26.0%) $7,554
 (4.0%)
Driver commissions$11,546
 $11,227
 2.8% $13,265
 (15.4%)
Insurance$5,452
 $4,952
 10.1% $4,543
 9.0%
Fuel$6,401
 $5,688
 12.5% $8,134
 (30.1%)
Maintenance expense$6,061
 $5,410
 12.0% $6,365
 (15.0%)
Mileage (000s)21,836
 22,611
 (3.4%) 25,205
 (10.3%)
____________________
(1)Represents the percentage increase (decrease) from the prior year.


The Company’sOur revenue rate structure includes a component for fuel costs such thatin which fuel cost fluctuations are largely passed through to the customer over time. A calculation of revenuesRevenues, net of fuel cost, is presented below (inwere as follows for the periods indicated (in thousands):

  2016  2015  2014 
Total transportation revenue $52,355  $63,331  $68,968 
Diesel fuel cost  (5,688)  (8,134)  (13,487)
Revenues net of fuel (1)
 $46,667  $55,197  $55,481 
______________
 Year Ended December 31,
 2017 2016 2015
      
Total transportation revenue$53,358
 $52,355
 $63,331
Diesel fuel cost(6,401) (5,688) (8,134)
Revenues, net of fuel cost (1)
$46,957
 $46,667
 $55,197
____________________
(1)Revenues, net of fuel cost, is a non-GAAP financial measure and is utilized for internal analysis.analysis of the results of our transportation segment.


2017 compared to 2016
. Revenues, net of fuel are reducedcost, increased by $0.3 million during the year ended December 31, 2017, primarily as a result of increased activity in our transportation segment. We began to see a slight increase in transportation activity during late 2017, and we continue to pursue our strategy of streamlining operations and diversifying offerings in our transportation segment. This increase in services resulted in an increase in variable expenses related to transportation activities. Fuel increased by $0.7 million as a result of an increase in the price of diesel during 2017 as compared to 2016. Our operating results for 2017 were also adversely impacted by Hurricane Harvey, which affected the Gulf Coast area in late August and early September of 2017, resulting in decreased revenues and lower mileage during 2017.

2016 compared to 2015. Revenues, net of fuel cost, decreased by $8.5 million during the year ended December 31, 2016 as compared to 2015, because of lower demand which is indicative fromas indicated by the change in miles driven shown above.decreased mileage during 2016 as compared to 2015. The combination of lower demand and excess industry-wide trucking capacity led to pressures on volumes and freight rates throughout 2016. The result is an adverse impact on operating earnings and management is working to reverse this situation.  The demand situation is being addressed by the Company with increased marketing efforts and diversification strategies.earnings. During 2016, the Companywe reduced expenses through staff reductions and selling of older inefficient equipment and revamped its approachequipment. Fuel decreased by $2.4 million as a result of lower mileage during 2016 as compared to equipment maintenance.2015.


1923



Equipment additions and retirement for the transportation fleet were as follows:follows for the periods indicated:
 Year Ended December 31,
 2017 2016 2015
      
New truck-tractors purchased—
       30 units
       60 units
Truck-tractors retired21 units
 —
 —
New trailers purchased—
       54 units
       12 units
Trailers retired—
       50 units
 —

 201620152014
New truck-tractors purchased30 units60 units40 units
Truck-tractors retired--40 units
New trailers purchased54 units12 units30 units
Trailers retired50 units--

The sale of retired equipment produced gains of less than $0.1 million, $0.4 million in 2016.and less than $0.1 million during the years ended December 31, 2017, 2016 and 2015, respectively.

The Company’s predominateOur customers are primarily in the domestic petrochemical industry. Contributing to customerCustomer demand is affected by low natural gas prices (a basic feedstock cost for the petrochemical industry) and high export demand for petrochemicals. Increased operating expenses and an industry wide shortage of qualified drivers affected the Company by suppressing revenues and results of operations during the heavy demand cycle of 2014 and early 2015.  During 2016, the competitive landscape in the transportation sector remained difficult and led to lower revenues in this segment. During late 2017, we have seen an increase in customer demand for chemical tank trucking, and we are working on capturing those opportunities.

-Oil and Gas

Oil and Gas
Our upstream crude oil and natural gas exploration and production segment revenues and operating earnings are(losses) were primarily a function of crude oil and natural gas prices and volumes. We accounted for our upstream operations under the successful efforts method of accounting. As a result of AREC’s bankruptcy filing in April 2017 and our loss of control of this subsidiary, we deconsolidated AREC effective with its bankruptcy filing and recorded our investment in AREC under the cost method of accounting. Our results for 2017 are only through April 30, 2017, during the period in which AREC was consolidated.

Our upstream crude oil and natural gas exploration and production volumes and prices.  Comparative amounts forsegment revenues, operating earnings (losses) and selected expensescosts were as follows (infor the periods indicated (in thousands):

  2016  2015  2014 
  Amount  
Change(1)
  Amount  
Change(1)
  Amount  
Change(1)
 
Revenues $3,410   (32.6)% $5,063   (62.1)% $13,361   (5.4)%
                         
Operating earnings (loss)(2)
  (533)  (97.2)%  (19,016)  153.2%  (7,510)  255.4%
                         
Depreciation and depletion  1,546   (69.5)%  5,066   (33.1)%  7,573   1.1%
                         
Dry hole expense  -   (100.0)%  817   (21.0)%  1,034   343.8%
                         
Prospect impairments  283   (83.9)%  1,758   (56.1)%  4,008   218.9%
                         
Producing property impairments  30   (99.7)%  10,324   158.0%  4,001   191.4%
______________
 Year Ended December 31,
 2017 2016 
Change (1)
 2015 
Change (1)
          
Revenues (2)
$1,427
 $3,410
 (58.2%) $5,063
 (32.6%)
Operating earnings (losses) (2)
53
 (533) 109.9% (19,016) 97.2%
Depreciation and depletion (2)
423
 1,546
 (72.6%) 5,066
 (69.5%)
Dry hole expense (2)
—
 —
 0.0% 817
 (100.0%)
Prospect impairments (2)
3
 283
 (98.9%) 1,758
 (83.9%)
Producing property impairments (2)
—
 30
 (100.0%) 10,324
 (99.7%)
____________________
(1)Represents the percentage increase (decrease) from the prior year.
(2)
Includes gains
(2)Results for 2017 represents amounts for the period from property sales of $2.5 million in 2014.January 1, 2017 through April 30, 2017.
20


2017 compared to 2016
As shown in the table below, declining. Our upstream crude oil and natural gas prices coupledexploration and production revenues and depreciation and depletion expense decreased $2.0 million and $1.1 million, respectively, during the year ended December 31, 2017 as compared to 2016. These decreases were primarily as a result of the deconsolidation of AREC effective with decliningits bankruptcy filing in April 2017 (four months of revenues and expenses in 2017 versus twelve months of revenues and expenses in 2016) as well as production declines offsetting commodity price increases in 2017.


24


2016 compared to 2015. Our upstream crude oil and natural gas exploration and production segment revenues and depreciation and depletion expense decreased $1.7 million and $3.5 million, respectively, during the year ended December 31, 2016 as compared to 2015, primarily as a result of production declines. Sales volumes acted to reduce revenues for the comparative years presented.  The sales volume decrease followeddecreased following normal production declines as persistently low prices curtailed the development of crude oil and natural gas and crude oil properties in 2015 and 2016. Contributing to operating losses were property impairments as shown in the table above. Property impairments resulted in 2015 and 2014 following fourth quarteroccurred as result of declines in crude oil prices.

Depreciation and depletion expense, calculated on a units-of-production basis, decreased primarily due to lower production volumes in 2016.
Comparative volumes
Volume and prices wereprice information was as follows:follows for the periods indicated (volumes in thousands):
 Year Ended December 31,
 2017 2016 2015
        
Crude oil     
Volume – barrels (1)
11,643
 34,200
 50,000
Average price per barrel$49.44
 $38.07
 $46.51
      
Natural gas     
Volume – Mcf (1)
189,488
 662,000
 889,000
Average price per Mcf$2.86
 $2.26
 $2.46
      
Natural gas liquids     
Volume – barrels (1)
11,204
 42,500
 42,100
Average price per barrel$26.77
 $14.39
 $12.70

(1)Volumes for 2017 are only through April 30, 2017 as a result of the deconsolidation of this subsidiary due to its bankruptcy filing.

  2016   2015   2014  
Production Volumes                 
- Crude oil  34,200 Bbls  50,000 Bbls  79,100 Bbls
- Natural gas  662,000 Mcf  889,000 Mcf  1,133,000 Mcf
 - Natural gas liquids  42,500 Bbls  42,100 Bbls  45,900 Bbls
                      
Average Price                    
- Crude oil $38.07 Bbls $46.51 Bbl $88.42 Bbl
- Natural gas $2.26 Mcf $2.46 Mcf $4.65 Mcf
 - Natural gas liquids $14.39 Bbls $12.70 Bbl $28.83 Bbl

During 2016, the Companyperiod from January 1, 2017 through April 30, 2017, we participated in the drilling of 7six wells in the Permian Basin and one well in the Haynesville Shale with no dry holes. During the year ended December 31, 2016, we participated in the drilling of seven wells in Permian Basin with no dry holes.  There were 9 wells in process as ofholes, and during the year ended December 31, 2016.2015, we participated in the drilling of 14 wells with one dry hole.

An independent evaluation of estimated oil and gas reserves andDuring the estimated future income derived from our properties is prepared on an annual basis.  See Note (12) to Consolidated Financial Statements.  The following estimates of future undiscounted net income before taxes from oil and gas properties based on average prices during 2016 is presented in such report as ofyears ended December 31, 2016 as follows (in thousands):

  As of 
  December 31, 2016 
Future net income before taxes   
-          Estimate for the year 2017 $937 
-          Estimate for the year 2018  707 
-          Estimate for the year 2019  619 
-          Estimate for the year 2020  502 
-          Estimate for the year 2021  429 
Thereafter  2,285 
Total future net income before taxes $5,479 

Net capitalizedand 2015, impairment charges for crude oil and natural gas properties were approximately $0.3 million and $12.1 million, respectively.

Capitalized crude oil and natural gas property costs (remaining net book value) associated withwere amortized in expense as the projected future net income stream as ofunderlying crude oil and natural gas reserves were produced (units-of-production method).

General and Administrative Expense

General and administrative expenses decreased by $0.7 million during the year ended December 31, 2017 as compared to 2016, wasprimarily due to the deconsolidation of AREC in April 2017 (four months of expense in 2017 versus twelve months of expense in 2016), partially offset by an increase of approximately $1.0 million in personnel expenses in 2017 as follows (a result of a voluntary early retirement program for certain employees, and higher legal and audit fees in thousands):2017.

  As of 
  December 31, 2016 
Net capitalized cost of oil and gas properties $6,358 

Impairment charges for oilGeneral and gas properties were not significantadministrative expenses increased by $0.5 million during the year ended December 31, 2016 as the forward curve as of December 31, 2016 was positively correlatedcompared to the average prices (as required by SEC regulations) used to develop the future undiscounted net income before taxes from oil and gas properties shown above. 

                Capitalized oil and gas property costs are amortized in expense as the underlying oil and gas reserves are produced (units-of-production method).
21
 -Oil and gas property sales

During 2014, the Company sold its interest in certain Oklahoma and Texas properties for proceeds totaling $2.5 million and half of its interest in certain South Texas (Lavaca County) properties for proceeds totaling $1.5 million.  Combined, the Company recorded a $2.5 million pre-tax gain from these transactions.  The Company retained an interest in the South Texas properties as development continues. The other Texas and Oklahoma properties were sold because they were nearing the end of their economic life.

-General and administrative expense and income tax
General and administrative expenses were slightly elevated in 20162015, primarily as a result of increased use of outside consultants in the fourth quarter of 2016.  Expenses in 2015 were elevatedhigher due to a $1.1 million lump sum payment made during the first quarter of 2015 to the Company’sour former President upon retirementhis retirement.

25


Investments in Unconsolidated Affiliates

During the second quarter of 2017, we deconsolidated AREC effective with its bankruptcy filing on April 21, 2017 and terminationrecorded our investment in AREC under the cost method of his previous employment agreement.  The provisionaccounting. Based upon bids received in the auction process (see Note 3 in the Notes to Consolidated Financial Statements for further information), we determined that the fair value of our investment in AREC was expected to be lower than its net book value immediately prior to the deconsolidation. As a result, during the second quarter of 2017, we recorded a non-cash charge of $1.6 million associated with the deconsolidation of AREC, which reflected the excess of the net assets of AREC over its estimated fair value based on an expected sales transaction price of approximately $5.0 million, net of estimated transaction costs. During the third quarter of 2017, we recognized an additional loss of $1.9 million, which represents the difference between the proceeds we expect to be paid upon settlement of the bankruptcy, net of anticipated remaining closing costs identified as part of the liquidation plan, and the book value of our cost method investment.

During the third quarter of 2017, we completed a review of our investment in VestaCare and determined that there was an other than temporary impairment as the current projected operating results of VestaCare did not support the carrying value of our investment. As such, we recognized a pre-tax impairment charge of $2.5 million during the third quarter of 2017 related to our investment in VestaCare.

During the year ended December 31, 2016, we completed a review of our equity method investment in Bencap and determined that there was an other than temporary impairment. Under the terms of the investment agreement, Bencap had the option to request borrowings from us of up to $1.5 million (on or after December 5, 2016 but before October 31, 2018) that we were required to provide or forfeit our 30 percent member interest. During 2016, our management determined that we were unlikely to provide additional funding due to Bencap’s lower than projected revenue growth and operating losses since investment inception. During the third quarter of 2016, we recognized an after-tax net loss of $1.4 million to write-off our investment in Bencap, which included a pre-tax impairment charge of $1.7 million, pre-tax losses from the equity method investment of $0.5 million and a tax benefit of $0.8 million.

Income Taxes

Provision for (benefit from) income taxes is based onupon federal and state tax rates, and variations in amounts are consistent with taxable income in the respective accounting periods.

-Discontinued operations

In 2014,On December 22, 2017, the Company sold the warehouseTax Cut and real estate used by the discontinued petroleum refined products marketing business operation for $0.6 million in cashJobs Act was enacted into law resulting in a pre-tax gain on salereduction in the federal corporate income tax rate from 35 percent to 21 percent for years beginning in 2018. At December 31, 2017, we had a deferred tax liability of $0.5approximately $3.3 million with such gain reported(reflecting a reduction of approximately $2.0 million resulting from the lower rate under which those deferred taxes would be expected to be recovered or settled). As a result of the lower tax rate, we expect to see a decrease in discontinued operationseither our provision for 2014.or benefit from income taxes during 2018 as compared to 2017.

See Note 11 in the Notes to Consolidated Financial Statements for further information.



26


Liquidity and Capital Resources

The Company’sLiquidity

Our liquidity derivesis from our cash balance and net cash provided by operating activities and is therefore dependent on the success of future operations. See discussionIf our cash inflow subsides or turns negative, we will evaluate our investment plan and remain flexible.

One of our wholly owned subsidiaries, AREC, filed for bankruptcy in April 2017. Over the past few years, we have de-emphasized our upstream operations and do not expect this Chapter 11 filing by AREC to have a material adverse impact on any of our core businesses. In connection with its bankruptcy filing, AREC entered into the DIP Credit Agreement with AE. AREC borrowed approximately $0.4 million under ‟Item 1A. Risk Factors”.  The most significant sourcethe DIP Credit Agreement, and the amount was repaid during the third quarter of liquidity, over time, is2017 with proceeds from the cash yield from annual net earnings factoringsales of the assets. AE was the primary creditor in AREC’s Chapter 11 process. As a result of an auction process (see Note 1 in the non-cash book expense itemsNotes to Consolidated Financial Statements), AREC sold its assets for depreciation, depletion, amortization and impairments.  The Company has no debt and fundsapproximately $5.2 million during 2017. After settlement of certain claims in late 2017, AE received approximately $2.8 million from AREC. AE anticipates receiving an additional $0.4 million in 2018 when the majority of its capital projects from this annual cash flow.  In most annual periods, the cash inflow from this source exceeds capital spending outflows.  Should cash inflow subside or turn negative, the Company will evaluate its investments accordingly.bankruptcy case is dismissed.

Cash provided from operating activities was as follows (in thousands):

  2016  2015  2014 
Net cash provided by operating activities $6,944  $25,477  $47,133 

As ofAt December 31, 2017, 2016 and 2015, the Companywe had no bank debt or other forms of debenture obligations. CashWe maintain cash balances are maintained in order to meet the timing of day-to-day cash needs and such amountsneeds. Cash and working capital, the excess of current assets over current liabilities, were as follows (inat the dates indicated (in thousands):

  As of December 31, 
  2016  2015 
Cash $87,342  $91,877 
Working capital $106,444  $96,340 

The Company relies on its ability to obtain open-line trade credit from its suppliers especially with respect to its crude oil marketing operation.  In this regard, the Company generally maintains substantial cash balances.  The cash balance decreased during 2016 as capital investments and dividends exceeded our cash flow.
22

 December 31,
 2017 2016 2015
      
Cash and cash equivalents$109,393
 $87,342
 $91,877
Working capital116,087
 106,444
 96,340
At various times each month, the Company may make 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 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 customers to make similar early payments or to post cash collateral with the Company in order to support their purchases from the Company.  Early payments and cash collateral received from customer’s increases cash and reduces accounts receivable as of the balance sheet date.

The Company maintainsWe maintain a stand-by letter of credit facility with Wells Fargo Bank, National Association to provide for the issuance of up to $60 million in stand-by letters of credit for the benefit of suppliers of crude oil.oil within our crude oil marketing segment and for other purposes. Stand-by letters of credit are issued as needed and are cancelled whencanceled as the underlying purchase obligation isobligations are satisfied throughby cash payment when due. The issuance of stand-by letters of credit enables the Companyus to avoid posting cash collateral when procuring crude oil supply. AsWe are currently using the letter of credit facility for a letter of credit related to our insurance program. At December 31, 2016,2017, we had $2.2 million outstanding under this facility. During January 2018, the Company had no outstanding lettersletter of credit under this facility.

Early payments, collateral and lettersamount outstanding decreased to approximately $0.9 million. No letter of credit amounts were as follows (in thousands):

  As of December 31, 
  2016  2015 
Early payments received $15,032  $16,770 
         
Cash collateral received $-  $840 
         
Prepayments to suppliers $-  $167 
         
Early payments to suppliers $14,382  $11,645 
         
Letters of credit outstanding $-  $1,000 

The necessity for early payments, collateral posting and letters of credit is substantially reduced as ofoutstanding at December 31, 2016, consistent with lower crude commodity prices.  Management believes2016.

We believe 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 our short-term and long-term liquidity needs.  Quarterly dividends

We utilize cash from operations to make discretionary investments in our marketing and transportation businesses. With the exception of $.22operating and capital lease commitments primarily associated with storage tank terminal arrangements, leased office space and tractors, our future commitments and planned investments can be readily curtailed if operating cash flows decrease. See “Other Items” below for information regarding our operating and capital lease obligations.

The most significant item affecting future increases or decreases in liquidity is earnings from operations, and these earnings are dependent on the success of future operations. See “Part I, Item 1A. Risk Factors.”


27


Cash Flows from Operating, Investing and Financing Activities

Our consolidated cash flows from operating, investing and financing activities were as follows for the periods indicated (in thousands):
 Year Ended December 31,
 2017 2016 2015
      
Cash provided by (used in):     
Operating activities$26,096
 $6,944
 $25,477
Investing activities(216) (7,768) (10,072)
Financing activities(3,829) (3,711) (3,712)

Operating activities. Net cash flows provided by operating activities for the year ended December 31, 2017 increased by $19.2 million when compared to 2016. This increase was primarily due to an increase in revenues, partially offset by increased operating and general and administrative expenses.

