Adams Resources & Energy (AE) 10-K 12 Mar 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Mar. 01, 2018	Jun. 30, 2017
Document and Entity Information [Abstract]
Entity Registrant Name	ADAMS RESOURCES & ENERGY, INC.
Entity Central Index Key	2,178
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		4,217,596
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 88,123,994

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
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
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	0
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	0
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	0	0
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

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 303	$ 225
Preferred stock - par value (in dollars per share)	$ 1	$ 1
Preferred stock - shares authorized (in shares)	960,000	960,000
Preferred stock - outstanding (in shares)	0	0
Common stock - par value (in dollars per share)	$ 0.1	$ 0.1
Common stock - shares authorized (in shares)	7,500,000	7,500,000
Common stock - shares issued (in shares)	4,217,596	4,217,596
Common stock - shares outstanding (in shares)	4,217,596	4,217,596

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 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)	0	0
Impairment of investment in unconsolidated affiliate	(2,500)	0	0
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 investments in unconsolidated affiliates, net of tax benefit of $—, $770 and $—, respectively	0	(1,430)	0
Net (losses) earnings	$ (482)	$ 2,513	$ (1,275)
Earnings (losses) per share:
From continuing operations (in dollars per share)	$ (0.11)	$ 0.94	$ (0.30)
From investment in unconsolidated affiliate (in dollars per share)	0	(0.34)	0
Basic and diluted net (losses) earnings per common share (in dollars per share)	$ (0.11)	$ 0.60	$ (0.30)
Weighted average number of common shares outstanding (in shares)	4,218	4,218	4,218
Dividends per common share (in dollars per share)	$ 0.88	$ 0.88	$ 0.88

CONSOLIDATED STATEMENTS OF OPE5

CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Statement [Abstract]
Tax benefit from investments in unconsolidated affiliates	$ 0	$ 770	$ 0

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 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	0	0	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	0	468	0
Impairment of investments in unconsolidated affiliates	2,500	1,732	0
Loss on deconsolidation of subsidiary (Note 3)	3,505	0	0
Changes in assets and liabilities:
Accounts receivable	(34,935)	(15,368)	72,594
Accounts receivable/payable, affiliates	271	0	0
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	0	0
Investments in unconsolidated affiliates	0	(4,700)	0
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)	0	0
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

CONSOLIDATED STATEMENTS OF SHAR

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - USD ($) $ in Thousands	Total	Common Stock [Member]	Contributed Capital [Member]	Retained Earnings [Member]
Beginning balance at Dec. 31, 2014	$ 157,497	$ 422	$ 11,693	$ 145,382
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (losses) earnings	(1,275)	0	0	(1,275)
Dividends paid on common stock	(3,712)	0	0	(3,712)
Ending balance at Dec. 31, 2015	152,510	422	11,693	140,395
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (losses) earnings	2,513	0	0	2,513
Dividends paid on common stock	(3,711)	0	0	(3,711)
Ending balance at Dec. 31, 2016	151,312	422	11,693	139,197
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (losses) earnings	(482)	0	0	(482)
Dividends paid on common stock	(3,711)	0	0	(3,711)
Ending balance at Dec. 31, 2017	$ 147,119	$ 422	$ 11,693	$ 135,004

Organization and Basis of Prese

Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Basis of Presentation	Organization and Basis of Presentation Organization 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 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 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. 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 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. 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.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	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 expenses 137 100 116 Deductions (59 ) (81 ) (89 ) Balance at end of period $ 303 $ 225 $ 206 Cash and Cash Equivalents Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than three months from the date of purchase. Cash and cash equivalents are maintained with major financial institutions, and deposit amounts may exceed the amount of federally backed insurance provided. While we regularly monitor the financial stability of these institutions, cash and cash equivalents ultimately remain at risk subject to the financial viability of these institutions. Derivative Instruments In the normal course of our operations, our crude oil marketing segment purchases and sells crude oil. We seek to profit by procuring the commodity as it is produced and then delivering the product to the end users or the intermediate use marketplace. As typical for the industry, these 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, we account for these contracts at fair value, unless the normal purchase and sale exception is applicable. These types of underlying contracts are standard for the industry and are the governing document for our crude oil marketing segment. None of our derivative instruments have been designated as hedging instruments. Employee Benefits We maintain a 401(k) savings plan for the benefit of our employees. We do not maintain any other pension or retirement plans. Our 401(k) plan contributory expenses were as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 2015 Contributory expenses $ 734 $ 757 $ 768 Earnings Per Share Earnings per share are based on the weighted average number of shares of common stock and potentially dilutive common stock shares outstanding during the period. The weighted average number of shares outstanding was 4,217,596 for each of the years ended December 31, 2017 , 2016 and 2015 . There were no potentially dilutive securities outstanding during those periods. Fair Value Measurements The carrying amounts reported in the consolidated 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. Our fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in 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 business 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 inputs used to estimate such fair values. The hierarchy considers fair value amounts 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. The characteristics of the fair value amounts classified within each level of the hierarchy are described as follows: • Level 1 fair values are based on quoted prices, which are available in active markets for identical assets or liabilities as of the measurement date. Active markets are defined as those in which transactions for identical assets or liabilities occur with sufficient frequency so as to provide pricing information on an ongoing basis. For Level 1 valuation of marketable securities, we utilize market quotations provided by our primary financial institution. For the valuations of derivative financial instruments, we utilize the New York Mercantile Exchange (“NYMEX”) for certain 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 fair values are based on unobservable market data inputs for assets or liabilities. Fair value contracts consist of derivative 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 recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of such items and their 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. 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. 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. Leases . In February 2016, the FASB issued ASC 842, Leases (“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. The 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.