Net cash flows provided by operating activities for the year ended December 31, 2016 decreased by $18.5 million when compared to 2015. This decrease was primarily due to a decrease in revenues, partially offset by a decrease in operating and general and administrative expenses.

At various times each month, we may make cash prepayments and/or early payments in advance of the normal due date to certain suppliers of crude oil within our marketing operations. Crude oil supply prepayments are recouped and advanced from month to month as the suppliers deliver product to us. In addition, in order to secure crude oil supply, we may also “early pay” our suppliers in advance of the normal payment due date of the twentieth of the month following the month of production. These “early payments” reduce cash and accounts payable as of the balance sheet date. We also require certain customers to make similar early payments or to post cash collateral with us in order to support their purchases from us. Early payments and cash collateral received from customers increases cash and reduces accounts receivable as of the balance sheet date.

Early payments were as follows at the dates indicated (in thousands):
 December 31,
 2017 2016 2015
      
Early payments received$20,078
 $15,032
 $16,770
Cash collateral received—
 —
 840
Prepayments to suppliers—
 —
 167
Early payments to suppliers6,100
 14,382
 11,645

We rely heavily on our ability to obtain open-line trade credit from our suppliers especially with respect to our crude oil marketing operations. During the fourth quarter of 2016, we elected to make several early payments in our crude oil marketing operations. Our cash balance increased by approximately $22.1 million at December 31, 2017 relative to the year ended December 31, 2016 as the year end 2016 balance was slightly lower than normal as a result of these early payments made during the fourth quarter of 2016. Consistent with higher crude commodity prices, the need for early payments was higher at December 31, 2017 as compared to December 31, 2016 and 2015.


28


Investing activities. Net cash flows used in investing activities for the year ended December 31, 2017 decreased by $7.6 million when compared to 2016. The decrease was primarily due to a $5.8 million decrease in capital spending for property and equipment (see table below), a $4.7 million decrease in investments in unconsolidated affiliates and the receipt of $2.8 million of proceeds related to the partial settlement of AREC’s bankruptcy, partially offset by a $3.0 million decrease in cash proceeds from the sales of assets. During 2016, we invested a total of $4.7 million in two medical-related investments, VestaCare and Bencap.

Net cash flows used in investing activities for the year ended December 31, 2016 decreased by $2.3 million when compared to 2015. The decrease was primarily due to a $2.6 million decrease in capital spending for property and equipment (see table below) and a $3.0 million increase in cash proceeds from the sales of assets, partially offset by a $4.7 million increase in investments in unconsolidated affiliates, as discussed above.

Financing activities. Cash used in financing activities for the year ended December 31, 2017 increased by $0.1 million when compared to 2016 and 2015. During each of the years ended December 31, 2017, 2016 and 2015, we paid a quarterly cash dividend of $0.22 per common share ($0.88 per common share per year), or $0.9$3.7 million. During 2017, we paid $0.1 million per quarter wereof principal repayments on capital lease obligations that we entered into in 2017 for certain of our tractors in our marketing segment, with principal contractual commitments to be paid during each quarterover a period of 2016 and 2015.

five years.
-Capital projects


Capital Projects
The Company utilizes
We use cash from operations and existing cash balances to make discretionary investments in itsour marketing and transportation and oil and gas businesses. ExceptCapital spending for commitments totaling $7.2 million associated with barge affreightment contracts, storage tank terminal arrangements and office lease space, the Company’s future commitments and planned investments can be readily adjusted as the Company deems necessary.
23

Apast five year history of capital spending isyears was as follows (infor the periods indicated (in thousands):

                
  2012  2013  2014  2015  2016 
                
Crude oil marketing $12,391  $11,343  $13,598  $2,126  $1,321 
                     
Truck transportation  15,538   3,165   8,994   6,579   6,868 
                     
Oil and gas exploration  23,083   13,094   7,931   2,369   295 
                     
Medical management  -   -   -   -   4,700 
                     
  $51,012  $27,602  $30,523  $11,074  $13,184 

Marketing
 Year Ended December 31,
 2017 2016 2015 2014 2013
          
Crude oil marketing (1)
$468
 $1,321
 $2,126
 $13,598
 $11,343
Truck transportation351
 6,868
 6,579
 8,994
 3,165
Oil and natural gas exploration1,825
 295
 2,369
 7,931
 13,094
Medical management—
 4,700
 —
 —
 —
Capital spending$2,644
 $13,184
 $11,074
 $30,523
 $27,602
_______________
(1)Our marketing segment amount for 2017 does not include approximately $1.8 million of tractors acquired under capital leases.

Our crude oil marketing segment spending levels were consistent for 2012 throughduring 2013 and 2014 and were backed by crude oil prices remaining strong, in the $90 -– $100 per barrel range. In late 2014, crude oil prices fell and we curtailed spending was curtailed induring 2015, 2016 and 2016.2017.

ForIn our transportation the 2012 period saw stepped up equipment replacements as customer demand increased following a cut back in such activity following the 2008 national recession.  The yearsegment, 2013 was stable thenwith an increase in expenditures ramped up in 2014 to add capacity tracking with the petrochemical industry expansion efforts. InHowever, in late 2015 and continuing into 2016 however,and 2017, demand for truck services weakened. The major project for 2016 was improvements to the existing Houston terminal facility. We are seeing increased demand in our transportation segment in 2017 and have plans to grow this segment in 2017.

The Company has de-emphasizedWe exited the crude oil and natural gas exploration segment in recent years and production business with the Company doesbankruptcy filing and subsequent sale of our crude oil and natural gas assets. We currently do not currently have any plans to pursue additional medical-related investments.

Off-balance Sheet Arrangements and

29


Other Items

Contractual Cash Obligations

The Company maintainsfollowing table summarizes our significant contractual obligations at December 31, 2017 (in thousands):
   Payments due by period
 Total Less than 1 year 1-3 years 3-5 years More than 5 years
          
Capital lease obligations (1)
$1,847
 $398
 $796
 $653
 $—
Operating lease obligations (2)
3,407
 2,758
 531
 95
 23
Purchase obligations (3)
123,238
 123,238
 —
 —
 —
Total contractual obligations$128,492
 $126,394
 $1,327
 $748
 $23
___________________
(1)Amounts represent our principal contractual commitments, including interest, outstanding under capital leases we entered into during 2017 for certain tractors in our marketing segment.
(2)Amounts represent rental obligations under non-cancelable operating leases and terminal arrangements with terms in excess of one year.
(3)Amount represents commitments to purchase certain quantities of crude oil substantially in January 2018 in connection with our crude oil marketing activities. These commodity purchase obligations are the basis for commodity sales, which generate the cash flow necessary to meet such purchase obligations.

In January 2018, we entered into a new lease agreement with a seven year term for storage tanks and other related assets in the Port of Victoria area of Texas in our crude oil marketing segment. Annual commitments for the years ended December 31, 2018 through 2025 will be approximately $1.5 million per year, for a total of approximately $10.1 million.

We maintain certain 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 enterswe enter into office space and certain lease and terminal access contracts in order to provide tank storage and dock access for itsour crude oil marketing business. SuchThese storage and access contracts require certain minimum monthly payments for the term of the contracts. All lease commitments qualify for off-balance sheet treatment.  The Company has no capital lease obligations.  Rental expense was as follows (in thousands):

  Year Ended December 31, 
  2016  2015  2014 
          
Rental expense $11,314  $11,168  $9,755 

As of December 31, 2016, rental obligations under long-term non-cancelable operating leases and terminal arrangements for the next five years and thereafter are payable as follows (inperiods indicated (in thousands):

2017  2018  2019  2020  2021  Thereafter  Total 
$4,768  $2,018  $365  $4  $-  $-  $7,155 

24

 Year Ended December 31,
 2017 2016 2015
      
Rental expense$12,073
 $11,314
 $11,168
In addition to its lease obligations, the Company is also committed to purchase certain quantities of crude oil in connection with its marketing activities.  Such commodity purchase obligations are the basis for commodity sales, which generate the cash flow necessary to meet such purchase obligations.  Approximate commodity purchase obligations as of December 31, 2016 are as follows (in thousands):

January  Remaining             
2017  2017  2018  2019  Thereafter  Total 
$89,408  $330  $-  $-  $-  $89,738 

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’sOur primary insurance needs are workers’ compensation, automobile and umbrella liability coverage for itsour trucking fleet and medical insurance for itsour employees. Insurance costs arewere as follows (infor the periods indicated (in thousands):

  2016  2015  2014 
Insurance costs $13,330  $15,570  $14,800 

Competition
 Year Ended December 31,
 2017 2016 2015
      
Insurance costs$10,438
 $13,330
 $15,570

In all phasesOff-Balance Sheet Arrangements

We have no off-balance sheet arrangements that have or are reasonably expected to have a material current or future effect on our financial position, results of its operations the Company encounters strong competition from a numberor cash flows.

30


Related Party Transactions

For information regarding our related party transactions, see Note 9 of the Company. The Company faces competition principally in establishing trade credit, pricingNotes to Consolidated Financial Statements included under Part II, Item 8 of available materials and qualitythis annual report.

Recent Accounting Developments

For information regarding recent accounting developments, see Note 2 of service, as well as for the acquisitionNotes to Consolidated Financial Statements included under Part II, Item 8 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.this annual report.


Outlook

Persistently low crude oil prices, coupled with declining oil production, are expectedWe took various steps to adversely impact the Company’s crude oil marketing operation.  Demand for transportation services remains uncertain.  Thestreamline our business in 2017, which we anticipate will lead to increased margins in both of our core segments during 2018. Our focus in transportation, therefore, is on both aggressive marketing, diversification strategies and cost containment.  For the oil and gas segment, the effort is to reduce cost and optimize cash flow as reserves are produced.  During 2017, the Company2018 will be focused on improvingexpanding our core businesses and working on strategic business development. In spite of recovering crude oil prices and increased production in our crude oil gathering and marketing core areas, margins remain tight. Competition with peers and with pipeline direct connects to lease production remains challenging.

The Company has the followingOur major objectives for 2017:2018 are as follows:

-Marketing—manage declining supply volumes and unit margins to maximize cash flow, while looking to expand into new regions.
Marketing – We will have a focus on increasing margins to maximize cash flow, capturing midstream opportunities associated with increasing rig counts, drilling and completion activity in the U.S.

-
Transportation—increase truck utilization, enhance diversification strategies and improve cost efficiencies.
Transportation – We plan to increase truck utilization, upgrade fleet quality and enhance driver retention and recruitment. The transportation segment is uniquely positioned to take advantage of major downstream infrastructure projects that are taking place across the Gulf Coast.
-Strategic business development – deploy a disciplined investment approach to growing existing core areas and funding new growth opportunities.


Strategic business development – We will deploy a disciplined investment approach to growth in our two core segments and funding new growth opportunities that are adjacent and complimentary to existing operating activities.
-Oil and gas— continue to de-emphasize this business unit while preserving the resource value of our oil and gas properties.

25

Critical Accounting Policies and UseEstimates

In our financial reporting processes, we employ methods, estimates and assumptions that affect the reported amounts of Estimatesassets and liabilities and disclosure of contingent assets and liabilities as of the date of our financial statements.  These methods, estimates and assumptions also affect the reported amounts of revenues and expenses for each reporting period.  Investors should be aware that actual results could differ from these estimates if the underlying assumptions prove to be incorrect.  The following sections discuss the use of estimates within our critical accounting policies and estimates.


Fair Value Accounting

The Company enters
We enter into certain forward commodity contracts that are required to be recorded at fair value, and suchthese 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,we elect, cash flow hedge accounting. The CompanyWe had no contracts designated for hedge accounting during the years ended December 31, 2017, 2016 2015 and 2014.2015.

The Company utilizes
31


We utilize a market approach to valuing itsour commodity contracts. On a contract by contract, forward month by forward month basis, the Company obtainswe obtain observable market data for valuing itsour contracts that typically have durations of less than 18 months. As ofAt December 31, 2016,2017, all of the Company’sour market value measurements were based on inputs based on observable market data (Level 2 inputs). See discussion under ‟Fair“Fair Value Measurements” in Note (1)10 to the Consolidated Financial Statements.

The Company’sOur 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 monitorsWe monitor and manages itsmanage our exposure to market risk to ensure compliance with the Company’sour risk management policies. SuchThese risk management policies are regularly assessed to ensure their appropriateness given management’sour objectives, strategies and current market conditions.

Trade Accounts and Allowance for Doubtful Accounts

Due to theOur trade accounts receivable has high volume and complexity of transactions and thea high degree of interdependence with third parties, this is a difficult area to control and manage.  The Company manages this processparties. We manage our receivables by participating in a monthly settlement process with each of itsour counterparties. Ongoing account balances are monitored monthly, and the Company attemptswe attempt to gain the cooperation of suchour counterparties to reconcile outstanding balances. The CompanyWe also placesplace great emphasis on collecting cash balances due and paying only bonafide and properly supported claims. In addition, the Company maintainswe maintain and monitors itsmonitor our bad debt allowance. NeverthelessWe perform credit evaluations of our customers and grant credit based on past payment history, financial conditions and anticipated industry conditions. Customer payments are regularly monitored and a provision for doubtful accounts is established based on specific situations and overall industry conditions. However, a degree of risk remains due to the custom and practices of the industry. See Note 2 in the Notes to Consolidated Financial Statements for further information.

OilLiability and Gas Reserve EstimateContingency Accruals

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.
26

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, 2016 and 2015, the Company has accrued $0.5 million of future legal and/or settlement costs for these matters.

From time to time as incidentincidental to itsour operations, the Company becomeswe become involved in various accidents, lawsuits and/or disputes. Primarily asAs an operator of an extensive trucking fleet, the Company iswe are 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 haswe have extensive operations that must comply with a wide variety of tax laws, environmental laws and labor laws, among others. Should an incident occur, management evaluateswe evaluate the claim based on its nature, the facts and circumstances and the applicability of insurance coverage. ToWhen our assessment indicates that it is probable that a liability has occurred and the extent management believes that such event may impact the financial conditionamount of the Company, management will estimate the monetary value of the claim andliability can be reasonably estimated, we make appropriate accruals or disclosure. We base our estimates on all known facts at the time and our assessment of the ultimate outcome, including consultation with external experts and counsel. We revise these estimates as additional information is obtained or resolution is achieved.

At December 31, 2017, we were not aware of any contingencies or liabilities that would have a material adverse effect on our financial position, results of operations or cash flows.

Revenue Recognition

The Company’sOur crude oil marketing customers are invoiced 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 Companywe also recognizesrecognize fair value or mark-to-market gains and losses related to its commodity activities. See discussion under ‟Revenue“Revenue Recognition” in Note (1)2 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

See Note 2 in the Company’s interests in producing wells is recognized as title and physical possession of the oil and natural gas passesNotes to the purchaser.

Recent Accounting Pronouncements

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which supersedes the revenue recognition requirements in “Revenue Recognition (Topic 605).” Topic 606 is basedConsolidated Financial Statements for a discussion regarding our adoption on the core principle that revenue is recognized to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. Topic 606 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract.

Topic 606 is effective for fiscal years beginning after December 15, 2017, and interim periods within those years, with early adoption permitted in 2017; however we do not plan to adopt the standard early. Entities will have the option to apply the standard using a full retrospective or modified retrospective adoption method. The Company has not yet selected a transition method.  The Company has a team in place to analyze the impact of Update 2014-09, and the related ASU's, across all revenue streams to evaluate the impactJanuary 1, 2018 of the new accounting standard onrelated to revenue contracts.   This includes reviewing current accounting policies and practices to identify potential differences that would result from applying the requirements under the new standard. Our evaluation of the impact on our Consolidated Financial Statements and related disclosures is ongoing and not complete.  The Company is continuing our review of contracts relative to the provisions of Topic 606.recognition.



2732


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.  The adoption of this guidance did not have an impact on the  Consolidated Financial Statements.

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” This standard requires, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company expects to adopt this standard in the first quarter of 2019 and is currently evaluating the impact of this standard on our Consolidated Financial Statements and related disclosures. In connection with our assessment work, The Company has a team in place to analyze the impact of ASU 2016-02 and is continuing a review of our contracts relative to the provisions of the lease standard.

In August 2016, the FASB issued ASU No. 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.” This standard is intended to reduce existing diversity in practice in how certain transactions are presented on the statement of cash flows. The standard is effective for interim and annual reporting periods beginning after December 15, 2017, although early adoption is permitted. The guidance requires application using a retrospective transition method. The Company will adopt ASU No. 2016-15 in the first quarter of 2017 and has determined the amendment will not have a material impact on our Consolidated Financial Statements and related disclosures.

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

Item 7A7A. .  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKQuantitative and Qualitative Disclosures about Market Risk

The Company’s exposureIn the normal course of business, we are exposed to market risk includes potential adversecertain risks, including changes in interest rates and commodity prices.

Interest Rate Risk

The Company had no long-term debt outstanding at December 31, 2016 and 2015.  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, 2016.
28

Commodity Price Risk

The Company’sOur major market risk exposure is in the pricing applicable to itsour marketing and production of crude oil and natural gas. Realized pricing is primarily driven by the prevailing spot prices applicable to crude oil and natural gas. Commodity price risk in the Company’sour 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 enterswe enter into forward contracts to minimize or hedge the impact of market fluctuations on itsour purchases of crude oil and natural gas. In each instance, the Company lockswe lock 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’sour assessments of numerous accounting standards and positions that comply with generally accepted accounting principlesGAAP in the United States.U.S. The fair value of suchthese 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’sour results of operations.  See discussion under ‟Fair Value Measurements” inoperations (see Note 12 to the Consolidated Financial Statements.Statements for further information).

Historically, prices received for crude oil and natural gas sales have been volatile and unpredictable with price volatility expected to continue. From January 1, 20152016 through December 31, 2016, the Company’s2017, our crude oil monthly average wholesale purchase costs ranged from an average low of $26.26 per barrel to a monthly average high of $57.36$60.16 per barrel during the same period. A hypothetical ten percent additional adverse change in average hydrocarbon prices, assuming no changes in volume levels, would have reduced earnings by approximately $1.6$1.2 million and $1.3$1.6 million for the comparative years ended December 31, 20162017 and 2015,2016, respectively.

33


29Item 8. Financial Statements and Supplementary Data.




ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA



ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



Page
 Page No.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMReports of Independent Registered Public Accounting Firms31
FINANCIAL STATEMENTS:
35
  
Consolidated Balance Sheets as of December 31, 20162017 and 2015201632
37
  
Consolidated Statements of Operations
for the Years Ended December 31, 2017, 2016 and 2015
38
 
Consolidated Statements of Cash Flows
for the Years Ended December 31, 2017, 2016 2015 and 20142015		33
39
  
Consolidated Statements of Shareholders’ Equity
for the Years Ended
December 31, 2017, 2016 2015 and 2014201534
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2016, 2015 and 201435
40
  
Notes to Consolidated Financial Statements36
Note 1   – Organization and Basis of Presentation
41
Note 2   – Summary of Significant Accounting Policies
42
Note 3   – Subsidiary Bankruptcy, Deconsolidation and Sale
47
Note 4   – Prepayments and Other Current Assets
48
Note 5   – Property and Equipment
49
Note 6   – Cash Deposits and Other Assets
50
Note 7   – Investments in Unconsolidated Affiliates
51
Note 8   – Segment Reporting
53
Note 9   – Transactions with Affiliates
54
Note 10 – Derivative Instruments and Fair Value Measurements
55
Note 11 – Income Taxes
59
Note 12 – Supplemental Cash Flow Information
61
Note 13 – Commitments and Contingencies
61
Note 14 – Concentration of Credit Risk
63
Note 15 – Quarterly Financial Information (Unaudited)
65
Note 16 – Oil and Gas Producing Activities (Unaudited)
66


3034


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheetssheet of Adams Resources & Energy, Inc. and subsidiaries (the "Company"“Company”) as of December 31, 2017, the related consolidated statements of operations, shareholders’ equity, and cash flows for the year ended December 31, 2017, and the related notes (collectively, the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017, and the results of its operations and its cash flows for the year ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 12, 2018 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ KPMG LLP
We have served as the Company’s auditor since 2017.