Subsidiary Bankruptcy, Deconsol

Subsidiary Bankruptcy, Deconsolidation and Sale	12 Months Ended
	Dec. 31, 2017
Reorganizations [Abstract]
Subsidiary Bankruptcy, Deconsolidation and Sale	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 AREC’s bankruptcy filing, AE ceded its authority to the Bankruptcy 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 of AREC were removed from our consolidated balance sheet as of April 30, 2017, and we recorded our investment in AREC at its estimated fair value of approximately $5.0 million . We determined the fair value of our investment based upon bids we received in an auction process (see Note 1 for further discussion). We also determined that the estimated 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 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. 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 crude oil 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 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. 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 Possession 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 DIP Credit Agreement. 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.

Prepayments and Other Current A

Prepayments and Other Current Assets	12 Months Ended
	Dec. 31, 2017
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepayments and Other Current Assets	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 other 839 694 Total $ 1,264 $ 2,097

Property and Equipment

Property and Equipment	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Property and Equipment	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 equipment 2 – 5 18,490 18,282 Buildings 5 – 39 15,727 15,707 Office equipment 1 – 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 periods 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 leases 121 — — 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 crude oil 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 impairments 3 283 1,758 Total crude oil and natural gas impairments $ 3 $ 313 $ 12,082 At December 31, 2017 and 2016, we had no capitalized costs for non-producing crude oil and natural gas leasehold interests. Gains on sales of assets We sold certain used trucks and equipment from our marketing and transportation segments and recorded net pre-tax gains as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 2015 Sales of used trucks and equipment $ 594 $ 1,966 $ 535 Asset Retirement Obligations We record AROs for the estimated retirement costs associated with certain tangible long-lived assets. The estimated fair value of AROs 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. If the liability is settled for an amount other than the recorded amount, an increase or decrease to expense is recognized. A summary of our 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 incurred 18 162 39 Accretion of discount 58 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).

Cash Deposits and Other Assets

Cash Deposits and Other Assets	12 Months Ended
	Dec. 31, 2017
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Cash Deposits and Other Assets	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 fund 2,284 1,450 Accumulated interest income 814 812 Other amounts: State collateral deposits 57 143 Materials and supplies 273 354 Other 37 171 Total $ 7,232 $ 5,529 We have established certain deposits to support participation in our liability insurance program and remittance of state crude oil severance taxes and other state collateral deposits. Insurance collateral deposits are held by the insurance company to cover past or potential open claims based upon a percentage of the maximum assessment under our insurance policies. Excess amounts in our loss fund represent premium payments in excess of claims incurred to date that we 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 the fair value hierarchy (see Note 10 for further information).

Investments in Unconsolidated A

Investments in Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Investments in Unconsolidated Affiliates	Investments in Unconsolidated Affiliates At December 31, 2017, we had no remaining balances in our medical-related investments. We currently do not have any plans to pursue 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 equity method of accounting. 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. We completed a review of our equity 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 equity 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 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 April 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 cost method of accounting. During the third quarter of 2017, we reviewed our investment in VestaCare and determined that the current 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. 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.

Segment Reporting

Segment Reporting	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Segment Reporting	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 amortization 7,812 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 amortization 9,997 7,249 1,546 18,792 Property and equipment additions 1,321 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 amortization 11,097 7,554 5,066 23,717 Property and equipment additions 2,126 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 gas segment’s operating earnings included property impairments of $12.1 million for the year ended December 31, 2015 . 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 income 1,103 582 327 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 Transportation 29,069 32,120 35,010 Oil and Gas (1) 425 7,279 8,930 Cash and other 118,465 100,216 102,552 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.

Transactions with Affiliates

Transactions with Affiliates	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Transactions with Affiliates	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. 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 us 81 65 68 Billings to affiliates 4 5 35 Rentals paid to affiliate 583 628 618 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).