Houston, Texas
March 12, 2018



35


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 sheet of Adams Resources & Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2016, and 2015, and the related consolidated statements of operations, shareholders'shareholders’ equity, and cash flows for each of the threetwo years in the period ended December 31, 2016. These financial statements are the responsibility of the Company'sCompany’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 as of December 31, 2016, and 2015, and the results of their operations and their cash flows for each of the threetwo years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.

          We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2016, 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 31, 2017 expressed an adverse opinion on the Company's internal control over financial reporting because of a material weakness.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas
March 31, 2017





3136



ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands)
  December 31, 
ASSETS 2016  2015 
CURRENT ASSETS:      
Cash and cash equivalents $87,342  $91,877 
Accounts receivable, net of allowance for doubtful accounts of        
$225 and $206, respectively  87,162   71,813 
Inventories  13,070   7,671 
Fair value contracts  112   - 
Income tax receivable  2,735   2,587 
Prepayments  2,097   2,589 
         
Total current assets  192,518   176,537 
         
PROPERTY AND EQUIPMENT:        
Marketing  56,907   65,200 
Transportation  70,849   70,732 
Oil and gas (successful efforts method)  62,784   77,117 
Other  108   187 
   190,648   213,236 
         
Less – Accumulated depreciation, depletion and amortization  (144,323)  (153,521)
   46,325   59,715 
OTHER ASSETS:        
Investments  2,500   - 
Cash deposits and other  5,529   6,963 
  $246,872  $243,215 
LIABILITIES AND SHAREHOLDERS’ EQUITY        
         
CURRENT LIABILITIES:        
Accounts payable $79,897  $74,117 
Accounts payable – related party  53   40 
Fair value contracts  64   195 
Accrued and other liabilities  6,060   5,845 
Total current liabilities  86,074   80,197 
         
LONG-TERM DEBT  -   - 
         
OTHER LIABILITIES:        
Asset retirement obligations  2,329   2,469 
Deferred taxes and other liabilities  7,157   8,039 
   95,560   90,705 
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 for all periods presented  422   422 
Contributed capital  11,693   11,693 
Retained earnings  139,197   140,395 
Total shareholders’ equity  151,312   152,510 
  $246,872  $243,215 

The accompanying notes are an integral part of these consolidated financial statements.
  December 31,
  2017 2016
ASSETS    
Current assets:    
Cash and cash equivalents $109,393
 $87,342
Accounts receivable, net of allowance for doubtful
accounts of $303 and $225, respectively
 121,353
 87,162
Inventory 12,192
 13,070
Derivative assets 166
 112
Income tax receivable 1,317
 2,735
Prepayments and other current assets 1,264
 2,097
Total current assets 245,685
 192,518
Property and equipment, net 29,362
 46,325
Investments in unconsolidated affiliates 425
 2,500
Cash deposits and other assets 7,232
 5,529
Total assets $282,704
 $246,872
     
LIABILITIES AND SHAREHOLDERS’ EQUITY    
Current liabilities:    
Accounts payable $124,706
 $79,897
Accounts payable – related party 5
 53
Derivative liabilities 145
 64
Current portion of capital lease obligations 338
 —
Other current liabilities 4,404
 6,060
Total current liabilities 129,598
 86,074
Other long-term liabilities:    
Asset retirement obligations 1,273
 2,329
Capital lease obligations 1,351
 —
Deferred taxes and other liabilities 3,363
 7,157
Total liabilities 135,585
 95,560
     
Commitments and contingencies (Note 13) 
 
     
Shareholders’ equity:    
Preferred stock – $1.00 par value, 960,000 shares
authorized, none outstanding
 —
 —
Common stock – $0.10 par value, 7,500,000 shares
authorized, 4,217,596 shares outstanding
 422
 422
Contributed capital 11,693
 11,693
Retained earnings 135,004
 139,197
Total shareholders’ equity 147,119
 151,312
Total liabilities and shareholders’ equity $282,704

$246,872

See Notes to Consolidated Financial Statements.

3237


ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)


  Years Ended December 31, 
  2016  2015  2014 
REVENUES:         
Marketing $1,043,775  $1,875,885  $4,050,497 
Transportation  52,355   63,331   68,968 
Oil and natural gas  3,410   5,063   13,361 
   1,099,540   1,944,279   4,132,826 
COSTS AND EXPENSES:            
Marketing  1,016,733   1,841,893   4,020,017 
Transportation  45,154   52,076   56,802 
Oil and natural gas operations  2,084   6,931   7,817 
Oil and natural gas property impairments  313   12,082   8,009 
Oil and natural gas property sale (gain)  -   -   (2,528)
General and administrative  10,410   9,939   8,613 
Depreciation, depletion and amortization  18,792   23,717   24,615 
   1,093,486   1,946,638   4,123,345 
             
Operating (Loss) Earnings  6,054   (2,359)  9,481 
             
Other Income (Expense):            
Interest income  582   327   301 
Interest expense  (2)  (13)  (2)
             
Earnings (loss) before income taxes            
and equity investments  6,634   (2,045)  9,780 
             
Income Tax (Provision) Benefit:            
Current  (2,778)  (4,073)  (9,712)
Deferred  87   4,843   6,151 
   (2,691)  770   (3,561)
Earnings (loss) from continuing operations  3,943   (1,275)  6,219 
Earnings (loss) from equity investments, net of tax benefit            
of $770, zero and zero, respectively  (1,430)  -   - 
Earnings (loss) from discontinued operations net of tax            
(provision) benefit of zero, zero and $(163) respectively  -   -   304 
Net Earnings (Loss) $2,513  $(1,275) $6,523 
             
EARNINGS (LOSS) PER SHARE:            
From continuing operations $.94  $(.30) $1.48 
From equity investments  (.34)  -   - 
From discontinued operations  -   -   .07 
Basic and diluted net earnings per share $.60  $(.30) $1.55 
             
Dividends declared per common share $.88  $.88  $.88 

  Year Ended December 31,
  2017 2016 2015
Revenues:      
Marketing $1,267,275
 $1,043,775
 $1,875,885
Transportation 53,358
 52,355
 63,331
Oil and natural gas 1,427
 3,410
 5,063
Total revenues 1,322,060
 1,099,540
 1,944,279
       
Costs and expenses:      
Marketing 1,247,763
 1,016,733
 1,841,893
Transportation 48,538
 45,154
 52,076
Oil and natural gas 948
 2,084
 6,931
Oil and natural gas property impairments 3
 313
 12,082
General and administrative 9,707
 10,410
 9,939
Depreciation, depletion and amortization 13,599
 18,792
 23,717
Total costs and expenses 1,320,558
 1,093,486
 1,946,638
       
Operating earnings (losses) 1,502
 6,054
 (2,359)
       
Other income (expense):      
Loss on deconsolidation of subsidiary (Note 3) (3,505) —
 —
Impairment of investment in unconsolidated affiliate (2,500) —
 —
Interest income 1,103
 582
 327
Interest expense (27) (2) (13)
Total other income (expense), net (4,929) 580
 314
       
(Losses) earnings before income taxes and investment      
in unconsolidated affiliate (3,427) 6,634
 (2,045)
       
Income tax (provision) benefit:      
Current (895) (2,778) (4,073)
Deferred 3,840
 87
 4,843
Income tax benefit (provision) 2,945
 (2,691) 770
       
Earnings (losses) from continuing operations (482) 3,943
 (1,275)
Losses from investment in unconsolidated affiliate, net of      
tax benefit of $—, $770 and $—, respectively —
 (1,430) —
Net (losses) earnings $(482) $2,513
 $(1,275)
       
Earnings (losses) per share:      
From continuing operations $(0.11) $0.94
 $(0.30)
From investment in unconsolidated affiliate —
 (0.34) —
Basic and diluted net (losses) earnings per common share $(0.11) $0.60
 $(0.30)
       
Weighted average number of common shares outstanding 4,218
 4,218
 4,218
       
Dividends per common share $0.88
 $0.88
 $0.88

The accompanying notes are an integral part of these consolidated financial statements.See Notes to Consolidated Financial Statements.


3338



ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
  Year Ended December 31,
  2017 2016 2015
Operating activities:      
Net (losses) earnings $(482) $2,513
 $(1,275)
Adjustments to reconcile net (losses) earnings to net cash      
provided by operating activities:      
Depreciation, depletion and amortization 13,599
 18,792
 23,717
Gains on sale of property (594) (1,966) (535)
Dry hole costs incurred —
 —
 817
Impairment of oil and natural gas properties 3
 313
 12,082
Provision for doubtful accounts 78
 19
 27
Deferred income taxes (3,840) (857) (4,843)
Net change in fair value contracts 27
 (243) 188
Losses from equity investment —
 468
 —
Impairment of investments in unconsolidated affiliates 2,500
 1,732
 —
Loss on deconsolidation of subsidiary (Note 3) 3,505
 —
 —
Changes in assets and liabilities:      
Accounts receivable (34,935) (15,368) 72,594
Accounts receivable/payable, affiliates 271
 —
 —
Inventories 878
 (5,399) 5,810
Income tax receivable 1,418
 (148) (1,617)
Prepayments and other current assets 831
 492
 8,351
Accounts payable 44,790
 6,984
 (87,404)
Accrued liabilities (991) 52
 (166)
Other (962) (440) (2,269)
Net cash provided by operating activities 26,096
 6,944
 25,477
       
Investing activities:      
Property and equipment additions (2,644) (8,484) (11,074)
Proceeds from property sales 720
 3,706
 719
Proceeds from sales of AREC assets 2,775
 —
 —
Investments in unconsolidated affiliates —
 (4,700) —
Insurance and state collateral (deposits) refunds (1,067) 1,710
 283
Net cash used in investing activities (216) (7,768) (10,072)
       
Financing activities:      
Principal repayments of capital lease obligations (118) —
 —
Dividends paid on common stock (3,711) (3,711) (3,712)
Net cash used in financing activities (3,829) (3,711) (3,712)
       
Increase (decrease) in cash and cash equivalents 22,051
 (4,535) 11,693
Cash and cash equivalents at beginning of period 87,342
 91,877
 80,184
Cash and cash equivalents at end of period $109,393
 $87,342
 $91,877

See Notes to Consolidated Financial Statements.

39


ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(In thousands)

           Total 
  Common  Contributed  Retained  Shareholders’ 
  Stock  Capital  Earnings  Equity 
             
BALANCE, January 1, 2014 $422  $11,693  $142,570  $154,685 
Net earnings  -   -   6,523   6,523 
Dividends paid on common stock  -   -   (3,711)  (3,711)
BALANCE, December 31, 2014 $422  $11,693  $145,382  $157,497 
Net earnings  -   -   (1,275)  (1,275)
Dividends paid on common stock  -   -   (3,712)  (3,712)
BALANCE, December 31, 2015 $422  $11,693  $140,395  $152,510 
Net earnings (loss)  -   -   2,513   2,513 
Dividends paid on common stock  -   -   (3,711)  (3,711)
BALANCE, December 31, 2016 $422 ��$11,693  $139,197  $151,312 


The accompanying notes are an integral part of these consolidated financial statements.
34
        Total
  Common Contributed Retained Stockholders’
  Stock Capital Earnings Equity
         
Balance, January 1, 2015 $422
 $11,693
 $145,382
 $157,497
Net losses —
 —
 (1,275) (1,275)
Dividends paid on common stock —
 —
 (3,712) (3,712)
Balance, December 31, 2015 422
 11,693
 140,395
 152,510
Net earnings —
 —
 2,513
 2,513
Dividends paid on common stock —
 —
 (3,711) (3,711)
Balance, December 31, 2016 422
 11,693
 139,197
 151,312
Net losses —
 —
 (482) (482)
Dividends paid on common stock —
 —
 (3,711) (3,711)
Balance, December 31, 2017 $422
 $11,693
 $135,004
 $147,119


See Notes to Consolidated Financial Statements.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)


  Years Ended December 31, 
  2016  2015  2014 
CASH PROVIDED BY OPERATIONS:         
Net earnings (loss) $2,513  $(1,275) $6,523 
Adjustments to reconcile net earnings to net cash            
from operating activities-            
Depreciation, depletion and amortization  18,792   23,717   24,615 
Property sales (gains) oil and natural gas  -   -   (2,528)
Property sale (gains) other  (1,966)  (535)  (1,028)
Dry hole costs incurred  -   817   1,034 
Impairment of oil and natural gas properties  313   12,082   8,009 
Provision for doubtful accounts  19   27   (73)
Deferred income taxes (includes equity investments)  (857)  (4,843)  (6,151)
Net change in fair value contracts  (243)  188   402 
Equity investment (earnings) losses  468   -   - 
Impairment of equity investment  1,732   -   - 
Decrease (increase) in accounts receivable  (15,368)  72,594   99,749 
Decrease (increase) in inventories  (5,399)  5,810   14,135 
Decrease (increase) in income tax receivable  (148)  (1,617)  1,127 
Decrease (increase) in prepayments  492   8,351   5,839 
Increase (decrease) in accounts payable  6,984   (87,404)  (104,887)
Increase (decrease) in accrued and other liabilities  52   (166)  448 
Other changes, net  (440)  (2,269)  (81)
Net cash provided by operating activities  6,944   25,477   47,133 
             
INVESTING ACTIVITIES:            
Property and equipment additions  (8,484)  (11,074)  (30,523)
Insurance and state collateral (deposits) refunds  1,710   283   (493)
Investments  (4,700)  -   - 
Proceeds from property sales  3,706   719   7,045 
Net cash (used in) investing activities  (7,768)  (10,072)  (23,971)
             
FINANCING ACTIVITIES:            
Dividend payments  (3,711)  (3,712)  (3,711)
Net cash (used in) financing activities  (3,711)  (3,712)  (3,711)
             
Increase (decrease) in cash and cash equivalents  (4,535)  11,693   19,451 
             
Cash and cash equivalents at beginning of year  91,877   80,184   60,733 
             
Cash and cash equivalents at end of year $87,342  $91,877  $80,184 


The accompanying notes are an integral part of these consolidated financial statements.
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ADAMS RESOURCES & ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(1)  Summary
Note 1. Organization and Basis of Significant Accounting PoliciesPresentation

Principles of ConsolidationOrganization

The accompanying consolidated financial statements include the accounts of Adams Resources & Energy, Inc., (“AE”) is a publicly traded Delaware corporation (‟AE”) together with its wholly owned subsidiaries (the ‟Company”) after eliminationorganized in 1973, the common shares of all intercompany accounts and transactions.  The impactwhich are listed on the accompanying financial statements of events occurring after December 31, 2016 was evaluated throughNYSE MKT LLC (“NYSE MKT”) under the date of issuance of these financial statements.

Nature of Operations

The Company isticker symbol “AE”. We and our subsidiaries are primarily engaged in the business of crude oil marketing, transportation and storage in various crude oil and natural gas basins in the lower 48 states of the United States (“U.S.”). We also conduct tank truck transportation of liquid chemicals and dry bulk and oilISO tank container storage and gas explorationtransportation primarily in the lower 48 states of the U.S. with deliveries into Canada and production.  Its primary area of operation is withinMexico and with terminals in the Gulf Coast region of the U.S. Unless the context requires otherwise, references to “we,” “us,” “our,” the “Company” or “AE” are intended to mean the business and operations of Adams Resources & Energy, Inc. and its consolidated subsidiaries.

On April 21, 2017, one of our wholly owned subsidiaries, Adams Resources Exploration Corporation (“AREC”), filed a voluntary petition in the United States.States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”) seeking relief under Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code”), Case No. 17-10866 (KG). AREC operated its business and managed its properties as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and order of the Bankruptcy Court. AE was the primary creditor in the Chapter 11 process.

On May 3, 2017, AREC filed a motion with the Bankruptcy Court for approval of an auction process to sell its assets pursuant to Section 363 of the Bankruptcy Code and for approval to engage an advisor to conduct the auction. The auction commenced on July 19, 2017 to determine the highest or otherwise best bid to acquire all or substantially all of AREC’s assets. During the third quarter of 2017, Bankruptcy Court approval was obtained on three asset purchase and sales agreements with three unaffiliated parties, and AREC closed on the sales of substantially all of its assets (see Note 3 for further information).

As a result of AREC’s voluntary bankruptcy filing in April 2017, we no longer controlled the operations of AREC; therefore, we deconsolidated AREC effective with the bankruptcy filing and recorded our investment in AREC under the cost method (see Note 3 for further information). We obtained approval of a confirmed plan in December 2017, and we expect the case to be dismissed during the first half of 2018. Over the past few years, we have de-emphasized our upstream operations and do not expect this Chapter 11 filing by AREC to have a material adverse impact on any of our core businesses.

Historically, we have operated and reported in three business segments: (i) crude oil marketing, transportation and storage, (ii) tank truck transportation of liquid chemicals and dry bulk and ISO tank container storage and transportation, and (iii) upstream crude oil and natural gas exploration and production. We exited the crude oil and natural gas exploration and production business during 2017 with the sale of our crude oil and natural gas exploration and production assets (see Note 3 for further information).

The consolidated financial statements and the accompanying notes are prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) and the rules of the U.S. Securities and Exchange Commission (“SEC”). All significant intercompany transactions and balances have been eliminated in consolidation.


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Table of Contents

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Use of Estimates

The preparation of our financial statements in conformity with GAAP requires management to use estimates and assumptions that affect the reported amount of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We base our estimates and judgments on historical experience and on various other assumptions and information we believe to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the operating environment changes. While we believe the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.


Note 2. Summary of Significant Accounting Policies

We adhere to the following significant accounting policies in the preparation of our consolidated financial statements.
Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable associated with crude oil marketing activities comprise approximately 90 percent of our total receivables, and industry practice requires payment for these sales to occur within 20 days of the end of the month following a transaction. Our 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.

Our allowance for doubtful accounts is determined based on specific identification combined with a review of the general status of the aging of all accounts. We consider the following factors in our review of our allowance for doubtful accounts: (i) historical experience with customers, (ii) the perceived financial stability of customers based on our research, (iii) the levels of credit we grant to customers, and (iv) the duration of the receivable. We may increase the allowance for doubtful accounts in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties. On a routine basis, we review estimates associated with the allowance for doubtful accounts to ensure that we have recorded sufficient reserves to cover potential losses. See Note 14 for further information regarding credit risk.

The following table presents our allowance for doubtful accounts activity for the periods indicated (in thousands):
 Year Ended December 31,
 2017 2016 2015
      
Balance at beginning of period$225
 $206
 $179
Charges to costs and expenses137
 100
 116
Deductions(59) (81) (89)
Balance at end of period$303
 $225
 $206

Cash and Cash Equivalents

Cash and cash equivalents include any Treasury bill, commercial paper, money market fund or federal fundsrepresent unrestricted cash on hand and highly liquid investments with maturityoriginal maturities of 90 days or less.less than three months from the date of purchase. Cash and cash equivalents are maintained with major financial institutions, and such depositsdeposit amounts may exceed the amount of federally backed insurance provided. While the Companywe regularly monitorsmonitor the financial stability of suchthese institutions, cash and cash equivalents ultimately remain at risk subject to the financial viability of suchthese institutions.

Allowance for Doubtful Accounts

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Accounts receivable are
Table of Contents

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Derivative Instruments

In the productnormal course of 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 20 days of the month following the transaction date.  For such receivables, an allowance for doubtful accounts is determined based on specific account identification.  The balance of accounts receivable results primarily from 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.

Inventory

Inventory consists of crude oil held in storage tanks and at third-party pipelines as part of the Company’sour operations, our crude oil marketing operations.  Crude oil inventorysegment purchases and sells crude oil. We seek to profit by procuring the commodity as it is carried atproduced and then delivering the lower of average costproduct to the end users or market.

36
Prepayments

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

  December 31, 
  2016  2015 
Cash collateral deposits for commodity purchases $-  $167 
Insurance premiums  1,403   1,609 
Rents, license and other  694   813 
  $2,097  $2,589 

Property and Equipment

Expendituresthe intermediate use marketplace. As typical 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 evaluationsindustry, these transactions are made onpursuant to the terms of forward month commodity purchase and/or sale contracts. Some of these contracts meet the definition of a quarterly basis.  If an exploratory wellderivative instrument, and therefore, we account for these contracts at fair value, unless the normal purchase and sale exception is determined to be nonproductive, the costsapplicable. These types of drilling the wellunderlying contracts are charged to expense. Costs incurred to drill and complete development wells, including dry holes, are capitalized.  As of December 31, 2016 and 2015, the Company had no unevaluated or ‟suspended” exploratory drilling costs.

Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method.  The reserve base 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 volumesstandard for the period.  All other propertyindustry and equipment is depreciated usingare the straight-line method over the estimated average useful livesgoverning document for our crude oil marketing segment. None of three to twenty years.our derivative instruments have been designated as hedging instruments.

The Company reviews its long-lived assets for impairment whenever there is evidence that the carrying value of such assets may not be recoverable.  Any impairment recognized is permanent and may not be restored.  No impairment triggers were identifiedEmployee Benefits

We maintain a 401(k) savings plan for the Company’s Marketingbenefit of our employees. We do not maintain any other pension or Transportation property and equipment during the years ending December 31, 2016, 2015 or 2014.  Producing oil and gas properties are reviewed on a field-by-field basis.  For properties requiring impairment, the fair value is estimated based on an internal discounted cash flow model.  Cash flows are developed based on estimated future production and prices and then discounted using a market based rate of return consistent with that used by the Company in evaluating cash flows for other assets of a similar nature.  This fair value measure depends highly on management’s assessment of the likelihood of continued exploration efforts in a given 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.

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.
37
Impairment provisions including in oil and gas segment operating lossesretirement plans. Our 401(k) plan contributory expenses were as follows (in thousands):

  2016  2015  2014 
Producing property impairments $30  $10,324  $4,001 
Non-producing property impairments $283  $1,758  $4,008 
  $313  $12,082  $8,009 

Fair value measurements for producing oil and gas properties that were subject to fair value impairment for the years ended December 31, 2016 and 2015 summarize as follows (inperiods indicated (in thousands):

  Producing Properties 
  Subject to Fair 
  Value Impairment 
  2016  2015 
Net book value at January 1 $70  $18,744 
Property additions  2   2,117 
Depletion taken  (15)  (4,454)
Impairment valuation loss  (30)  (10,324)
Net book value at December 31 $27  $6,083 

Capitalized costs for non-producing oil and gas leasehold interests are categorized as follows (in thousands):

  December 31,  December 31, 
  2016  2015 
       
Napoleonville Louisiana acreage $-  $49 
South Texas project acreage  -   - 
Wyoming and other acreage  -   182 
Total Non-producing Leasehold Costs $-  $231 

Since the Company is generally not the operator of its oil and gas property interests, it does not maintain underlying detail acreage data and is dependent on the operator when determining which specific acreage will ultimately be drilled.  However, the capitalized cost detail on a property-by-property basis is reviewed by management and deemed impaired if development is not anticipated prior to lease expiration.  Onshore leasehold periods are normally three years and may contain renewal options.  Capitalized cost activity on non-producing leasehold were as follows (in thousands):

  Leasehold Costs 
  2016  2015 
Net book value January 1 $231  $959 
Leasehold additions  52   106 
Advanced royalty payment  -   529 
In-process wells suspended  -   395 
Property sales  -   - 
Impairments valuation loss  (283)  (1,758)
Net book value December 31 $-  $231 

The Company sold certain used trucks and equipment from its marketing and transportation segments and recorded net pre-tax gains as follows (in thousands):

  2016  2015  2014 
Sales of used trucks and equipment $1,966  $535  $1,028 

38
Investments
 Year Ended December 31,
 2017 2016 2015
      
Contributory expenses$734
 $757
 $768

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 $2.2 million cash payment.  Bencap provides medical insurance brokerage and medical claims auditing services to employers utilizing ERISA governed employee benefit plans.  The Company has accounted for this investment under the equity method of accounting.

During the third quarter of 2016, the Company completed a review of its equity method investment in Bencap and determined there was an other than temporary impairment.  Underlying this decision are the terms of the investment agreement where Bencap has the option to request borrowings up to $1.5 million (on or after December 5, 2016 but before October 31, 2018) that the Company must provide or forfeit its 30% member interest.  During the third quarter of 2016, management of the Company determined that it was unlikely to provide additional funding due to Bencap’s lower than projected revenue growth and operating losses since investment inception.  As a result, the Company recognized a net loss of $1.4 million from its investment in Bencap as of September 30, 2016.  This loss included a pre-tax impairment charge of $1.7 million and pre-tax losses from the equity method investment of $0.5 million. In February 2017, Bencap requested additional funding of approximately $0.5 million and the Company declined the additional funding request.

In April 2016 the Company, through its ARMM subsidiary, acquired an approximate 15% equity interest (less than 3% voting interest) in VestaCare, Inc., a California corporation (“VestaCare”), for a $2.5 million cash payment.  VestaCare provides an array of software as a service (“SaaS”) electronic payment technologies to medical providers, payers and patients including VestaCare’s most recent product offering, VestaPay™.  VestaPay™ allows medical care providers to structure fully automated and dynamically updating electronic payment plans for their patients.    The Company does not currently have any plans to pursue additional medical-related investments.

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):

  As of December 31, 
  2016  2015 
Insurance collateral deposits $5,032  $6,531 
State collateral deposits  143   140 
Materials and supplies  354   292 
  $5,529  $6,963 

Revenue Recognition

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

Most all crude oil purchase and sale contracts qualify and are designated as non-trading activities and the Company considers such contracts as normal purchases and sales activity.  For normal purchases and sales the Company’s customers are invoiced monthly based upon contractually agreed upon terms with revenue recognized in the month in which the physical product is delivered to the customer.  Such sales are recorded gross in the financial statements because the Company takes title, has risk of loss for the products, is the primary obligor for the purchase, establishes the sale price independently with a third party, and maintains credit risk associated with the sale of the product.
39

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 as follows (in thousands):

  2016  2015  2014 
Revenue gross-up $314,270  $480,111  $1,272,034 

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.

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 used to support crude oil purchases within the marketing segment.  This facility is collateralized by the eligible accounts receivable within the segment.  Stand-by letters of credit issued were as follows (in thousands):

  As of December 31, 
  2016  2015 
Stand-by letters of credit $-  $1,000 

The issued stand-by letters of credit are cancelled as the underlying purchase obligations are satisfied by cash payment when due.  The letter of credit facility places certain restrictions on the Company’s Gulfmark Energy, Inc. subsidiary.  Such restrictions included the maintenance of a combined 1.1 to 1.0 current ratio and the maintenance of positive net earnings excluding inventory valuation changes, as defined, among other restrictions.  The Company is currently in compliance with all such financial covenants.

Statement of Cash Flows

There were no significant non-cash financing activities in any of the periods reported.  Statement of cash flow items include the following (in thousands):

  2016  2015  2014 
          
Interest paid $2  $13  $2 
             
Federal and state tax paid $2,589  $6,197  $8,169 
             
State tax refund $-  $-  $18 

40

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, 
  2016  2015  2014 
          
Property and equipment additions $679  $1,707  $1,137 

Earnings perPer 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 each of the years ended December 31, 2017, 2016 2015 and 2014.2015. 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 forming the foundation for calculating depreciation, depletion and amortization and for estimating cash flows when assessing impairment triggers and 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 such items and their respective tax basis (See also Note (2) to consolidated financial statements).

Use of Derivative Instruments

The Company’s marketing segment is involved in the purchase and sale of crude oil.  The Company seeks to make a profit by procuring this commodity as it is produced and then delivering the material to end users or the intermediate use marketplace.  As is typical for the industry, such transactions are made pursuant to the terms of forward month commodity purchase and/or sale contracts.  Some of these contracts meet the definition of a derivative instrument and therefore, the Company accounts for such contracts at fair value, unless the Company foregoes the trading designation and the normal purchase and sale exception is made.  Such underlying contracts are standard for the industry and are the governing document for the Company’s crude oil wholesale distribution businesses. None of the Company’s derivative instruments have been designated as hedging instruments.  Derivatives instruments are presented net on the balance sheet where the Company has a legal right of offset.  The accounting methodology utilized by the Company for its commodity contracts is further discussed below under the caption ‟Fair Value Measurements”.
41

The estimated fair value of forward month commodity contracts (derivatives) is reflected in the accompanying Consolidated Balance Sheet as of December 31, 2016 as follows (in thousands):

  Balance Sheet Location and Amount 
  Current  Other  Current  Other 
  Assets  Assets  Liabilities  Liabilities 
Asset Derivatives            
- Fair Value Commodity            
Contracts at Gross Valuation $378  $-  $-  $- 
Liability Derivatives                
- Fair Value Commodity                
Contracts at Gross Valuation  -   -   330   - 
Less Counterparty Offsets  (266)  -   (266)  - 
As Reported Fair Value Contracts $112  $-  $64  $- 

As of December 31, 2016, two contracts comprised the Company’s derivative valuations.  These contracts encompass approximately 65 barrels of diesel fuel per day during January through March 2017 and 145,000 barrels of crude oil during January 2017 through April 2017.

The estimated fair value of forward month commodity contracts (derivatives) is reflected in the accompanying Consolidated Balance Sheet as of December 31, 2015 as follows (in thousands):

  Balance Sheet Location and Amount 
  Current  Other  Current  Other 
  Assets  Assets  Liabilities  Liabilities 
Asset Derivatives            
- Fair Value Commodity            
Contracts at Gross Valuation $-  $-  $-  $- 
Liability Derivatives                
- Fair Value Commodity                
Contracts at Gross Valuation  -   -   195   - 
Less Counterparty Offsets  -   -   -   - 
As Reported Fair Value Contracts $-  $-  $195  $- 

As of December 31, 2015, one contract comprised the Company’s derivative valuations.  The purchase and sale contract encompasses approximately 65 barrels of diesel fuel per day in each of January, February and March 2016.

The Company only enters into commodity contracts with creditworthy counterparties or obtains collateral support for such activities.  As of December 31, 2016 and 2015, 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, 2016, 2015 and 2014 as follows (in thousands):

  Gain (Loss) 
Location 2016  2015  2014 
Revenues – marketing $243  $(188) $312 

42

Fair Value Measurements

The carrying amountamounts reported in the Consolidated Balance Sheetconsolidated balance sheets 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

Our 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 either (i) actual market data or (ii) assumptions that other market participants would use whenin pricing an asset or liability, including estimates of risk, in the principal market of the asset or liability at a specified measurement date. Recognized valuation techniques employ inputs such as contractual prices, quoted market prices or rates, operating costs, discount factors and the Company uses abusiness growth rates. These inputs may be either readily observable, corroborated by market data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the highest extent possible. Accordingly, we utilize valuation techniques (such as the market approach) that maximize the use of observable inputs and minimize the use of unobservable inputs.

A three-tier hierarchy has been established that classifies fair value amounts recognized in the financial statements based on the observability of three levels that prioritizes the informationinputs 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.estimate such fair values.  The hierarchy considers fair value hierarchy givesamounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3).  At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


The characteristics of the highest priority to quoted prices in active markets and the lowest priority to unobservable data.  The fair value amounts classified within each level of the hierarchy is summarizedare described as follows:

Level 1 –fair values are based on quoted prices, which are available in active markets for identical assets or liabilities that may be accessed atas of the measurement date. Active markets are defined as those in which transactions for the assetidentical assets or liabilityliabilities occur inwith sufficient frequency and volumeso as to provide pricing information on an ongoing basis. For Level 1 valuation of marketable securities, the Company utilizeswe utilize market quotations provided by itsour primary financial institution and forinstitution. For the valuations of derivative financial instruments, the Company utilizeswe utilize the New York Mercantile Exchange ‟NYMEX”(“NYMEX”) for suchcertain commodity valuations.

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

Level 3 – Unobservablefair values are based on unobservable market data inputs for assets or liabilities.

AsFair value contracts consist of December 31, 2016, the Company’sderivative financial instruments and 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 we elect, cash flow hedge accounting. We had no contracts designated for hedge accounting during any of the current reporting periods (see Note 10 for further information).

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

Impairment Testing for Long-Lived Assets

Long-lived assets (primarily property and equipment) are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written-down to their estimated fair values. The carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset’s carrying value exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge equal to the excess of the asset’s carrying value over its estimated fair value is recorded. Fair value is defined as the price that would be received to sell an asset or be paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. We measure fair value using market price indicators or, in the absence of such data, appropriate valuation techniques. See Note 10 for information regarding impairment charges related to long-lived assets.

Income Taxes

Income taxes are accounted for using the asset and liability method. Under this approach, deferred tax assets and liabilities are summarizedrecognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of such items and categorizedtheir respective tax basis (see Note 11 for further information). On December 22, 2017, the Tax Cut and Jobs Act was enacted into law resulting in a reduction in the federal corporate income tax rate from 35 percent to 21 percent for years beginning in 2018, which will impact our deferred tax assets and liabilities.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Inventory

Inventory consists of crude oil held in storage tanks and at third-party pipelines as part of our crude oil marketing operations. Crude oil inventory is carried at the lower of average cost or net realizable value.

Letter of Credit Facility

We maintain a Credit and Security Agreement with Wells Fargo Bank, National Association to provide up to a $60 million stand-by letter of credit facility used to support crude oil purchases within our crude oil marketing segment and for other purposes. We are currently using the letter of credit facility for a letter of credit related to our insurance program. This facility is collateralized by the eligible accounts receivable within the crude oil marketing segment and expires on August 27, 2019.

The issued stand-by letters of credit are canceled as the underlying purchase obligations are satisfied by cash payment when due. The letter of credit facility places certain restrictions on Gulfmark Energy, Inc., one of our wholly owned subsidiaries. These restrictions include 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. We are currently in compliance with all such financial covenants. At December 31, 2017, we had $2.2 million outstanding under this facility. No letter of credit amounts were outstanding at December 31, 2016.

Property and Equipment

Property and equipment is recorded at cost. Expenditures for additions, improvements and other enhancements to property and equipment are capitalized, and minor replacements, maintenance and repairs that do not extend asset life or add value are charged to expense as incurred. When property and equipment assets are retired or otherwise disposed of, the related cost and accumulated depreciation is removed from the accounts and any resulting gain or loss is included in results of operations in operating costs and expenses for the respective period. Property and equipment, except for land, is depreciated using the straight-line method over the estimated average useful lives of three to twenty years.

Oil and natural gas exploration and development expenditures were 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, were capitalized. Exploratory drilling costs were initially capitalized until the properties were evaluated and determined to be either productive or nonproductive.  These evaluations were made on a quarterly basis.  If an exploratory well was determined to be nonproductive, the costs of drilling the well were charged to expense. Costs incurred to drill and complete development wells, including dry holes, were capitalized.  At December 31, 2017 and 2016, we had no unevaluated or “suspended” exploratory drilling costs. In April 2017, our upstream crude oil and natural gas exploration and production subsidiary was deconsolidated and accounted for under the cost method of accounting (see Notes 1 and 3 for further discussion).

We capitalize interest costs, if any, incurred in connection with major capital expenditures while the asset is in its construction phase. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s estimated useful life as a component of depreciation expense. When capitalized interest is recorded, it reduces interest expense.

Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related long-lived asset. ARO amounts are measured at their estimated fair value using expected present value techniques. Over time, the ARO liability is accreted to its present value (through accretion expense), and the capitalized amount is depreciated over the remaining useful life of the related long-lived asset. We will incur a gain or loss to the extent that our ARO liabilities are not settled at their recorded amounts.

See Note 5 for additional information regarding our property and equipment and AROs.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Revenue Recognition

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

Most crude oil purchase and sale contracts qualify and are designated as non-trading activities, and we consider these contracts as normal purchases and sales activity. For normal purchases and sales, our 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. These sales are recorded on a gross basis in the financial statements because we take title, have risk of loss for the products, are the primary obligor for the purchase, establish the sale price independently with a third party and maintain 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. These buy/sell arrangements are reflected on a net revenue basis in the accompanying consolidated financial statements.

Reporting these crude oil contracts on a gross revenue basis would increase our reported revenues as follows for the periods indicated (in thousands):
 Year Ended December 31,
 2017 2016 2015
      
Revenue gross-up$203,095
 $314,270
 $480,111

Transportation segment customers are invoiced, and the related revenue is recognized as the service is provided.

Recent Accounting Pronouncements

Revenue Recognition. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Codification Topic 606, Revenue from Contracts with Customers (“ASC 606”). The new accounting standard, along with its related amendments, replaces the current rules-based GAAP governing revenue recognition with a principles-based approach. Under the new standard, a company recognizes revenue when it satisfies a performance obligation by transferring a promised good or service to a customer at an amount that reflects the consideration it expects to receive in exchange for those goods and services. The standard also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments. ASC 606 is effective for interim and annual reporting periods beginning after December 15, 2017 and may be applied on either a full or modified retrospective basis.
We adopted the new standard and all related amendments on January 1, 2018 using the modified retrospective approach. This approach required us to apply the new revenue standard to (i) all new revenue contracts entered into after January 1, 2018 and (ii) all existing revenue contracts open as of January 1, 2018, with a cumulative adjustment to retained earnings, if applicable.  In accordance with this approach, our consolidated revenues for periods prior to January 1, 2018 will not be restated. In addition, no cumulative adjustment will be required to be made to our retained earnings, as there are no material differences in the nature, amount, timing or uncertainty of revenues recognized following our adoption of this new standard on January 1, 2018. We have also evaluated our business processes, systems and controls to ensure the accuracy and timeliness of the recognition and disclosure requirements under the new revenue guidance.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Leases. In February 2016, the FASB issued ASC 842, Leases (in thousands):“ASC 842”), which requires substantially all leases (with the exception of leases with a term of one year or less) to be recorded on the balance sheet using a method referred to as the right-of-use (“ROU”) asset approach. We plan to adopt the new standard on January 1, 2019 using the modified retrospective approach.

  Market Data Inputs       
  Gross Level 1  Gross Level 2  Gross Level 3  Counterparty    
  Quoted Prices  Observable  Unobservable  Offsets  Total 
Derivatives (fair value contracts)
               
- Current assets $-  $378  $-  $(266) $112 
- Current liabilities  -   (330)  -   266   (64)
Net Value $-  $48  $-  $-  $48 

43The new standard introduces two lease accounting models, which result in a lease being classified as either a “finance” or “operating” lease on the basis of whether the lessee effectively obtains control of the underlying asset during the lease term. A lease would be classified as a finance lease if it meets one of five classification criteria, four of which are generally consistent with current lease accounting guidance. By default, a lease that does not meet the criteria to be classified as a finance lease will be deemed an operating lease. Regardless of classification, the initial measurement of both lease types will result in the balance sheet recognition of a ROU asset representing a company’s right to use the underlying asset for a specified period of time and a corresponding lease liability. The lease liability will be recognized at the present value of the future lease payments, and the ROU asset will equal the lease liability adjusted for any prepaid rent, lease incentives provided by the lessor, and any indirect costs.