Derivative Instruments and Fair

Derivative Instruments and Fair Value Measurements	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Fair Value Measurements	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. 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 ) 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 recurring 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 own nonperformance risk and our counterparty’s nonperformance risk. When adjusting the fair value of derivative contracts for the effect of nonperformance risk, we consider the impact of netting and any 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 included in their entirety in the fair value hierarchy. Nonrecurring Fair Value Measurements Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring 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 year 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 long-lived assets that were subject to non-recurring fair value measurements during the year ended December 31, 2016 (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 2016 (Level 1) (Level 2) (Level 3) Loss Investment in Bencap $ — $ — $ — $ — $ 2,200 Oil and gas properties 62,784 — — 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

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The components of our income tax (provision) benefit were as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 2015 Current: Federal $ (1,418 ) $ (2,103 ) $ (3,883 ) State 523 (675 ) (190 ) Total current (895 ) (2,778 ) (4,073 ) Deferred: Federal 3,722 777 5,011 State 118 80 (168 ) Total deferred 3,840 857 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 taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes was as follows for the periods indicated (in thousands): 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) benefit 736 (387 ) (233 ) Federal statutory depletion 153 62 144 Federal tax rate adjustment 2,007 — — 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 . Deferred income taxes reflect the net difference between the financial statement carrying amounts and the underlying income tax basis in these items. The components of the federal deferred tax asset (liability) were as follows at 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 affiliates 623 606 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. 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. We 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 Federal 2013 Texas 2013 Louisiana 2014 Michigan 2013 Other Matters The Tax Cuts and Jobs Act (the “Act”) was signed into law on December 22, 2017. The Act changed many aspects of U.S. corporate income taxation and included a reduction of the 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 tax effects of the Act in the year 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 issued but do not currently anticipate significant revisions will be necessary. Any such revisions will be treated in accordance with the measurement period guidance outlined in Staff Accounting Bulletin No. 118.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2017
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	Supplemental Cash Flow Information Supplemental cash flows and non-cash transactions were as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 2015 Cash paid for interest $ 22 $ 2 $ 13 Cash paid for federal and state taxes 459 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 leases 1,808 — —

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitment and Contingencies Capital Lease Obligations During the third quarter of 2017, we entered into capital leases for certain of our 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 in total thereafter (in thousands): 2018 $ 398 2019 398 2020 398 2021 398 2022 255 Thereafter — Total minimum lease payments 1,847 Less: Amount representing interest (158 ) Present value of capital lease obligations 1,689 Less current portion of capital lease obligations (338 ) Total long-term capital lease obligations $ 1,351 Operating Lease Obligations We lease certain property and equipment under noncancellable and cancelable operating leases. Our significant lease agreements consist of (i) arrangements with independent truck owner-operators for use of their equipment and driver services; (ii) leased office space; and (iii) certain lease and terminal access contracts in order to provide tank storage and dock access for our crude oil marketing business. Currently, our significant lease agreements have terms that range from one to eight years. 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 periods indicated (in thousands): Year Ended December 31, 2017 2016 2015 Rental expense $ 12,073 $ 11,314 $ 11,168 At December 31, 2017 , rental obligations under 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 thousands): 2018 2019 2020 2021 2022 Thereafter Total Operating leases $ 2,758 $ 463 $ 68 $ 63 $ 32 $ 23 $ 3,407 Insurance Policies Under our automobile and workers’ compensation insurance policies that 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 was shared with a group of similarly situated entities through an insurance captive. We have appropriately recognized estimated expenses and liabilities related to these policies for losses incurred but not reported to us or our insurance carrier. The amount of pre-funded insurance premiums left to cover potential future losses totaled as follows at the dates indicated (in thousands): 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. We also maintain third party insurance stop-loss coverage for annual aggregate medical claims exceeding $4.5 million . Medical accrual amounts were as follows at the dates indicated (in thousands): December 31, 2017 2016 Accrued medical claims $ 1,329 $ 1,411 Litigation AREC was named as a defendant in a number of Louisiana lawsuits involving alleged environmental contamination from prior drilling operations. Such suits typically allege improper disposal of oilfield wastes in earthen pits, with one matter involving allegations that drilling operations in 1986 contributed to the formation of a 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 two other suits. These suits are styled LePetit Chateau Deluxe v. Adams Resources Exploration Corporation dated March 2004 filed in Acadia Parish, Louisiana, and Henning Management, LLC v. Adams Resources Exploration Corporation dated November 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 we do not believe that these claims will result in a material adverse effect on us, significant attorney fees may be incurred to address claims related to these suits. At December 31, 2016 , we had $0.5 million accrued for future legal 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 our operations, we may become involved in various lawsuits and/or disputes. Primarily as an operator of an extensive trucking fleet, we are a party to motor vehicle accidents, worker compensation claims and other items of general liability as would be typical for the industry. We are presently unaware of any claims against us that are either outside the scope of insurance coverage or that may exceed the level of insurance coverage and could potentially represent a material adverse effect on our financial position or results of operations. 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 these arrangements is to guarantee the performance of the subsidiary in meeting their respective underlying obligations. 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. At December 31, 2017 , parental guaranteed obligations were approximately $48.2 million . Currently, neither AE nor any of its subsidiaries has any other types of guarantees outstanding that require liability recognition.

Concentration of Credit Risk

Concentration of Credit Risk	12 Months Ended
	Dec. 31, 2017
Risks and Uncertainties [Abstract]
Concentration of Credit Risk	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. Our 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, alternative 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 shown in the table 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 %

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data (Unaudited)	Quarterly Financial Information (Unaudited) The following table presents selected quarterly financial data for the periods indicated (in thousands, except per share data): 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) earnings 2,339 5,601 (1,822 ) (64 ) Earnings (losses) from continuing operations 1,554 3,540 (983 ) (168 ) Net (losses) earnings 1,430 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 )

Oil and Gas Producing Activitie

Oil and Gas Producing Activities (Unaudited)	12 Months Ended
	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil and Gas Producing Activities (Unaudited)	Oil and Gas Producing Activities (Unaudited) Our wholly owned subsidiary, AREC, 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 were maintained in Houston, and at December 31, 2016, we held an interest in 470 producing wells of which we 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 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 U.S., were as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 2015 Property acquisition costs: Unproved $ 4 $ 32 $ 348 Proved — — — Exploration costs: Expensed 5 291 1,667 Capitalized — — — Development costs 1,815 — 370 Total costs incurred $ 1,824 $ 323 $ 2,385 The aggregate capitalized costs relative to crude oil and natural gas producing activities were as follows at 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 Estimated Crude Oil and Natural Gas Reserves The following information regarding estimates of our proved crude oil and natural gas reserves, substantially all located onshore in Texas and Louisiana, was based on reports prepared on our behalf by our 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. Proved developed and undeveloped reserves were as follows for the periods indicated (in thousands): 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 year 4,214 187 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 additions 42 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 periods indicated (in thousands): 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. We assigned responsibility for compliance in reserve bookings to the office of President of AREC. No portion of this individual’s compensation was 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. We employed a third party petroleum consultant, Ryder Scott Company, to prepare our crude oil and natural gas reserve data estimates as of December 31, 2016 and 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. 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 were included in contracts. The disclosures below do not purport to present the fair market value of our 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 was as follows for 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 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, our independent petroleum engineers assumed market prices as presented in the table below: 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 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 included the value of associated natural gas liquids. Crude 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 was as follows for the periods indicated (in thousands): 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 were as follows for 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 discount 130 194 1,116 Production rate changes and other (493 ) (945 ) (3,603 ) Net change in income taxes 1,217 682 6,578 End of year $ — $ 2,260 $ 3,527 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, were as follows for the periods indicated (in thousands): 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 taxes 53 (1,503 ) (19,016 ) Income tax benefit (expense) (19 ) 526 6,656 Operating earnings (losses) $ 34 $ (977 ) $ (12,360 )

Summary of Significant Accoun24

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Consolidation	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 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 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. 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 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.
Use of Estimates	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.
Accounts Receivable and Allowance for Doubtful Accounts	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.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than three months from the date of purchase. Cash and cash equivalents are maintained with major financial institutions, and deposit amounts may exceed the amount of federally backed insurance provided. While we regularly monitor the financial stability of these institutions, cash and cash equivalents ultimately remain at risk subject to the financial viability of these institutions.
Derivative Instruments	Derivative Instruments In the normal course of our operations, our crude oil marketing segment purchases and sells crude oil. We seek to profit by procuring the commodity as it is produced and then delivering the product to the end users or the intermediate use marketplace. As typical for the industry, these 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, we account for these contracts at fair value, unless the normal purchase and sale exception is applicable. These types of underlying contracts are standard for the industry and are the governing document for our crude oil marketing segment. None of our derivative instruments have been designated as hedging instruments.
Earnings Per Share	Earnings Per Share Earnings per share are based on the weighted average number of shares of common stock and potentially dilutive common stock shares outstanding during the period. The weighted average number of shares outstanding was 4,217,596 for each of the years ended December 31, 2017 , 2016 and 2015 . There were no potentially dilutive securities outstanding during those periods.
Fair Value Measurements	Fair Value Measurements The carrying amounts reported in the consolidated 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. Our fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in 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 business 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 inputs used to estimate such fair values. The hierarchy considers fair value amounts 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. The characteristics of the fair value amounts classified within each level of the hierarchy are described as follows: • Level 1 fair values are based on quoted prices, which are available in active markets for identical assets or liabilities as of the measurement date. Active markets are defined as those in which transactions for identical assets or liabilities occur with sufficient frequency so as to provide pricing information on an ongoing basis. For Level 1 valuation of marketable securities, we utilize market quotations provided by our primary financial institution. For the valuations of derivative financial instruments, we utilize the New York Mercantile Exchange (“NYMEX”) for certain 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 fair values are based on unobservable market data inputs for assets or liabilities. Fair value contracts consist of derivative 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	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 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 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.
Inventory	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	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 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	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.
Revenue Recognition	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	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. Leases . In February 2016, the FASB issued ASC 842, Leases (“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. The 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.
Cash Deposits and Other Assets	We have established certain deposits to support participation in our liability insurance program and remittance of state crude oil severance taxes and other state collateral deposits. Insurance collateral deposits are held by the insurance company to cover past or potential open claims based upon a percentage of the maximum assessment under our insurance policies. Excess amounts in our loss fund represent premium payments in excess of claims incurred to date that we 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 the fair value hierarchy (see Note 10 for further information).