The subsequent measurement of each type of lease varies. Leases classified as a finance lease will be accounted for using the effective interest method. Under this approach, a lessee will amortize the ROU asset (generally on a straight-line basis in a manner similar to depreciation) and the discount on the lease liability (as a component of interest expense). Leases classified as an operating lease will result in the recognition of a single lease expense amount that is recorded on a straight-line basis (or another systematic basis, if more appropriate).

We have started the process of reviewing our lease agreements in light of the new guidance. Although we are in the early stages of our ASC 842 implementation project, we anticipate that this new lease guidance will cause significant changes to the way leases are recorded, presented and disclosed in our consolidated financial statements.


Note 3. Subsidiary Bankruptcy, Deconsolidation and Sale

Bankruptcy Filing, Deconsolidation and Sale

On April 21, 2017, AREC filed a voluntary petition in the Bankruptcy Court seeking relief under the Bankruptcy Code. AREC operated its business and managed its properties as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and order of the Bankruptcy Court. As a result of December 31, 2015,AREC’s bankruptcy filing, AE ceded its authority to the Company’s fair valueBankruptcy Court, and AE management could not carry on AREC activities in the ordinary course of business without Bankruptcy Court approval. AE managed the day-to-day operations of AREC, but did not have discretion to make significant capital or operating budgetary changes or decisions or to purchase or sell significant assets, as AREC’s material decisions were subject to review and approval by the Bankruptcy Court. For these reasons, we concluded that AE lost control of AREC, and no longer had significant influence over AREC during the pendency of the bankruptcy. Therefore, we deconsolidated AREC effective with the filing of the Chapter 11 bankruptcy in April 2017.

In order to deconsolidate AREC, the carrying values of the assets and liabilities are summarizedof AREC were removed from our consolidated balance sheet as of April 30, 2017, and categorized as follows (we recorded our investment in thousands):

  Market Data Inputs       
  Gross Level 1  Gross Level 2  Gross Level 3  Counterparty    
  Quoted Prices  Observable  Unobservable  Offsets  Total 
Derivatives (fair value contracts)
               
- Current assets $-  $-  $-  $-  $- 
- Current liabilities  -   (195)  -   -   (195)
Net Value $-  $(195) $-  $-  $(195)

When determiningAREC at its estimated fair value measurements, the Company makes credit valuation adjustments to reflect both its own nonperformance risk and its counterparty’s nonperformance risk.  When adjustingof approximately $5.0 million. We determined the fair value of derivative contractsour investment based upon bids we received in an auction process (see Note 1 for further discussion). We also determined that the effectestimated fair value 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 scoresour investment in AREC was expected to evaluate the likelihood of default by the Company orbe lower than its counterparties.  As of December 31, 2016 and 2015, credit valuation adjustments were not significantnet book value immediately prior to the overall valuation of the Company’s fair value contracts.deconsolidation. As a result, during the second quarter of 2017, we recorded a non-cash charge of approximately $1.6 million associated with the deconsolidation of AREC, which reflected the excess of the net assets of AREC over its estimated fair value based on the expected sales transaction price of approximately $5.0 million, net of estimated transaction costs. Subsequent to the deconsolidation of AREC, we accounted for our investment in AREC using the cost method of accounting because AE did not exercise significant influence over the operations of AREC due to the Chapter 11 filing.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


On August 1, 2017, a hearing was held before the Bankruptcy Court seeking approval of asset purchase and sales agreements under Section 363 of the Bankruptcy Code with three unaffiliated parties to purchase AREC’s crudeoil and natural gas assets for aggregate cash proceeds of approximately $5.2 million. The Bankruptcy Court approved the asset purchase and sales agreements, and we closed on the sales of these assets during the third quarter of 2017.

In October 2017, AREC submitted its liquidation plan to the Bankruptcy Court for approval. In connection with the sales of these assets and liabilities are includedsubmission of the liquidation plan, we recognized an additional loss of $1.9 million during the third quarter of 2017, which represents the difference between the proceeds we expect to be paid upon settlement of the bankruptcy, net of anticipated remaining closing costs identified as part of the liquidation plan, and the book value of our cost method investment. In December 2017, we received proceeds of approximately $2.8 million from AREC related to the settlement of a portion of the bankruptcy process. The bankruptcy process is expected to be completed with a confirmed plan during 2018.

DIP Financing – Related Party Relationship

In connection with the bankruptcy filing, AREC entered into a Debtor in their entiretyPossession Credit and Security Agreement with AE (“DIP Credit Agreement”) dated as of April 25, 2017, in an aggregate amount of up to $1.25 million, of which the funds were to be used by AREC solely to fund operations through August 11, 2017. Loans under the DIP Credit Agreement accrued interest at a rate of LIBOR plus 2.0 percent per annum and were due and payable upon the earlier of (a) twelve months after the petition date, (b) the closing of the sale of substantially all of AREC’s assets, (c) the effective date of a Chapter 11 plan of reorganization of AREC, and (d) the date that the DIP loan was accelerated upon the occurrence of an event of default, as defined in the fair value hierarchy.

The following table illustratesDIP Credit Agreement. AREC borrowed approximately $0.4 million under the factors impactingDIP Credit Agreement, and the change inamount was repaid during the net valuethird quarter of 2017 with proceeds from the sales of the Company’s fair value contractsassets.


Note 4. Prepayments and Other Current Assets

The components of prepayments and other current assets were as follows at the dates indicated (in thousands):
 December 31,
 2017 2016
    
Insurance premiums$425
 $1,403
Rents, licenses and other839
 694
Total$1,264
 $2,097



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 5. Property and Equipment

The historical costs of our property and equipment and related accumulated depreciation balances were as follows at the dates indicated (in thousands):
 Estimated    
 Useful Life December 31,
 in Years 2017 2016
      
Tractors and trailers (1)
5 – 6 $88,065
 $89,576
Oil and gas (successful efforts)
 —
 62,784
Field equipment2 – 5 18,490
 18,282
Buildings5 – 39 15,727
 15,707
Office equipment1 – 5 1,929
 1,913
Land  1,790
 1,790
Construction in progress  275
 596
Total  126,276
 190,648
Less accumulated depreciation  (96,914) (144,323)
Property and equipment, net  $29,362
 $46,325
______________
(1)2017 includes assets held under capital leases. During the third quarter of 2017, we entered into capital leases for certain tractors in our marketing segment. Gross property and equipment and accumulated amortization associated with assets held under capital leases were $1.8 million and $0.1 million, respectively, at December 31, 2017 (see Note 13 for further information).

Components of depreciation, depletion and amortization expense were as follows for the year endedperiods indicated (in thousands):
 Year Ended December 31,
 2017 2016 2015
Depreciation, depletion and amortization, excluding amounts     
under capital leases$13,478
 $18,792
 $23,717
Amortization of property and equipment under capital leases121
 —
 —
Total depreciation, depletion and amortization$13,599
 $18,792
 $23,717

Crude Oil and Natural Gas Exploration and Production Assets

Our subsidiary that owned the upstream crudeoil and natural gas exploration and production assets was deconsolidated effective with its bankruptcy filing in April 2017 and subsequently accounted for as a cost method investment (see Note 3). These upstream crude oil and natural gas exploration and production assets were sold during the third quarter of 2017. We have no further interest in these assets.

Impairment provisions including in upstream crude oil and natural gas exploration and production segment operating losses were as follows for the periods indicated (in thousands):
 Year Ended December 31,
 2017 2016 2015
      
Producing property impairments$—
 $30
 $10,324
Non-producing property impairments3
 283
 1,758
Total crude oil and natural gas impairments$3
 $313
 $12,082

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


At December 31, 2017 and 2016, (in thousands):we had no capitalized costs for non-producing crude oil and natural gas leasehold interests.

  Level 1  Level 2    
  Quoted Prices  Observable  Total 
Net Fair Value January 1 $-  $(195) $(195)
- Net realized (gains) losses  -   195   195 
- Net unrealized gains (losses)  -   48   48 
Net Fair Value December 31 $-  $48  $48 

The following table illustrates the factors impacting the change in theGains on sales of assets

We sold certain used trucks and equipment from our marketing and transportation segments and recorded net value of the Company’s fair value contractspre-tax gains as follows for the year ended December 31, 2015 (inperiods indicated (in thousands):

  Level 1  Level 2    
  Quoted Prices  Observable  Total 
Net Fair Value January 1 $-  $(7) $(7)
- Net realized (gains) losses  -   7   7 
- Net unrealized gains (losses)  -   (195)  (195)
Net Fair Value December 31 $-  $(195) $(195)

44
 Year Ended December 31,
 2017 2016 2015
      
Sales of used trucks and equipment$594
 $1,966
 $535

Asset Retirement Obligations

The Company records a liabilityWe record AROs for the estimated retirement costs associated with certain tangible long-lived assets. The estimated fair value of asset retirement obligationsAROs 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 gainan increase or lossdecrease to expense is recognized. A summary of the Company’s asset retirement obligationsour AROs is presented as follows (for the periods indicated (in thousands):
 Year Ended December 31,
 2017 2016 2015
      
ARO liability beginning balance$2,329
 $2,469
 $2,464
Liabilities incurred18
 162
 39
Accretion of discount58
 92
 93
Liabilities settled(261) (394) (127)
Deconsolidation of subsidiary (1)
(871) —
 —
ARO liability ending balance$1,273
 $2,329
 $2,469
_______________
(1)Relates to our upstream crude oil and natural gas exploration and production subsidiary that was deconsolidated in April 2017 as a result of its bankruptcy filing (see Note 3 for further information).


Note 6. Cash Deposits and Other Assets

Components of cash deposits and other assets were as follows at the dates indicated (in thousands):
 December 31,
 2017 2016
    
Amounts associated with liability insurance program:   
Insurance collateral deposits$3,767
 $2,599
Excess loss fund2,284
 1,450
Accumulated interest income814
 812
Other amounts:   
State collateral deposits57
 143
Materials and supplies273
 354
Other37
 171
Total$7,232
 $5,529

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


We have established certain deposits to support participation in thousands):

  2016  2015 
Balance on January 1 $2,469  $2,464 
-Liabilities incurred  162   39 
-Accretion of discount  92   93 
-Liabilities settled  (394)  (127)
Balance on December 31 $2,329  $2,469 


Recent Accounting Pronouncements

In May 2014,our liability insurance program and remittance of state crude oil severance taxes and other state collateral deposits. Insurance collateral deposits are held by the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which supersedesinsurance company to cover past or potential open claims based upon a percentage of the revenue recognition requirementsmaximum assessment under our insurance policies. Excess amounts in “Revenue Recognition (Topic 605).” Topic 606 is based on the core principleour loss fund represent premium payments in excess of claims incurred to date that revenue is recognized to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects towe may be entitled to recover through settlement or commutation as claim periods are closed. Interest income is earned on the majority of amounts held by the insurance companies and will be paid to us upon settlement of policy years.

Insurance collateral deposits are invested at the discretion of our insurance carrier. This fair value measure relies on inputs from quoted prices for similar assets and is thus categorized as a “Level 3” valuation in exchangethe fair value hierarchy (see Note 10 for those goods or services. Topic 606 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and changesfurther information).


Note 7. Investments in judgments and assets recognized from costs incurred to obtain or fulfill a contract.Unconsolidated Affiliates


Topic 606 is effective for fiscal years beginning afterAt December 15,31, 2017, and interim periods within those years, with early adoption permittedwe had no remaining balances in 2017; however weour medical-related investments. We currently do not planhave any plans to adoptpursue additional medical-related investments.

Bencap

In December 2015, we formed a new wholly owned subsidiary, Adams Resources Medical Management, Inc. (“ARMM”), and in January 2016, ARMM acquired a 30 percent member interest in Bencap LLC (“Bencap”) for a $2.2 million cash payment. Bencap provides medical insurance brokerage and medical claims auditing services to employers utilizing ERISA governed employee benefit plans. We accounted for this investment under the standard early. Entities will haveequity method of accounting.

Under the terms of the investment agreement, Bencap had the option to apply the standard using a full retrospectiverequest borrowings from us of up to $1.5 million (on or modified retrospective adoption method. The Company has not yet selected a transition method.  The Company has a team in place to analyze the impact of Update 2014-09, and the related ASU's, across all revenue streams to evaluate the impact of the new standard on revenue contracts.   This includes reviewing current accounting policies and practices to identify potential differencesafter December 5, 2016 but before October 31, 2018) that would result from applying the requirements under the new standard. Our evaluation of the impact on our Consolidated Financial Statements and related disclosures is ongoing and not complete.  The Company is continuing our review of contracts relative to the provisions of Topic 606.

In July 2015, the FASB amended the existing accounting standards for inventorywe were required to provide for the measurement of inventory at theor forfeit our 30 percent member interest. During 2016, our management determined that we were unlikely to provide additional funding due to Bencap’s 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,than projected revenue growth and interim periods thereafter, with early adoption permitted.  The adoption of this guidance did not have an impact on the  Consolidated Financial Statements.
45

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” This standard requires, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company expects to adopt this standard in the first quarter of 2019 and is currently evaluating the impact of this standard on our Consolidated Financial Statements and related disclosures. In connection with our assessment work, The Company has a team in place to analyze the impact of ASU 2016-02 and is continuingoperating losses since investment inception. We completed a review of our contracts relativeequity method investment in Bencap during 2016 and determined that there was an other than temporary impairment. During the third quarter of 2016, we recognized an after-tax net loss of $1.4 million to write-off our investment in Bencap, which consisted of a pre-tax impairment charge of approximately $1.7 million, pre-tax losses from the provisionsequity method investment of $0.5 million and an income tax benefit of $0.8 million. In February 2017, in accordance with the terms of the lease standard.investment agreement, Bencap requested additional funding of approximately $0.5 million from us. We declined the additional funding request and as a result, forfeited our 30 percent member interest in Bencap. At December 31, 2017, we had no further ownership interest in Bencap.

VestaCare

In AugustApril 2016, ARMM acquired an approximate 15 percent equity interest (less than 3 percent voting interest) in VestaCare, Inc., a California corporation (“VestaCare”), for a $2.5 million cash payment. VestaCare provides an array of software as a service (SaaS) electronic payment technologies to medical providers, payers and patients including VestaCare’s most recent product offering, VestaPay™. VestaPay™ allows medical care providers to structure fully automated and dynamically updating electronic payment plans for their patients. We account for this investment under the FASB issued ASU No. 2016-15, “Statementcost method of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.” This standard is intended to reduce existing diversity in practice in how certain transactions are presented onaccounting. During the statement of cash flows. The standard is effective for interim and annual reporting periods beginning after December 15, 2017, although early adoption is permitted. The guidance requires application using a retrospective transition method. The Company will adopt ASU No. 2016-15 in the firstthird quarter of 2017, we reviewed our investment in VestaCare and has determined that the amendmentcurrent projected operating results did not support the carrying value of the investment. As such, during the third quarter of 2017, we recognized an impairment charge of $2.5 million to write-off our investment in VestaCare. At December 31, 2017, we continue to own an approximate 15 percent equity interest in VestaCare.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


AREC

As a result of AREC’s voluntary bankruptcy filing in April 2017 and our loss of control of AREC, we deconsolidated AREC in April 2017, and we recorded our investment in this subsidiary under the cost method of accounting. We recorded a non-cash charge during the second quarter of 2017 of approximately $1.6 million associated with the deconsolidation of AREC, which reflected the excess of the net assets of AREC over its estimated fair value based on the expected sales transaction price, net of estimated transaction costs. As a result of the sale of substantially all of AREC’s assets during the third quarter of 2017, we recognized an additional loss of $1.9 million, which represents the difference between the net proceeds we expect to be paid upon settlement of the bankruptcy, net of anticipated remaining closing costs identified as part of the liquidation plan, and the book value of our cost method investment. In December 2017, we received proceeds of approximately $2.8 million from AREC related to the settlement of a portion of the bankruptcy process. At December 31, 2017, our remaining investment in AREC was $0.4 million (see Note 3 for further information). The remaining investment will be removed upon settlement of the bankruptcy, which is anticipated during the first half of 2018.



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 8. Segment Reporting

Historically, our three reporting segments have been: (i) crude oil marketing, transportation and storage, (ii) tank truck transportation of liquid chemicals and dry bulk and ISO tank container storage and transportation, and (iii) upstream crude oil and natural gas exploration and production. Our upstream crude oil and natural gas exploration and production wholly owned subsidiary filed for bankruptcy in April 2017 (see Note 3 for further information), and as a result of our loss of control of the wholly owned subsidiary, AREC was deconsolidated and is accounted for under the cost method of accounting. AREC remained a reportable segment until its deconsolidation, effective April 30, 2017.

Information concerning our various business activities was follows for the periods indicated (in thousands):
 Reporting Segments  
 Marketing Transportation Oil and Gas Total
        
Year Ended December 31, 2017       
Revenues$1,267,275
 $53,358
 $1,427
 $1,322,060
Segment operating (losses) earnings (1) (2)
11,700
 (544) 53
 11,209
Depreciation, depletion and amortization7,812
 5,364
 423
 13,599
Property and equipment additions (3)
468
 351
 1,825
 2,644
        
Year Ended December 31, 2016       
Revenues$1,043,775
 $52,355
 $3,410
 $1,099,540
Segment operating (losses) earnings (1)
17,045
 (48) (533) 16,464
Depreciation, depletion and amortization9,997
 7,249
 1,546
 18,792
Property and equipment additions1,321
 6,868
 295
 8,484
        
Year Ended December 31, 2015       
Revenues$1,875,885
 $63,331
 $5,063
 $1,944,279
Segment operating (losses) earnings (1) (4)
22,895
 3,701
 (19,016) 7,580
Depreciation, depletion and amortization11,097
 7,554
 5,066
 23,717
Property and equipment additions2,126
 6,579
 2,369
 11,074
_________________
(1)Our marketing segment’s operating earnings included inventory liquidation gains of $3.3 million and $8.2 million for the years ended December 31, 2017 and 2016, respectively, and inventory valuation losses of $5.4 million for the year ended December 31, 2015.
(2)Segment operating (losses) earnings includes approximately $0.4 million of costs related to a voluntary early retirement program that was implemented in August 2017.
(3)Our marketing segment’s property and equipment additions do not include approximately $1.8 million of tractors acquired during the third quarter of 2017 under capital leases. See Note 13 for further information.
(4)
Our crude oil and natural gassegment’s operating earnings included property impairments of $12.1 million for the year ended December 31, 2015.


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Segment operating earnings reflect revenues net of operating costs and depreciation, depletion and amortization expense and are reconciled to earnings (losses) before income taxes and investment in unconsolidated affiliate, as follows for the periods indicated (in thousands):
 Year Ended December 31,
 2017 2016 2015
      
Segment operating earnings$11,209
 $16,464
 $7,580
General and administrative (1)
(9,707) (10,410) (9,939)
Operating earnings (losses)1,502
 6,054
 (2,359)
Loss on deconsolidation of subsidiary(3,505) —
 —
Impairment of investment in unconsolidated affiliate(2,500) —
 —
Interest income1,103
 582
 327
Interest expense(27) (2) (13)
(Losses) earnings before income taxes and investment     
in unconsolidated affiliate$(3,427) $6,634
 $(2,045)
_______________
(1)General and administrative expenses for the year ended December 31, 2017 included approximately $1.0 million of costs related to a voluntary early retirement program we implemented in August 2017.

Identifiable assets by industry segment were as follows at the dates indicated (in thousands):
 December 31,
 2017 2016 2015
      
Reporting segment:     
Marketing$134,745
 $107,257
 $96,723
Transportation29,069
 32,120
 35,010
Oil and Gas (1)
425
 7,279
 8,930
Cash and other118,465
 100,216
 102,552
Total assets$282,704
 $246,872
 $243,215
____________________
(1)At December 31, 2017, amount represents our remaining cost method investment in this segment. See Note 3 for further information.