Summary of Significant Accoun25

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Changes in the allowance for doubtful accounts	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 expenses 137 100 116 Deductions (59 ) (81 ) (89 ) Balance at end of period $ 303 $ 225 $ 206
Schedule of cost of retirement plans	Our 401(k) plan contributory expenses were as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 2015 Contributory expenses $ 734 $ 757 $ 768
Reporting revenue of crude oil contracts on a gross revenue basis	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

Prepayments and Other Current26

Prepayments and Other Current Assets (Tables)	12 Months Ended
	Dec. 31, 2017
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Components of 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 other 839 694 Total $ 1,264 $ 2,097

Property and Equipment (Tables)

Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Property and equipment	Components of depreciation, depletion and amortization expense were as follows for the periods 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 leases 121 — — Total depreciation, depletion and amortization $ 13,599 $ 18,792 $ 23,717 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 equipment 2 – 5 18,490 18,282 Buildings 5 – 39 15,727 15,707 Office equipment 1 – 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).
Fair value of impairment provisions	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 impairments 3 283 1,758 Total crude oil and natural gas impairments $ 3 $ 313 $ 12,082
Pre-tax gain on the sale of equipment	We sold certain used trucks and equipment from our marketing and transportation segments and recorded net pre-tax gains as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 2015 Sales of used trucks and equipment $ 594 $ 1,966 $ 535
Company's asset retirement obligations	A summary of our 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 incurred 18 162 39 Accretion of discount 58 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).

Cash Deposits and Other Assets

Cash Deposits and Other Assets (Tables)	12 Months Ended
	Dec. 31, 2017
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Components of 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 fund 2,284 1,450 Accumulated interest income 814 812 Other amounts: State collateral deposits 57 143 Materials and supplies 273 354 Other 37 171 Total $ 7,232 $ 5,529

Segment Reporting (Tables)

Segment Reporting (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Information concerning business activities	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 amortization 7,812 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 amortization 9,997 7,249 1,546 18,792 Property and equipment additions 1,321 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 amortization 11,097 7,554 5,066 23,717 Property and equipment additions 2,126 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 gas segment’s operating earnings included property impairments of $12.1 million for the year ended December 31, 2015 .
Reconciliation of segment earnings to earnings before income taxes	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 income 1,103 582 327 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	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 Transportation 29,069 32,120 35,010 Oil and Gas (1) 425 7,279 8,930 Cash and other 118,465 100,216 102,552 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.

Transactions with Affiliates (T

Transactions with Affiliates (Tables)	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Schedule of activities with affiliates	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 us 81 65 68 Billings to affiliates 4 5 35 Rentals paid to affiliate 583 628 618 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.

Derivative Instruments and Fa31

Derivative Instruments and Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives reflected in the consolidated balance sheet	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 $ — 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 $ —
Derivatives reflected in the consolidated statement of operations	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 )
Fair value assets and liabilities	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
Fair value, nonrecurring	The following table presents categories of long-lived assets that were subject to non-recurring fair value measurements during the year 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 long-lived assets that were subject to non-recurring fair value measurements during the year ended December 31, 2016 (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 2016 (Level 1) (Level 2) (Level 3) Loss Investment in Bencap $ — $ — $ — $ — $ 2,200 Oil and gas properties 62,784 — — 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

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Components of the company's income tax (provision) benefit	The components of our income tax (provision) benefit were as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 2015 Current: Federal $ (1,418 ) $ (2,103 ) $ (3,883 ) State 523 (675 ) (190 ) Total current (895 ) (2,778 ) (4,073 ) Deferred: Federal 3,722 777 5,011 State 118 80 (168 ) Total deferred 3,840 857 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.
Reconciliation of taxes computed at the corporate federal income tax rate to the reported income tax (provision)	A reconciliation of the provision for (benefit from) income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes was as follows for the periods indicated (in thousands): 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) benefit 736 (387 ) (233 ) Federal statutory depletion 153 62 144 Federal tax rate adjustment 2,007 — — 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 .
Components of the federal deferred tax asset (liability)	Deferred income taxes reflect the net difference between the financial statement carrying amounts and the underlying income tax basis in these items. The components of the federal deferred tax asset (liability) were as follows at 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 affiliates 623 606 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.
Earliest tax years remaining for federal and major states of operations	The earliest tax years remaining open for audit for federal and major states of operations are as follows: Earliest Open Tax Year Federal 2013 Texas 2013 Louisiana 2014 Michigan 2013