Intersegment sales are insignificant. Other identifiable assets are primarily corporate cash, corporate accounts receivable, investments and properties not identified with any specific segment of our business. Accounting policies for transactions between reportable segments are consistent with applicable accounting policies as disclosed herein.


Note 9. Transactions with Affiliates

We enter into certain transactions in the normal course of business with affiliated entities including direct cost reimbursement for shared phone and administrative services. In addition, we lease our corporate office space from an affiliated entity.

We utilize our former affiliate, Bencap, to administer certain of our employee medical benefit programs including a detail audit of individual medical claims (see Note 13 for further information). Bencap earns a fee from us for providing such services at a discounted amount from its standard charge to non-affiliates. As discussed in Note 7, at December 31, 2017, we have no further ownership interest in Bencap.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Activities with affiliates were as follows for the periods indicated (in thousands):
 Year Ended December 31,
 2017 2016 2015
      
Overhead recoveries (1)
$—
 $32
 $97
Affiliate billings to us81
 65
 68
Billings to affiliates4
 5
 35
Rentals paid to affiliate583
 628
 618
Fee paid to Bencap (2)
108
 583
 —
___________________
(1)In connection with the operation of certain crude oil and natural gas properties, we charged related parties for administrative overhead. In late 2016, these charges ended as properties were either plugged and abandoned or operating responsibilities for these properties were transferred to another entity.
(2)Amount represents fees paid to Bencap through the forfeiture of our investment during the first quarter of 2017. As a result of the investment forfeiture, Bencap is no longer an affiliate.

DIP Financing

In connection with its voluntary bankruptcy filing, AREC entered into the DIP Credit Agreement with AE, of which amounts outstanding were repaid during the third quarter of 2017 with proceeds from the sales of AREC’s assets. We earned interest income of approximately $0.1 million under the DIP Credit Agreement through December 31, 2017 (see Note 3 for further information).


Note 10. Derivative Instruments and Fair Value Measurements

Derivative Instruments

At December 31, 2017, we had in place 20 commodity purchase and sale contracts, of which four of these contracts had no fair value associated with them as the contractual prices of crude oil were within the range of prices specified in the agreements. These contracts encompassed approximately:
452 barrels per day of crude oil during January 2018;
322 barrels per day of crude oil during February through May 2018;
258 barrels per day of crude oil during June 2018;
646 barrels per day of crude oil during July 2018;
322 barrels per day of crude oil during August through September 2018; and
258 barrels per day of crude oil during October through December 2018.

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The estimated fair value of forward month commodity contracts (derivatives) reflected in the accompanying consolidated balance sheet were as follows at the date indicated (in thousands):
 December 31, 2017
 Balance Sheet Location and Amount
 Current Other Current Other
 Assets Assets Liabilities Liabilities
Asset derivatives:       
Fair value forward hydrocarbon commodity       
contracts at gross valuation$166
 $—
 $—
 $—
Liability derivatives:       
Fair value forward hydrocarbon commodity       
contracts at gross valuation—
 —
 145
 —
Less counterparty offsets—
 —
 —
 —
As reported fair value contracts$166
 $—
 $145
 $—

At December 31, 2016, two contracts comprised our derivative valuations. These contracts encompassed approximately 65 barrels per day of diesel fuel during January through March 2017 and 145,000 barrels of crude oil per month during January through April 2017.

The estimated fair value of forward month commodity contracts (derivatives) reflected in the accompanying consolidated balance sheet were as follows at the date indicated (in thousands):
 December 31, 2016
 Balance Sheet Location and Amount
 Current Other Current Other
 Assets Assets Liabilities Liabilities
Asset derivatives:       
Fair value forward hydrocarbon commodity       
contracts at gross valuation$378
 $—
 $—
 $—
Liability derivatives:       
Fair value forward hydrocarbon commodity       
contracts at gross valuation—
 —
 330
 —
Less counterparty offsets(266) —
 (266) —
As reported fair value contracts$112
 $—
 $64
 $—

We only enter into commodity contracts with creditworthy counterparties and evaluate our exposure to significant counterparties on an ongoing basis. At December 31, 2017 and 2016, we were not holding nor have we posted any collateral to support our forward month fair value derivative activity. We are not subject to any credit-risk related trigger events. We have no other financial investment arrangements that would serve to offset our derivative contracts.

Forward month commodity contracts (derivatives) reflected in the accompanying consolidated statements of operations were as follows for the periods indicated (in thousands):
 Gains (Losses)
 Year Ended December 31,
 2017 2016 2015
      
Revenues – marketing$(26) $243
 $(188)

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Fair Value Measurements

The following tables set forth, by level with the Level 1, 2 and 3 fair value hierarchy, the carrying values of our financial assets and liabilities at the dates indicated (in thousands):
 December 31, 2017
 Fair Value Measurements Using    
 Quoted Prices        
 in Active Significant      
 Markets for Other Significant    
 Identical Assets Observable Unobservable    
 and Liabilities Inputs Inputs Counterparty  
 (Level 1) (Level 2) (Level 3) Offsets Total
          
Derivatives:         
Current assets$—
 $166
 $—
 $—
 $166
Current liabilities—
 (145) —
 —
 (145)
Net value$—
 $21
 $—
 $—
 $21

 December 31, 2016
 Fair Value Measurements Using    
 Quoted Prices        
 in Active Significant      
 Markets for Other Significant    
 Identical Assets Observable Unobservable    
 and Liabilities Inputs Inputs Counterparty  
 (Level 1) (Level 2) (Level 3) Offsets Total
          
Derivatives:         
Current assets$—
 $378
 $—
 $(266) $112
Current liabilities—
 (330) —
 266
 (64)
Net value$—
 $48
 $—
 $—
 $48

These assets and liabilities are measured on a material impactrecurring basis and are classified based on the lowest level of input used to estimate their fair value. Our assessment of the relative significance of these inputs requires judgments.

When determining fair value measurements, we make credit valuation adjustments to reflect both our Consolidated Financial Statementsown nonperformance risk and related disclosures.

Management believesour counterparty’s nonperformance risk. When adjusting the fair value of derivative contracts for the effect of nonperformance risk, we consider the impact of other recently issued standardsnetting and updates, whichany applicable credit enhancements. Credit valuation adjustments utilize Level 3 inputs, such as credit scores to evaluate the likelihood of default by us or our counterparties. At December 31, 2017 and 2016, credit valuation adjustments were not significant to the overall valuation of our fair value contracts. As a result, applicable fair value assets and liabilities are not yet effective, will not haveincluded in their entirety in the fair value hierarchy.

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Nonrecurring Fair Value Measurements

Certain nonfinancial assets and liabilities are measured at fair value on a material impact onnonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of impairment. The following table presents categories of long-lived assets that were subject to non-recurring fair value measurements during the Company’s consolidated financial position, resultsyear ended December 31, 2017 (in thousands):
   Fair Value Measurements at the End of the Reporting Period Using  
   Quoted Prices      
   in Active Significant    
 Carrying Markets for Other Significant Total
 Value at Identical Assets Observable Unobservable Non-Cash
 December 31, and Liabilities Inputs Inputs Impairment
 2017 (Level 1) (Level 2) (Level 3) Loss
          
Oil and gas properties -         
Investment in AREC$425
 $—
 $425
 $—
 $3,505
Investment in VestaCare—
 —
 —
 —
 2,500
         $6,005

The following table presents categories of operations, or cash flows upon adoption.long-lived assets that were subject to non-recurring fair value measurements during the year ended December 31, 2016 (in thousands):

(2)
   Fair Value Measurements at the End of the Reporting Period Using  
   Quoted Prices      
   in Active Significant    
 Carrying Markets for Other Significant Total
 Value at Identical Assets Observable Unobservable Non-Cash
 December 31, and Liabilities Inputs Inputs Impairment
 2016 (Level 1) (Level 2) (Level 3) Loss
          
Investment in Bencap$—
 $—
 $—
 $—
 $2,200
Oil and gas properties62,784
 —
 —
 62,784
 313
         $2,513

The following table presents categories of long-lived assets that were subject to non-recurring fair value measurements during the year ended December 31, 2015 (in thousands):
   Fair Value Measurements at the End of the Reporting Period Using  
   Quoted Prices      
   in Active Significant    
 Carrying Markets for Other Significant Total
 Value at Identical Assets Observable Unobservable Non-Cash
 December 31, and Liabilities Inputs Inputs Impairment
 2015 (Level 1) (Level 2) (Level 3) Loss
          
Oil and gas properties$77,117
 $—
 $—
 $77,117
 $12,082



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Note 11. Income Taxes

The following table shows the components of the Company’sour income tax (provision) benefit (inwere as follows for the periods indicated (in thousands):

  Years ended December 31, 
  2016  2015  2014 
Current:         
Federal $(2,103) $(3,883) $(8,626)
State  (675)  (190)  (1,249)
   (2,778)  (4,073)  (9,875)
Deferred:            
Federal  777   5,011   5,878 
State  80   (168)  273 
   857   4,843   6,151 
             
  $(1,921) $770  $(3,724)

The following table summarizes the components
 Year Ended December 31,
 2017 2016 2015
Current:     
Federal$(1,418) $(2,103) $(3,883)
State523
 (675) (190)
Total current(895) (2,778) (4,073)
Deferred:     
Federal3,722
 777
 5,011
State118
 80
 (168)
Total deferred3,840
 857
 4,843
Total provision for (benefit from) income taxes (1)
$2,945
 $(1,921) $770
______________
(1)
2016 includes a tax benefit of $0.8 million related to losses from our investment in Bencap, and is included in the loss from investment in unconsolidated affiliate category on the consolidated statements of operations.

A reconciliation of the provision for (benefit from) income tax (provision) benefit (in thousands):

  Years ended December 31, 
  2016  2015  2014 
From continuing operations $(2,691) $770  $(3,561)
From discontinued operations  -   -   (163)
From equity investments  770   -   - 
  $(1,921) $770  $(3,724)

46
Taxes computed attaxes with amounts determined by applying the corporatestatutory U.S. federal income tax rate (inclusive of continuing operations, equity investments and discontinued operations) reconcile to the reported income tax (provision)before income taxes was as follows (infor the periods indicated (in thousands):

  Years ended December 31, 
  2016  2015  2014 
Statutory federal income tax (provision) benefit $(1,552) $716  $(3,587)
State income tax (provision) benefit  (387)  (233)  (634)
Federal statutory depletion  62   144   549 
Other  (44)  143   (52)
  $(1,921) $770  $(3,724)

 Year Ended December 31,
 2017 2016 2015
      
Pre-tax net book income (1)
$(3,427) $4,434
 $(2,045)
      
Statutory federal income tax (provision) benefit$1,165
 $(1,552) $716
State income tax (provision) benefit736
 (387) (233)
Federal statutory depletion153
 62
 144
Federal tax rate adjustment2,007
 —
 —
Valuation allowance(1,038) —
 —
Other(78) (44) 143
Total provision for (benefit from) income taxes$2,945
 $(1,921) $770
Effective income tax rate (2)
86% 43% 38%
_______________
(1)2016 includes the pre-tax loss from investment in unconsolidated affiliate of $2.2 million.
(2)
Excluding the adjustment related to the federal tax rate change, the effective income tax rate for 2017 is 58 percent.


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Deferred income taxes reflect the net difference between the financial statement carrying amounts and the underlying income tax basis in suchthese items. The components of the federal deferred tax asset (liability) arewere as follows (inat the dates indicated (in thousands):
 December 31,
 2017 2016
    
Long-term deferred tax asset (liability): (1)
   
Prepaid and other insurance$(684) $(1,058)
Property(2,497) (7,341)
Investments in unconsolidated affiliates623
 606
Valuation allowance related to investments in unconsolidated affiliates(623) —
Uniform capitalization—
 729
Other(121) (93)
Net long-term deferred tax liability(3,302) (7,157)
Net deferred tax liability$(3,302) $(7,157)
______________
(1)Amounts as of December 31, 2017 have been revalued at 21 percent as a result of the enactment of the Tax Cuts and Jobs Act on December 22, 2017.

  Years Ended December 31, 
  2016  2015 
       
Long-term deferred tax asset (liability)      
Prepaid and other insurance $(1,058) $(1,243)
Property  (7,341)  (7,408)
Equity method investment  606   - 
Uniform capitalization  729   704 
Other  (93)  (51)
Net long-term deferred tax  liability  (7,157)  (7,998)
Net deferred tax liability $(7,157) $(7,998)

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 hasWe have no significant unrecognized tax benefits. Interest and penalties associated with income tax liabilities are classified as income tax expense.

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

 Earliest Open
 Tax Year
  
Federal2013
Texas20122013
Louisiana20132014
Michigan20122013

47
Other Matters


(3)  ConcentrationThe Tax Cuts and Jobs Act (the “Act”) was signed into law on December 22, 2017. The Act changed many aspects of Credit Risk

Credit risk encompasses the amount of loss absorbed should the Company’s customers fail to perform pursuant to contractual terms.  Managing credit risk involvesU.S. corporate income taxation and included a number of considerations, such as the financial profilereduction of the customer,corporate income tax rate from 35 percent to 21 percent, implementation of a territorial tax system and imposition of a tax on deemed repatriated earnings of foreign subsidiaries. We recognized the value of collateral held, if any, specific terms and durationtax effects 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 exposure. Accounts receivable associated with crude oil marketing activities comprise approximately 90 percent of the Company’s total receivables and industry practice requires payment for such sales to occur within 20 days of the end of the month following a transaction.  The Company’s customer makeup, credit policies and the relatively short duration of receivables mitigate the uncertainty typically associated with receivables management.  An allowance for doubtful accounts is provided where appropriate.  An analysis of the changesAct in the allowance for doubtful accountsyear ended December 31, 2017 and recorded a $2.0 million tax benefit, which relates entirely to the remeasurement of deferred tax liabilities to the 21 percent tax rate. Upon completion of our 2017 U.S. income tax return in 2018, we may identify additional remeasurement adjustments to our recorded deferred tax liabilities. We will continue to assess our income taxes as future guidance is presented as follows (issued but do not currently anticipate significant revisions will be necessary. Any such revisions will be treated in thousands):accordance with the measurement period guidance outlined in Staff Accounting Bulletin No. 118.

  2016  2015  2014 
Balance, beginning of year $206  $179  $252 
Provisions for bad debts  100   116   50 
Less:  Write-offs and recoveries  (81)  (89)  (123)
Balance, end of year $225  $206  $179 

The Company’s largest customers consist

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 12. Supplemental Cash Flow Information

Supplemental cash flows and independent domestic refiners of crude oil.  In addition, the Company transacts business with independent oil producers, major chemical concerns, crude oil trading companies and a variety of commercial energy users.  Within this group of customers, the Company generally derives approximately 50 percent of its revenues from three to 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. 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 as shown below:

Individual customer salesIndividual customer receivables in excess
in excess of 10% of revenuesof 10% of total receivables as of December 31,
201620152014201620152014
18.2%24.4%20.3%20.9%20.3%16.6%
16.5%13.8%14.0%14.0%16.5%16.6%
15.9%--10.1%12.7%10.4%
10.6%-----

(4)  Employee Benefits

The Company maintains a 401(k) savings plan for the benefit of its employees.  No other pension or retirement plans are maintained by the Company.  The Company’s 401K plan contributory expensesnon-cash transactions were as follows (infor the periods indicated (in thousands):

  2016  2015  2014 
Contributory expenses $757  $768  $691 

48

 Year Ended December 31,
 2017 2016 2015
      
Cash paid for interest$22
 $2
 $13
Cash paid for federal and state taxes459
 2,589
 6,197
      
Non-cash transactions:     
Change in accounts payable related to property and equipment
    additions
70
 679
 1,707
Property and equipment acquired under capital leases1,808
 —
 —
(5)  Transactions with Affiliates

The late Mr. K. S. Adams, Jr., former Chairman
Note 13. Commitment and Contingencies

Capital Lease Obligations

During the third quarter of the Board, and2017, we entered into capital leases for certain of his family partnershipsour tractors in our marketing segment. The following table summarizes our principal contractual commitments outstanding under our capital leases at December 31, 2017 for the next five years, and affiliates have participated as working interest owners with Adams Resources Exploration Corporation (‟AREC”).  Mr. Adamsin total thereafter (in thousands):
2018$398
2019398
2020398
2021398
2022255
Thereafter—
Total minimum lease payments1,847
Less: Amount representing interest(158)
Present value of capital lease obligations1,689
Less current portion of capital lease obligations(338)
Total long-term capital lease obligations$1,351

Operating Lease Obligations

We lease certain property and the affiliates participated on terms similar to those afforded other non-affiliated working interest owners.  While the affiliates have generally maintained their existing property interest, they have not participated in any such transactions originating after the deathequipment under noncancellable and cancelable operating leases. Our significant lease agreements consist of Mr. Adams in October 2013.  In connection with the operation of certain of these oil and gas properties, the Company charges such related parties for administrative overhead as prescribed by the Council of Petroleum Accountants Society Bulletin 5. The Company also enters into certain transactions in the normal course of business with other affiliated entities including direct cost reimbursement for shared phone and administrative services.  In addition the Company leases its corporate office space from an affiliated entity based on a lease rental rate determined by an independent appraisal.

Activities with affiliates were as follows (in thousands):

  2016  2015  2014 
Overhead recoveries $32  $97  $151 
Affiliate billings to Company $65  $68  $65 
Company billings to affiliate $5  $35  $42 
Rentals paid to affiliate $628  $618  $607 
Fee paid to Bencap $583  $-  $- 

 (6)  Commitments and Contingencies

The Company maintains certain operating lease(i) arrangements with independent truck owner-operators for use of their equipment and driver services on a month-to-month basis. In addition, the Company enters intoservices; (ii) leased office spacespace; and (iii) certain lease and terminal access contracts in order to provide tank storage and dock access for itsour crude oil marketing business. AllCurrently, our significant lease commitments qualify for off-balance sheet treatment.  Such contracts require certain minimum monthlyagreements have terms that range from one to eight years.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Lease expense is charged to operating costs and expenses on a straight-line basis over the period of expected economic benefit. Contingent rental payments are expensed as incurred. We are generally required to perform routine maintenance on the underlying leased assets. Maintenance and repairs of leased assets resulting from our operations are charged to expense as incurred. Rental expense was as follows for the term of the contracts.  The Company has no capital lease arrangements.  Rental expense is as follows (inperiods indicated (in thousands):

  Years ended December 31, 
  2016  2015  2014 
Rental expense $11,314  $11,168  $9,755 

 Year Ended December 31,
 2017 2016 2015
      
Rental expense$12,073
 $11,314
 $11,168

At December 31, 2016,2017, rental obligations under long-term non-cancelable operating leases and terminal arrangements with terms in excess of one year for the next five years and thereafter are payable as follows (in(in thousands):

2017  2018  2019  2020  2021  Thereafter  Total 
$4,768  $2,018  $365  $4  $-  $-  $7,155 

  2018 2019 2020 2021 2022 Thereafter Total
               
Operating leases $2,758
 $463
 $68
 $63
 $32
 $23
 $3,407

Insurance Policies

Under the Company’sour automobile and workers’ compensation insurance policies the Company canthat were in place through September 30, 2017, we pre-funded our estimated losses, and therefore, we could 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 iswas shared with a group of similarly situated entities.  The Company hasentities through an insurance captive. We have appropriately recognized estimated expenses and liabilities related to these policies for losses incurred but not reported to the Companyus or itsour insurance carriercarrier. The amount of pre-funded insurance premiums left to cover potential future losses totaled as follows (inat the dates indicated (in thousands):

  As of December 31, 
  2016  2015  2014 
Estimated expenses and liabilities $2,657  $2,086  $2,585 
49
The Company maintains
 December 31,
 2017 2016
    
Pre-funded premiums for losses incurred but not reported$988
 $2,657

If the potential insurance claims do not further develop, the pre-funded premiums will be returned to us as a premium refund.

Effective October 1, 2017, we changed the structure of our automobile and workers’ compensation insurance policies. We have exited the group captive and now establish a liability for expected claims incurred but not reported on a monthly basis as we move forward. As claims are paid, the liability is relieved. At December 31, 2017, our accrual for automobile and workers’ compensation claims was $0.5 million.
We maintain a self-insurance program for managing employee medical claims. A liability for expected claims incurred but not reported is established on a monthly basis. As claims are paid, the liability is relieved. The CompanyWe also maintainsmaintain third party insurance stop-loss coverage for annual aggregate medical claims exceeding $4.5 million. Medical accrual amounts arewere as follows (inat the dates indicated (in thousands):
 December 31,
 2017 2016
    
Accrued medical claims$1,329
 $1,411


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Litigation


  As of December 31, 
  2016  2015  2014 
Accrued medical claims $1,411  $1,107  $1,057 

AREC iswas named as a defendant in a number of Louisiana based suitslawsuits 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 contributingmatter involving allegations that drilling operations in 1986 contributed to the formation of a sink hole.sinkhole in 2012 (the “Sinkhole Cases”). The Sinkhole Cases, while arising from a singular event, include a number of different lawsuits brought in Louisiana State Court and one consolidated action in the United States District Court for the Eastern District of Louisiana.  In addition to the Sinkhole Cases, AREC is also currently involved in three suchtwo other suits. TheThese 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 2012filed in Acadia Parish, Louisiana, and Henning Management, LLC v. Adams Resources Exploration Corporation dated November 2013.2013 filed in Jefferson Davis Parish, Louisiana. Each suit involves multiple industry defendants with substantially larger proportional interest in the properties. In the LePetit Chateau Deluxe matter, all the larger defendants have settled the case.

The plaintiffs in each of these matters are seeking unspecified compensatory and punitive damages. While management doeswe do not believe that these claims will result in a material adverse effect will result from the claims,on us, significant attorney fees willmay be incurred to defendaddress claims related to these items.  As ofsuits. At December 31, 2016, and 2015 the Company has accruedwe had $0.5 million ofaccrued for future legal and/or settlement costs for these matters. During May 2017, AREC was dismissed without prejudice as a party to the suit with Henning Management. We also determined that the likelihood of future claims from other remaining litigation was remote. As such, we released the $0.5 million accrual for future legal settlements related to these matters. At December 31, 2017, we had no remaining accruals for legal costs for these matters.

From time to time as incidental to itsour operations, the Companywe may become involved in various lawsuits and/or disputes. Primarily as an operator of an extensive trucking fleet, the Company iswe are 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 isWe are presently unaware of any claims against the Companyus 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’sour financial position or results of operations.

(7)  Guarantees

AE issues parent guarantees of commitments associated with the 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 itemsthese arrangements is to guarantee the performance of the subsidiary companies in meeting their respective underlying obligations.  Except for operating lease commitments and letters of credit, all such underlying obligations are recorded on the books of the subsidiary companies and are included in the Consolidated Financial Statements included herein.  Therefore, no such obligation is recorded again on the books of the parent. The parent would only be called upon to perform under the guarantee in the event of a payment default by the applicable subsidiary company. In satisfying such obligations, the parent would first look to the assets of the defaulting subsidiary company.

As ofAt December 31, 2016,2017, parental guaranteed obligations arewere approximately as follows (in thousands):

  2017  2018  2019  2020  Thereafter  Total 
Commodity purchases $24,210   -   -   -   -  $24,210 
Letters of credit  -   -   -   -   -   - 
  $24,210  $-  $-  $-  $-  $24,210 

Presently,$48.2 million. Currently, neither AE nor any of its subsidiaries has any other types of guarantees outstanding that require liability recognition.
50

Note 14. Concentration of Credit Risk

We may incur credit risk to the extent our customers do not fulfill their obligations to us pursuant to contractual terms. Risks of nonpayment and nonperformance by our customers are a major consideration in our business, and our credit procedures and policies may not be adequate to sufficiently eliminate customer credit risk. 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. We have established various procedures to manage credit exposure, including initial credit approval, credit limits, and rights of offset. We also utilize letters of credit and guarantees to limit exposure.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(8)  Segment Reporting

The Company is engaged in theOur largest customers consist of large multinational integrated crude oil companies and independent domestic refiners of crude oil. In addition, we transact business with independent crude oil producers, major chemical concerns, crude oil trading companies and a variety of commercial energy users. Within this group of customers, we derive approximately 50 percent of our revenues from three to five large crude oil refining customers. While we have ongoing established relationships with certain domestic refiners of crude oil, marketingalternative markets are readily available since we supply less than one percent of U.S. domestic refiner demand. As a fungible commodity delivered to major Gulf Coast supply points, our crude oil sales can be readily delivered to alternative end markets.

We believe that a loss of any of those customers where we currently derive more than 10 percent of our revenues would not have a material adverse effect on our operations 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, 2016-            
Marketing $1,043,775  $17,045  $9,997  $1,321 
Transportation  52,355   (48)  7,249   6,868 
Oil and gas  3,410   (533
)(2)
  1,546   295 
  $1,099,540  $16,464  $18,792  $8,484 
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 

(1) Marketing segment operating earnings included inventory valuation losses totaling  $5.4 million  and $14.3 million for 2015 and 2014, respectively.
(2) Oil and gassegment operating earnings include gains on property sales totaling $2.5 million during 2014 and property impairments totaling  $12.1 million and $8.0 million for 2015 and 2014, 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, 
  2016  2015  2014 
Segment operating earnings $16,464  $7,580  $18,094 
- General and administrative expenses  (10,410)  (9,939)  (8,613)
Operating earnings (loss)  6,054   (2,359)  9,481 
- Interest income  582   327   301 
- Interest expense  (2)  (13)  (2)
Earnings (loss) from continuing operations before            
income taxes and discontinued operations $6,634  $(2,045) $9,780 

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

  Years Ended December 31, 
  2016  2015  2014 
Marketing $107,257  $96,723  $189,332 
Transportation  32,120   35,010   37,643 
Oil and gas  7,279   8,930   25,888 
Cash and other  100,216   102,552   87,951 
  $246,872  $243,215  $340,814 

51

Intersegment sales are insignificant and all sales occurredshown in the United States.  Other identifiable assets are primarily corporate cash, corporate accounts receivable, and properties not identified with any specific segmenttable below:
Individual customer sales Individual customer receivables in excess
in excess of 10% of revenues of 10% of total receivables
for the year ended December 31, at December 31,
2017 2016 2015 2017 2016 2015
           
22.8% 18.2% 24.4% 19.1% 20.9% 20.3%
17.1% 16.5% 13.8% 15.0% 14.0% 16.5%
10.8% 15.9%   11.1% 10.1% 12.7%
10.7% 10.6%   10.4%    



64

Table of the Company’s business.  Accounting policies for transactions between reportable segments are consistent with applicable accounting policies as disclosed herein.Contents

(9)  Discontinued OperationsADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In 2014, the Company sold for $0.7 million in cash the warehouse and real estate used by its former petroleum refined products marketing operation to yield a pre-tax gain of $0.6 million with such gain reported in discontinued operations for 2014.

(10)  Subsequent Event

During the third quarter of 2016, the Company completed a review of its equity method investment in Bencap and determined there was an other than temporary impairment.  Underlying this decision are the terms of the investment agreement where Bencap has the option to request borrowings up to $1.5 million (on or after December 5, 2016 but before October 31, 2018) that the Company must provide or forfeit its 30% member interest.  During the third quarter of 2016, management of the Company determined that it was unlikely to provide additional funding due to Bencap’s lower than projected revenue growth and operating losses since investment inception.  As a result, the Company recognized a net loss of $1.4 million from its investment in Bencap as of September 30, 2016.  This loss included a pre-tax impairment charge of $1.7 million and pre-tax losses from the equity method investment of $0.5 million. In February 2017, Bencap requested additional funding of approximately $0.5 million and the Company declined the additional funding request.

(11)Note 15. Quarterly Financial DataInformation (Unaudited)

SelectedThe following table presents selected quarterly financial data and earnings per share of the Company are presented below for the years ended December 31, 2016 and 2015 (inperiods indicated (in thousands, except per share data):
     Earnings (Loss) from       
     Continuing Operations  Net Earnings (Loss)  Dividends 
  Revenues  Amount  Per Share  Amount  Per Share  Amount  Per Share 
                   
2016                  
March 31 $250,531  $1,554  $.37  $1,430  $.34  $928  $.22 
June 30  293,163   3,540   .84   3,404   .81   928   .22 
September 30  256,877   (983)  (.23)  (2,153)  (.51)  928   .22 
December 31  298,969   (168)  (.04)  (168)  (.04)  927   .22 
Total $1,099,540  $3,943  $.94  $2,513  $.60  $3,711  $.88 
                             
2015                            
March 31 $555,573  $3,097  $.73  $3,097  $.73  $928  $.22 
June 30  600,558   4,340   1.03   4,340   1.03   928   .22 
September 30  439,893   (308)  (.07)  (308)  (.07)  928   .22 
December 31  348,255   (8,404)  (1.99)  (8,404)  (1.99)  928   .22 
Total $1,944,279  $(1,275) $(.30) $(1,275) $(.30) $3,712  $.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.
52

 First Second Third Fourth
 Quarter Quarter Quarter Quarter
Year Ended December 31, 2017       
Revenues$303,087
 $315,202
 $295,311
 $408,460
Operating (losses) earnings(1,584) 619
 (1,290) 3,757
Earnings (losses) from continuing operations(860) (282) (3,033) 3,693
Net (losses) earnings(860) (282) (3,033) 3,693
        
Earnings (losses) per share:       
From continuing operations$(0.20) $(0.07) $(0.72) $0.88
From investment in unconsolidated       
affiliate—
 —
 —
 —
Basic and diluted net (losses) earnings per share$(0.20) $(0.07) $(0.72) $0.88
        
Year Ended December 31, 2016       
Revenues$250,531
 $293,163
 $256,877
 $298,969
Operating (losses) earnings2,339
 5,601
 (1,822) (64)
Earnings (losses) from continuing operations1,554
 3,540
 (983) (168)
Net (losses) earnings1,430
 3,404
 (2,153) (168)
        
Earnings (losses) per share:       
From continuing operations$0.37
 $0.84
 $(0.23) $(0.04)
From investment in unconsolidated       
affiliate(0.03) (0.03) (0.28) —
Basic and diluted net (losses) earnings per share$0.34
 $0.81
 $(0.51) $(0.04)
(12)



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 16. Oil and Gas Producing Activities (Unaudited)

Adams Resources Exploration Corporation (‟AREC”), aOur wholly owned subsidiary, of AE, isAREC, participated in the exploration and development of domestic crude oil and natural gas properties primarily in the Permian Basin of West Texas and the Haynesville Shale. AREC’s offices arewere maintained in Houston, and the Company holdsat December 31, 2016, we held an interest in 470 producing wells of which 6we operated six. As discussed further in Note 3, AREC was deconsolidated effective with its bankruptcy filing in April 2017, and we recorded our investment in AREC under the cost method of accounting in April 2017. During the third quarter of 2017, AREC closed on the sale of substantially all of its assets. As a result of the sales of these assets, we no longer have an ownership interest in any crude oil and natural gas producing activities. In the disclosures and tables below, amounts for 2017 are Company operated.for the period from January 1, 2017 through April 30, 2017, as a result of the deconsolidation of AREC due to its bankruptcy filing.
.
Crude Oil and Natural Gas Producing Activities -

Total costs incurred in crude oil and natural gas exploration and development activities, all within the United States,U.S., were as follows (infor the periods indicated (in thousands):

  For the year Ended December 31, 
  2016  2015  2014 
Property acquisition costs         
Unproved $32  $348  $1,144 
Proved  -   -   - 
Exploration costs            
Expensed  291   1,667   5,054 
Capitalized  -   -   - 
Development costs  -   370   1,745 
Total costs incurred $323  $2,385  $7,943 

 Year Ended December 31,
 2017 2016 2015
Property acquisition costs:     
Unproved$4
 $32
 $348
Proved—
 —
 —
Exploration costs:     
Expensed5
 291
 1,667
Capitalized—
 —
 —
Development costs1,815
 —
 370
Total costs incurred$1,824
 $323
 $2,385

The aggregate capitalized costs relative to crude oil and natural gas producing activities arewere as follows (inat the dates indicated (in thousands):
 December 31,
 2017 2016
    
Unproved crude oil and natural gas properties$—
 $—
Proved crude oil and natural gas properties—
 62,784
Subtotal—
 62,784
Accumulated depreciation, depletion and amortization—
 (56,426)
Net capitalized cost$—
 $6,358

  As of December 31, 
  2016  2015 
Unproved oil and gas properties $-  $231 
Proved oil and gas properties  62,784   76,886 
   62,784   77,117 
Accumulated depreciation, depletion        
and amortization  (56,426)  (69,116)
Net capitalized cost $6,358  $8,001 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Estimated Crude Oil and Natural Gas Reserves -

The following information regarding estimates of the Company’sour proved crude oil and natural gas reserves, substantially all located onshore in Texas and Louisiana, iswas based on reports prepared on our behalf of the Company by itsour independent petroleum engineers. Because crude oil and natural 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. As discussed previously, AREC was deconsolidated effective with its bankruptcy filing in April 2017, and we recorded our investment in AREC under the cost method of accounting in April 2017. During the third quarter of 2017, AREC closed on the sale of substantially all of its assets. As a result of the sales of these assets, we no longer have an ownership interested in any crude oil and natural gas producing activities. In the tables below, amounts for 2017 are for the period from January 1, 2017 through April 30, 2017, as a result of the deconsolidation of AREC due to its bankruptcy filing.
53

Proved developed and undeveloped reserves are presentedwere as follows (infor the periods indicated (in thousands):

  Years Ended December 31, 
  2016  2015  2014 
  Natural     Natural     Natural    
  Gas  Oil  Gas  Oil  Gas  Oil 
  
(Mcf’s)
  
(Bbls.)
  
(Mcf’s)
  
(Bbls.)
  
(Mcf’s)
  
(Bbls.)
 
Total proved reserves-                  
Beginning of year  4,835   226   5,611   318   6,286   368 
Revisions of previous estimates  65   24   27   (2)  724   6 
Oil and gas reserves sold  (175)  (4)  -   (3)  (558)  (11)
Extensions, discoveries and                        
other reserve additions  151   18   86   13   292   82 
Production  (662)  (77)  (889)  (100)  (1,133)  (127)
End of year  4,214   187   4,835   226   5,611   318 

 Year Ended December 31,
 2017 2016 2015
 Natural Crude Natural Crude Natural Crude
 Gas Oil Gas Oil Gas Oil
 (Mcf) (Bbls) (Mcf) (Bbls) (Mcf) (Bbls)
Total proved reserves:                
Beginning of year4,214
 187
 4,835
 226
 5,611
 318
Revisions of previous estimates—
 —
 65
 24
 27
 (2)
Crude oil and natural gas reserves sold(4,067) (170) (175) (4) —
 (3)
Extensions, discoveries and other           
reserve additions42
 6
 151
 18
 86
 13
Production(189) (23) (662) (77) (889) (100)
End of year—
 —
 4,214
 187
 4,835
 226

The components of our previously owned proved crude oil and natural gas reserves, all within the U.S., were as follows for the three years ended December 31, 2016 is presented below.  All reserves are in the United States (inperiods indicated (in thousands):

  Years Ended December 31, 
  2016  2015  2014 
  Natural     Natural     Natural    
  Gas  Oil  Gas  Oil  Gas  Oil 
  
(Mcf’s)
  
(Bbls.)
  
(Mcf’s)
  
(Bbls.)
  
(Mcf’s)
  
(Bbls.)
 
Proved developed reserves  4,214   187   4,813   223   5,482   299 
Proved undeveloped reserves  -   -   22   3   129   19 
Total proved reserves  4,214   187   4,835   226   5,611   318 

The Company has
 Year Ended December 31,
 2017 2016 2015
 Natural Crude Natural Crude Natural Crude
 Gas Oil Gas Oil Gas Oil
 (Mcf) (Bbls) (Mcf) (Bbls) (Mcf) (Bbls)
            
Proved developed reserves—
 —
 4,214
 187
 4,813
 223
Proved undeveloped reserves—
 —
 —
 —
 22
 3
Total proved reserves—
 —
 4,214
 187
 4,835
 226

We had developed internal policies and controls for estimating and recording crude oil and natural gas reserve data. The estimation and recording of proved reserves is required to be in compliance with SEC definitions and guidance. The Company assignsWe assigned responsibility for compliance in reserve bookings to the office of President of AREC. No portion of this individual’s compensation iswas 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
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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


We employed a third party petroleum consultant, Ryder Scott Company, to prepare itsour crude oil and natural gas reserve data estimates as of December 31, 2016 2015 and 2014.2015. 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 crude oil and natural 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 crude oil and natural 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 crude oil and natural 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, crude oil and natural gas quantities ultimately recovered will vary from reserve estimates.
54

Standardized Measure of Discounted Future Net Cash Flows from Crude Oil and Natural 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 arewere included in contracts. The disclosures below do not purport to present the fair market value of the Company’sour previously owned crude oil and natural 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 presentedwas as follows (infor the periods indicated (in thousands):
 Year Ended December 31,
 2017 2016 2015
      
Future gross revenues$—
 $17,938
 $23,040
Future costs:     
Lease operating expenses—
 (12,421) (14,524)
Development costs—
 (38) (103)
Future net cash flows before income taxes—
 5,479
 8,413
Discount at 10% per annum—
 (2,002) (2,987)
Discounted future net cash flows before income taxes—
 3,477
 5,426
Future income taxes, net of discount at 10% per annum—
 (1,217) (1,899)
Standardized measure of discounted future net cash flows$—
 $2,260
 $3,527

  Years Ended December 31, 
  2016  2015  2014 
Future gross revenues $17,938  $23,040  $58,885 
Future costs -            
Lease operating expenses  (12,421)  (14,524)  (16,421)
Development costs  (38)  (103)  (1,068)
Future net cash flows before income taxes  5,479   8,413   41,396 
Discount at 10% per annum  (2,002)  (2,987)  (17,175)
Discounted future net cash flows            
before income taxes  3,477   5,426   24,221 
Future income taxes, net of discount at            
10% per annum  (1,217)  (1,899)  (8,477)
Standardized measure of discounted            
future net cash flows $2,260  $3,527  $15,744 

The estimated value of crude oil and natural gas reserves and future net revenues derived therefrom are highly dependent upon crude oil and natural gas commodity price assumptions. For such estimates, the Company’sour independent petroleum engineers assumed market prices as presented in the table below:

  Years ended December 31, 
  2016  2015  2014 
Market price         
Crude oil per barrel $38.34  $45.83  $89.60 
Natural gas per thousand cubic feet (mcf) $2.56  $2.62  $5.42 

Such
 Year Ended December 31,
 2017 2016 2015
Market price:     
Crude oil per barrel$—
 $38.34
 $45.83
Natural gas per thousand cubic feet (Mcf)$—
 $2.56
 $2.62


68

Table of Contents

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


These 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 prices reported in the reserve disclosures for natural gas includeincluded the value of associated natural gas liquids. OilCrude oil and natural 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 presentedwas as follows (infor the periods indicated (in thousands):

  Years ended December 31, 
  2016  2015  2014 
Future net cash flows before income taxes $5,479  $8,413  $41,396 
Future income taxes  (1,918)  (2,945)  (14,489)
Future net cash flows  3,561   5,468   26,907 
Discount at 10% per annum  (1,301)  (1,941)  (11,163)
Standardized measure of discounted            
future net cash flows $2,260  $3,527  $15,744 