Supplemental Cash Flow Inform33

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2017
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	Supplemental cash flows and non-cash transactions were as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 2015 Cash paid for interest $ 22 $ 2 $ 13 Cash paid for federal and state taxes 459 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 leases 1,808 — —

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Schedule of principal contractual commitments outstanding under our capital leases	The following table summarizes our principal contractual commitments outstanding under our capital leases at December 31, 2017 for the next five years, and in total thereafter (in thousands): 2018 $ 398 2019 398 2020 398 2021 398 2022 255 Thereafter — Total minimum lease payments 1,847 Less: Amount representing interest (158 ) Present value of capital lease obligations 1,689 Less current portion of capital lease obligations (338 ) Total long-term capital lease obligations $ 1,351
Rental expense	Rental expense was as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 2015 Rental expense $ 12,073 $ 11,314 $ 11,168
Long-term non-cancelable operating leases and terminal arrangements for the next five years	At December 31, 2017 , rental obligations under 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 thousands): 2018 2019 2020 2021 2022 Thereafter Total Operating leases $ 2,758 $ 463 $ 68 $ 63 $ 32 $ 23 $ 3,407
Schedule of expenses and losses incurred but not reported	We have appropriately recognized estimated expenses and liabilities related to these policies for losses incurred but not reported to us or our insurance carrier. The amount of pre-funded insurance premiums left to cover potential future losses totaled as follows at the dates indicated (in thousands): December 31, 2017 2016 Pre-funded premiums for losses incurred but not reported $ 988 $ 2,657
Schedule of accrued medical claims	Medical accrual amounts were as follows at the dates indicated (in thousands): December 31, 2017 2016 Accrued medical claims $ 1,329 $ 1,411

Concentration of Credit Risk (T

Concentration of Credit Risk (Tables)	12 Months Ended
	Dec. 31, 2017
Risks and Uncertainties [Abstract]
Schedule of concentration of risk	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 shown in the table 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 %

Quarterly Financial Data (Una36

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Selected quarterly financial data and earnings per share	The following table presents selected quarterly financial data for the periods indicated (in thousands, except per share data): 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) earnings 2,339 5,601 (1,822 ) (64 ) Earnings (losses) from continuing operations 1,554 3,540 (983 ) (168 ) Net (losses) earnings 1,430 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 )

Oil and Gas Producing Activit37

Oil and Gas Producing Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Cost incurred in oil and gas exploration and development activities	Total costs incurred in crude oil and natural gas exploration and development activities, all within the U.S., were as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 2015 Property acquisition costs: Unproved $ 4 $ 32 $ 348 Proved — — — Exploration costs: Expensed 5 291 1,667 Capitalized — — — Development costs 1,815 — 370 Total costs incurred $ 1,824 $ 323 $ 2,385
Capitalized costs relating to oil and gas producing activities	The aggregate capitalized costs relative to crude oil and natural gas producing activities were as follows at 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
Proved developed and undeveloped oil and gas reserves	Proved developed and undeveloped reserves were as follows for the periods indicated (in thousands): 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 year 4,214 187 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 additions 42 6 151 18 86 13 Production (189 ) (23 ) (662 ) (77 ) (889 ) (100 ) End of year — — 4,214 187 4,835 226
Components of proved oil and gas reserves	The components of our previously owned proved crude oil and natural gas reserves, all within the U.S., were as follows for the periods indicated (in thousands): 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
Standardized measure of discounted future net cash flows	The standardized measure of discounted future net cash flows was as follows for 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
Assumed market prices of oil and natural gas reserves and future net revenues	For such estimates, our independent petroleum engineers assumed market prices as presented in the table below: 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
Effect of income taxes and discounting on the standardized measure of discounted future net cash flows	The effect of income taxes and discounting on the standardized measure of discounted future net cash flows was as follows for the periods indicated (in thousands): 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
Principal sources of changes in the standardized measure of discounted future net flows	The principal sources of changes in the standardized measure of discounted future net cash flows were as follows for 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 discount 130 194 1,116 Production rate changes and other (493 ) (945 ) (3,603 ) Net change in income taxes 1,217 682 6,578 End of year $ — $ 2,260 $ 3,527
Results of operations for oil and gas producing activities	The results of crude oil and natural gas producing activities, excluding corporate overhead and interest costs, were as follows for the periods indicated (in thousands): 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 taxes 53 (1,503 ) (19,016 ) Income tax benefit (expense) (19 ) 526 6,656 Operating earnings (losses) $ 34 $ (977 ) $ (12,360 )