55

 Year Ended December 31,
 2017 2016 2015
      
Future net cash flows before income taxes$—
 $5,479
 $8,413
Future income taxes—
 (1,918) (2,945)
Future net cash flows—
 3,561
 5,468
Discount at 10% per annum—
 (1,301) (1,941)
Standardized measure of discounted future net cash flows$—
 $2,260
 $3,527

The principal sources of changes in the standardized measure of discounted future net cash flows arewere as follows (infor the periods indicated (in thousands):
 Year Ended December 31,
 2017 2016 2015
      
Beginning of year$2,260
 $3,527
 $15,744
Sale of crude oil and natural gas reserves(2,732) (350) (54)
Net change in prices and production costs—
 (1,391) (17,622)
New field discoveries and extensions, net of future
   production costs
94
 275
 292
Sales of crude oil and natural gas produced, net of production costs(476) 87
 1,038
Net change due to revisions in quantity estimates—
 181
 38
Accretion of discount130
 194
 1,116
Production rate changes and other(493) (945) (3,603)
Net change in income taxes1,217
 682
 6,578
End of year$—
 $2,260
 $3,527

  Years Ended December 31, 
  2016  2015  2014 
Beginning of year $3,527  $15,744  $17,836 
Sale of oil and gas reserves  (350)  (54)  (981)
Net change in prices and production costs  (1,391)  (17,622)  (72)
New field discoveries and extensions, net of future            
production costs  275   292   4,456 
Sales of oil and gas produced, net of production costs  87   1,038   (6,590)
Net change due to revisions in quantity estimates  181   38   2,460 
Accretion of discount  194   1,116   1,773 
Production rate changes and other  (945)  (3,603)  (4,265)
Net change in income taxes  682   6,578   1,127 
End of year $2,260  $3,527  $15,744 

Results of Operations for Crude Oil and Natural Gas Producing Activities -

The results of crude oil and natural gas producing activities, excluding corporate overhead and interest costs, arewere as follows (infor the periods indicated (in thousands):

  Years Ended December 31, 
  2016  2015  2014 
Revenues $3,410  $5,063  $13,361 
Costs and expenses -            
Production  (3,337)  (7,022)  (6,771)
Producing property impairment  (30)  (10,324)  (4,001)
Exploration  -   (1,667)  (5,054)
Oil and natural gas property sale gain  -   -   2,528 
Depreciation, depletion and amortization  (1,546)  (5,066)  (7,573)
Operating income (loss) before income taxes  (1,503)  (19,016)  (7,510)
Income tax benefit  526   6,656   2,628 
Operating income (loss) $(977) $(12,360) $(4,882)
             

 Year Ended December 31,
 2017 2016 2015
      
Revenues$1,427
 $3,410
 $5,063
Costs and expenses:     
Production(951) (3,337) (7,022)
Producing property impairment—
 (30) (10,324)
Exploration—
 —
 (1,667)
Depreciation, depletion and amortization(423) (1,546) (5,066)
Operating loss before income taxes53
 (1,503) (19,016)
Income tax benefit (expense)(19) 526
 6,656
Operating earnings (losses)$34
 $(977) $(12,360)

69


Item 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSUREChanges in and Disagreements with Accountants on Accounting and Financial Disclosure.


On June 7, 2017, we dismissed Deloitte & Touche, LLP (“Deloitte”) as our independent registered public accounting firm. There was no dispute or disagreement with the firm on any issue. On June 7, 2017, we appointed KPMG LLP as our new independent registered public accounting firm to perform independent audit services for the fiscal year ended December 31, 2017.
None.

56
Item 9A. CONTROLS AND PROCEDURESControls and Procedures.

Evaluation of Disclosure Controls and Procedures

We have,As of the end of the period covered by this annual report, our management carried out an evaluation, with the participation of our Chief Executive Officer (CEO)Chairman and our Chief Financial Officer, (CFO), evaluatedof the effectiveness of our disclosure controls and procedures as of December 31, 2016. The term “disclosure controls and procedures,” as defined in Rulespursuant to Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, or the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms.

Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.Act. Based on thethis evaluation, of our disclosure controls and procedures as of December 31, 2016,the end of the period covered by this annual report, our Chief Executive OfficerChairman and our Chief Financial Officer concluded that, as of such date, our disclosure controls and procedures were not effective as a result of a material weaknessconcluded:

(i)that our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive and financial officers, as appropriate to allow for timely decisions regarding required disclosures; and

(ii)that our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting as further described below. A material weakness is a deficiency,(as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) during the fourth quarter of 2017, that have materially affected, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

In light of the material weakness in internal control over financial reporting, we completed additional substantive proceduresare reasonably likely to validate the completeness and accuracy of the financial data impacted by the deficiency. These additional procedures have allowed us to conclude that, notwithstanding the material weakness inmaterially affect, our internal control over financial reporting, thereporting.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING AS OF DECEMBER 31, 2017

Management of Adams Resources & Energy, Inc. and its consolidated financial statements included in this Annual Report on Form 10-K fairly present, in all material respects, our financial position, results of operations and cash flows for the periods presented in conformity with accounting principles generally accepted in the United States of America.

Management's Report on Internal Control over Financial Reporting

Managementsubsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Exchange Act RulesRule 13a-15(f) and 15d-15(f). of the Securities Exchange Act of 1934, as amended.  Our management assessed the effectiveness of our internal control over financial reporting asis a process designed under the supervision of December 31, 2016, using the criteria set forth in the Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)our Executive Chairman and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with U.S.accounting principles generally accepted accounting principles. Internalin the United States.

Because of its inherent limitations, internal control over financial reporting includes thosemay 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 that: (1) pertain tomay deteriorate.

Management, including the maintenance of records that, in reasonable detail, accuratelyCompany’s Executive Chairman and fairly reflectChief Financial Officer, assessed the transactions and dispositionseffectiveness of the assetsCompany’s internal control over financial reporting as of December 31, 2017.  In making this assessment, management used the criteria described in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Company, (2) provide reasonable assuranceTreadway Commission (“COSO”).  Based on this assessment, management, including the Company’s Executive Chairman and Chief Financial Officer, concluded that transactions are recordedinternal control over financial reporting was effective 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.December 31, 2017.

Management
70


KPMG LLP has concludedissued its attestation report regarding our internal control over financial reportingreporting. That report is ineffective asincluded within this Item 9A (See “Report of December 31, 2016 as management identified a material weakness as further described below.Independent Registered Public Accounting Firm”).

Financial Close Process. We identified a design deficiency, which also prevented the control from operating effectively, relatedPursuant to the control overrequirements of Rules 13a-15(f) and 15d-15(f) of the review and approvalSecurities Exchange Act of manual journal entries in one of our segments. The design deficiency related to the same personnel reviewing, approving and posting journal entries.  If not remediated, the control deficiency could potentially impact the accuracy and completeness of our financial statements.
Deloitte & Touche LLP, our independent registered public accounting firm, has issued a1934, as amended, this annual report on our internal control over financial reporting, which is included herein.
57
Changes in Internal Control overOver Financial Reporting

Other than has been signed below by the material weakness described above, there have been no changes in our internal control over financial reporting identified in connection with the evaluation required by Rule 13a-15(d) and 15d-15(d)following persons on behalf of the Exchange Act that occurred during the three months ended December 31, 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.registrant and in their respective capacities indicated below on March 12, 2018.

Remediation Efforts to Address Identified Material Weaknesses

Management is dedicating time and resources to remediate the control deficiency that gave rise to the material weakness in our internal control over financial reporting.
The following steps are among the measures that we are implementing to address our material weakness as of December 31, 2016:

·
We are performing a review to ensure that no personnel signs off as the reviewer and subsequently posts the journal entry to the general ledger.
/s/ Townes G. Pressler/s/ Josh C. Anders
Townes G. PresslerJosh C. Anders
Executive ChairmanChief Financial Officer

·We are considering repositioning the personnel in the financial close group to allow for more segregation of duties within the group.

·We are addressing the control gap relating to the segregation of duties by requiring review of the manual journal entry to occur after the journal entry is independently posted.  Review after posting restricts the ability to edit the journal entry.

We are committed to maintaining a strong internal control environment. Management has updated the Audit Committee and is developing a detailed plan and timetable for the completion of the implementation of the remedial measures outlined above and will continue to monitor such implementation. In addition, under the direction of the Audit Committee, management will continue to review and make necessary changes to the overall design of our financial close process, as well as to our policies and procedures in order to improve the overall effectiveness of our internal control over financial reporting.

As we implement these remediation efforts, we may determine that additional steps may be necessary to remediate the material weakness. We cannot assure you that these remediation efforts will be successful or that our internal control over financial reporting will be effective in accomplishing all control objectives all of the time. We will continue to assess the effectiveness of our remediation efforts in connection with our evaluations of internal control over financial reporting.

58
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors and Stockholders of
Adams Resources & Energy, Inc.:
Houston, Texas
Opinion on Internal Control Over Financial Reporting

We have audited Adams Resources & Energy, Inc.’s and subsidiaries'subsidiaries (the "Company"“Company”) internal control over financial reporting as of December 31, 2016,2017, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of the Company as of December 31, 2017, the related consolidated statements of operations, shareholders’ equity, and cash flows for the year ended December 31, 2017, and the related notes (collectively, the consolidated financial statements), and our report dated March 12, 2018 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion

The Company'sCompany’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'sManagement’s Annual Report on Internal Control Over Financial Reporting.Reporting as of December 31, 2017. Our responsibility is to express an opinion on the Company'sCompany’s internal control over financial reporting based on our audit.
We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. 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 of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on that risk, andthe assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

71


Definition and Limitations of Internal Control Over Financial Reporting
    
A company'scompany’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'scompany’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'scompany’s assets that could have a material effect on the financial statements.

Because of theits 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 preventedprevent or detected on a timely basis.detect misstatements. 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.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weakness has been identified and included in management's assessment: the control over the review and approval of manual journal entries in one of the Company’s segments was not designed appropriately. This material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the consolidated financial statements as of and for the year ended December 31, 2016, of the Company and this report does not affect our report on such financial statements.
In our opinion, because of the effect of the material weakness identified above on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
59

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, 2016, of the Company and our report dated March 31, 2017 expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHEKPMG LLP

Houston, Texas
March 31, 2017

12, 2018

60
Item 9B. OTHER INFORMATIONOther Information.

None.
61

PART III


Item 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCEDirectors, Executive Officers and Corporate Governance.

The information concerning directors, corporate governance and executive officers of the Company is incorporatedrequired by reference from the Company’sthis item will be included in our definitive Proxy Statement for thein connection with our 2018 Annual Meeting of Shareholders to be held Wednesday, May 3, 2017, under the heading ‟Election of Directors” and ‟Executive Officers”(the “2018 Proxy Statement”), respectively, towhich will be filed with the Commission not later thanSEC within 120 days after the end of the fiscal year coveredended December 31, 2017, under the headings “Election of Directors” and “Executive Officers” and is incorporated herein by this Form 10-K.reference.

Item 11.EXECUTIVE COMPENSATIONExecutive Compensation.

The information required by Item 11 is incorporated by reference from the Company’s definitivethis item will be set forth in our 2018 Proxy Statement, for the Annual Meeting of Shareholders to be held Wednesday, May 3, 2017, under the heading ‟Executive Compensation” towhich will be filed with the Commission not later thanSEC within 120 days after the end of the fiscal year coveredended December 31, 2017, under the heading “Executive Compensation” and is incorporated herein by this Form 10-K.reference.

Item 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERSSecurity 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 definitivethis item will be set forth in our 2018 Proxy Statement, for the Annual Meeting of Shareholders to be held Wednesday May 3, 2017, under the heading ‟Voting Securities and Principal Holders Thereof” towhich will be filed with the Commission not later thanSEC within 120 days after the end of the fiscal year coveredended December 31, 2017, under the heading “Voting Securities and Principal Holders Thereof” and is incorporated herein by this Form 10-K.reference.


72


Item 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCECertain Relationships and Related Transactions, and Director Independence.

The information required by Item 13 is incorporated by reference from the Company’s definitivethis item will be set forth in our 2018 Proxy Statement, for the Annual Meeting of Shareholders to be held Wednesday May 3, 2017, under the headings ‟Transactions with Related Parties” and ‟Director Independence” towhich will be filed with the Commission not later thanSEC within 120 days after the end of the fiscal year coveredended December 31, 2017, under the headings “Transactions with Related Parties” and “Director Independence” and is incorporated herein by this Form 10-K.reference.


Item 14.PRINCIPAL ACCOUNTING FEES AND SERVICESPrincipal Accounting Fees and Services

The information required by Item 14 is incorporated by reference from the Company’s definitivethis item will be set forth in our 2018 Proxy Statement, for the Annual Meeting of Shareholders to be held Wednesday May 3, 2017, under the heading ‟Principal Accounting Fees and Services” towhich will be filed with the Commission not later thanSEC within 120 days after the end of the fiscal year coveredended December 31, 2017, under the heading “Principal Accounting Fees and Services” and is incorporated herein by this Form 10-K.reference.
62


PART IV

    

Item 15.EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Exhibits, Financial Statement Schedules


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

(1)
Financial Statements: See “Index to Consolidated Financial Statements” beginning on page 34 of this annual report for the financial statements included herein.

(2)Financial Statement Schedules: The separate filing of financial statement schedules has been omitted because such schedules are either not applicable or the information called for therein appears in the footnotes of our Consolidated Financial Statements.

(3)Exhibits:
1.          Financial Statements

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of December 31, 2016 and 2015

Consolidated Statements of Operations for the Years Ended
December 31, 2016, 2015 and 2014

Consolidated Statements of Shareholders’ Equity for the Years Ended
December 31, 2016, 2015 and 2014

Consolidated Statements of Cash Flows for the Years Ended
December 31, 2016, 2015 and 2014

Notes to Consolidated Financial Statements

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

3.          Exhibits required to be filed


3(a)          
-          
Exhibit
Number
Exhibit
3.1Certificate of Incorporation of the Company,Adams Resources & Energy, Inc., as amended.  (Incorporatedamended (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)1987).

3(c) -          3.2
Bylaws of Adams Resources & Energy, Inc., as amended (incorporated by reference to Exhibit 3(b) to Form 10-K for the year ended December 31, 2012).
3.3
Adams Resources & Energy, Inc. and Subsidiaries’ Code of Ethics (Incorporated(incorporated by reference to Exhibit 3(d) of the Annual Report onto Form 10-K (-File No. 1-7908) of the Company for the fiscal year ended December 31, 2002).

4(a) -          4.1Specimen common stock Certificate (Incorporatedcertificate (incorporated by reference to Exhibit 4(a) of the Annual Report onto Form 10-K of the Company (-File No. 1-7908) for the fiscal year ended December 31, 1991).

4(b) -          4.2
Credit and Security Agreement between Gulfmark Energy, Inc., Adams Resources Marketing, Ltd., and Wells Fargo Bank, National Association dated August 27, 2009 (Incorporated(incorporated by reference to Exhibit 4(b) of theto Quarterly Report on Form 10-Q for the period ended September 30, 2009).

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

10.2 -          10.2+
Retirement Agreement, dated February 26, 2015, by and between Adams Resources & Energy, Inc. and Frank T. ‟Chip”“Chip” Webster (Incorporated(incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed on February 26, 2015).
10.3
Sixth Amendment to Credit and Security Agreement dated as of September 28, 2017 between Gulfmark Energy, Inc., and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q for the period ended September 30, 2017).
63
73


21*          
-          Subsidiaries
Exhibit
Number
Exhibit
10.4*
Debtor in Possession Credit and Security Agreement dated as of the Registrant

23.1*          -          Consent of Ryder Scott Company

31.1*          -          April 25, 2017 by and among Adams Resources Exploration Corporation, as Borrower, and Adams Resources & Energy, Inc., as Lender.
21*
Subsidiaries of the registrant.
23.1*
Consent of Ryder Scott Company.
31.1*
Sarbanes-Oxley Section 302 Certification Pursuantof Chief Executive Officer pursuant to 17 CFR 13a-14 (a)/Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 20022002.

31.2* -          31.2*Adams Resources & Energy, Inc.
Sarbanes-Oxley Section 302 Certification Pursuantof Chief Financial Officer pursuant to 17 CFRExchange Act Rules 13a-14(a)/ and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 20022002.

32.1* -          32.1*
Sarbanes-Oxley Section 906 Certification Pursuantof Chief Executive Officer pursuant to 1818. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 20022002.

32.2* -          32.2*
Sarbanes-Oxley Section 906 Certification Pursuantof Chief Financial Officer pursuant to 1818. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 20022002.

99.1* -          99.1
Ryder Scott Company Report
as of December 31, 2016 (incorporated by reference to Exhibit 99.1 to Annual Report on Form 10-K for the year ended December 31, 2016).

101.INS*-          XBRL Instance Document
101.SCH*-          XBRL Schema Document
101.CAL*-          XBRL Calculation Linkbase Document
101.LAB*-          101.DEF*XBRL LabelDefinition Linkbase Document
101.INS*XBRL Instance Document
101.LAB*XBRL Labels Linkbase Document
101.PRE*-          XBRL Presentation Linkbase Document
101.DEF*-          101.SCH*XBRL Definition LinkbaseSchema Document

*- Filed herewithfor furnished (in the case of Exhibits 32.1 and 32.2) with this report.
+- Management contract or compensation plan or arrangementarrangement.
**-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, 2016, 2015 and 2014 (ii) the Consolidated Balance Sheets – December 31, 2016 and December 31, 2015, (iii) the Consolidated Statements of Cash Flows – Year Ended December 31, 2016, 2015 and 2014 (iv) Notes to Consolidated Financial Statements.

Item 16.
Form 10-K Summary

Not applicable.


6474


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.authorized on March 12, 2018.

 ADAMS RESOURCES & ENERGY, INC.
 (Registrant)
  
  
By  /s/ Josh C. Anders
By /s/ Thomas S. Smith
Josh C. AndersThomas S. SmithBy:/s/ Townes G. Pressler
Executive Vice President and Chief Financial OfficerChief Executive OfficerTownes G. Pressler
(Principal Financial Officer and Principal Accounting Officer)Executive Chairman
(Principal Executive Officer)
  
By:/s/ Josh C. Anders
Josh C. Anders
Chief Financial Officer
(Principal Financial Officer and Principal
Accounting Officer)




Date:  March 31, 2017
75


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 Registrantregistrant and in the capacities andindicated below on the date indicated.March 12, 2018.

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


By /s//s/ Townes G. PresslerDirector and Executive Chairman of the Board
Townes G. Pressler
/s/ Larry E. BellDirector
Larry E. Bell
/s/ Murray E. Brasseux
By /s/ E. C. Reinauer, Jr.
Director
Murray E. Brasseux DirectorE. C. Reinauer, Jr., Director
  
/s/ Michelle A. Earley Director
Michelle A. Earley  
By /s/ Larry E. Bell
Richard C. Jenner
By /s/ Michelle A. Earley
Director
Larry E. Bell, DirectorRichard C. JennerMichelle A. Earley, Director
  
/s/ E.C. Reinauer, Jr. Director
E.C. Reinauer, Jr.  
By /s/ Richard C. Jenner
W.R. Scofield
By /s/ W. R. Scofield
Richard C. Jenner, DirectorW. R. Scofield, Director
W.R. Scofield
  


6576

EXHIBIT INDEX

Exhibit
NumberDescription
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
66
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
101.DEF*-          XBRL Definition 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, 2016, 2015 and 2014, (ii) the Consolidated Balance Sheets – December 31, 2016 and December 31, 2015, (iii) the Consolidated Statements of Cash Flows – Year Ended December 31, 2016, 2015 and 2014 and (iv) Notes to Consolidated Financial Statements.
67