Organization and Basis of Pre38

Organization and Basis of Presentation (Details)	3 Months Ended	12 Months Ended
	Sep. 30, 2017agreement	Dec. 31, 2017statesegment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of states in which entity operates | state		48
Number of asset purchase and sales agreements with three unaffiliated parties | agreement	3
Number of operating segments		3
Number of reportable segments		3

Summary of Significant Accoun39

Summary of Significant Accounting Policies - Accounts Receivable and Allowance for Doubtful Accounts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Concentration Risk [Line Items]
Industry practice payment of receivables	20 days
Changes in the allowance for doubtful accounts [Roll Forward]
Balance at beginning of period	$ 225	$ 206	$ 179
Charges to costs and expenses	137	100	116
Deductions	(59)	(81)	(89)
Balance at end of period	$ 303	$ 225	$ 206
Product Concentration Risk [Member] | Accounts Receivable [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	90.00%

Summary of Significant Accoun40

Summary of Significant Accounting Policies - Employee Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Contributory expenses	$ 734	$ 757	$ 768

Summary of Significant Accoun41

Summary of Significant Accounting Policies - Earnings per Share (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Weighted average number of common shares outstanding (in shares)	4,218	4,218	4,218

Summary of Significant Accoun42

Summary of Significant Accounting Policies - Letter of Credit Facility (Details) - Wells Fargo Bank [Member]	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity	$ 60,000,000
Current ratio	1.1
Standby Letters of Credit [Member]
Line of Credit Facility [Line Items]
Letters of credit outstanding	$ 2,200,000	$ 0

Summary of Significant Accoun43

Summary of Significant Accounting Policies - Property and Equipment (Details)	12 Months Ended
	Dec. 31, 2017
Minimum [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, useful life	3 years
Maximum [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, useful life	20 years

Summary of Significant Accoun44

Summary of Significant Accounting Policies - Revenue Recognition (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Revenue gross-up	$ 203,095	$ 314,270	$ 480,111

Subsidiary Bankruptcy, Decons45

Subsidiary Bankruptcy, Deconsolidation and Sale (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Sep. 30, 2017	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Aug. 01, 2017	Apr. 30, 2017	Apr. 25, 2017
Subsidiary Bankruptcy and Deconsolidation [Line Items]
Loss on deconsolidation of subsidiary (Note 3)			$ 3,505	$ 0	$ 0
Proceeds from sales of AREC assets			$ 2,775	$ 0	$ 0
AREC [Member]
Subsidiary Bankruptcy and Deconsolidation [Line Items]
Loss on deconsolidation of subsidiary (Note 3)		$ 1,600
DIP financing amount arranged								$ 1,250
DIP amount outstanding		400
Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | AREC [Member]
Subsidiary Bankruptcy and Deconsolidation [Line Items]
Expected transaction price		$ 5,000				$ 5,200	$ 5,000
Loss on disposal	$ 1,900
London Interbank Offered Rate (LIBOR) [Member] | AREC [Member]
Subsidiary Bankruptcy and Deconsolidation [Line Items]
DIP financing, interest rate								2.00%

Prepayments and Other Current46

Prepayments and Other Current Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Insurance premiums	$ 425	$ 1,403
Rents, licenses and other	839	694
Total	$ 1,264	$ 2,097

Property and Equipment - Cost o

Property and Equipment - Cost of Property and Equipment and Related Accumulated Depreciaiton, Depletion, and Amortization (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Property and equipment, gross	$ 126,276	$ 190,648
Less accumulated depreciation, depletion and amortization	(96,914)	(144,323)
Property and equipment, net	29,362	46,325
Depreciation, depletion and amortization	$ 13,599	18,792	$ 23,717
Minimum [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, useful life	3 years
Maximum [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, useful life	20 years
Tractors and Trailers [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, gross	$ 88,065	89,576
Tractors and Trailers [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, useful life	5 years
Tractors and Trailers [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, useful life	6 years
Oil and Gas (Successful Efforts) [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, gross	$ 0	62,784
Field Equipment [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, gross	$ 18,490	18,282
Field Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, useful life	2 years
Field Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, useful life	5 years
Buildings [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, gross	$ 15,727	15,707
Buildings [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, useful life	5 years
Buildings [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, useful life	39 years
Office Equipment [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, gross	$ 1,929	1,913
Office Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, useful life	1 year
Office Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, useful life	5 years
Land [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, gross	$ 1,790	1,790
Construction in Progress [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, gross	275	596
Assets Held under Capital Leases [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, gross	1,800
Less accumulated depreciation, depletion and amortization	(100)
Depreciation, depletion and amortization	121	0	0
Assets Not Held under Capital Leases [Member]
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization	$ 13,478	$ 18,792	$ 23,717

Property and Equipment - Fair V

Property and Equipment - Fair Value of Impairment Provisions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Oil and natural gas property impairments	$ 3	$ 313	$ 12,082
Oil and Gas (Successful Efforts) [Member]
Property, Plant and Equipment [Line Items]
Oil and natural gas property impairments	0	30	10,324
Non Producing Oil and Gas Properties [Member]
Property, Plant and Equipment [Line Items]
Oil and natural gas property impairments	$ 3	$ 283	$ 1,758

Property and Equipment - Sales

Property and Equipment - Sales of Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Sales of used trucks and equipment	$ 594	$ 1,966	$ 535
Trucks [Member]
Property, Plant and Equipment [Line Items]
Sales of used trucks and equipment	$ 594	$ 1,966	$ 535

Property and Equipment - Asset

Property and Equipment - Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO liability beginning balance	$ 2,329	$ 2,469	$ 2,464
Liabilities incurred	18	162	39
Accretion of discount	58	92	93
Liabilities settled	(261)	(394)	(127)
Deconsolidation of subsidiary	(871)	0	0
ARO liability ending balance	$ 1,273	$ 2,329	$ 2,469

Cash Deposits and Other Asset51

Cash Deposits and Other Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Insurance collateral deposits	$ 3,767	$ 2,599
Excess loss fund	2,284	1,450
Accumulated interest income	814	812
State collateral deposits	57	143
Materials and supplies	273	354
Other	37	171
Total	$ 7,232	$ 5,529

Investments in Unconsolidated52

Investments in Unconsolidated Affiliates (Details) - USD ($)	1 Months Ended			3 Months Ended			12 Months Ended
	Feb. 28, 2017	Apr. 30, 2016	Jan. 31, 2016	Sep. 30, 2017	Jun. 30, 2017	Sep. 30, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Recognized net loss from investment							$ 0	$ 1,430,000	$ 0
Impairment of investments in unconsolidated affiliates							2,500,000	0	0
Losses from equity investment							0	468,000	0
Loss on deconsolidation of subsidiary (Note 3)							3,505,000	0	0
Proceeds from sales of AREC assets							$ 2,775,000	$ 0	$ 0
AREC [Member]
Schedule of Equity Method Investments [Line Items]
Loss on deconsolidation of subsidiary (Note 3)					$ 1,600,000
DIP amount outstanding					$ 400,000
AREC [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member]
Schedule of Equity Method Investments [Line Items]
Loss on disposal				$ 1,900,000
Bencap LLC [Member]
Schedule of Equity Method Investments [Line Items]
Maximum borrowing amount			$ 1,500,000
Income tax benefit						$ 800,000
Percentage of equity method investment							0.00%
VestaCare, Inc. [Member]
Schedule of Equity Method Investments [Line Items]
Voting interest		3.00%
Impairment of investments in unconsolidated affiliates				$ 2,500,000
Percentage of equity method investment		15.00%					15.00%
Bencap LLC [Member]
Schedule of Equity Method Investments [Line Items]
Voting interest			30.00%
Cash payment for acquisition			$ 2,200,000
Recognized net loss from investment						1,400,000
Impairment of investments in unconsolidated affiliates						1,700,000
Losses from equity investment						$ 500,000
Additional funding request	$ 500,000
VestaCare, Inc. [Member]
Schedule of Equity Method Investments [Line Items]
Cash payment for acquisition		$ 2,500,000

Segment Reporting - Information

Segment Reporting - Information concerning business activities (Details) $ in Thousands	1 Months Ended	3 Months Ended								12 Months Ended
	Aug. 31, 2017USD ($)	Dec. 31, 2017USD ($)	Sep. 30, 2017USD ($)	Jun. 30, 2017USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2017USD ($)segment	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | segment										3
Revenues		$ 408,460	$ 295,311	$ 315,202	$ 303,087	$ 298,969	$ 256,877	$ 293,163	$ 250,531	$ 1,322,060	$ 1,099,540	$ 1,944,279
Operating earnings (losses)										1,502	6,054	(2,359)
Depreciation, depletion and amortization										13,599	18,792	23,717
Property and equipment additions										2,644	8,484	11,074
Voluntary early retirement program expense	$ 400									1,000
Property and equipment acquired under capital leases										1,808	0	0
Marketing [Member]
Segment Reporting Information [Line Items]
Revenues										1,267,275	1,043,775	1,875,885
Depreciation, depletion and amortization										7,812	9,997	11,097
Property and equipment additions										468	1,321	2,126
Inventory liquidation gains and valuation (losses)		$ 3,300				$ 8,200				3,300	8,200	5,400
Transportation [Member]
Segment Reporting Information [Line Items]
Revenues										53,358	52,355	63,331
Depreciation, depletion and amortization										5,364	7,249	7,554
Property and equipment additions										351	6,868	6,579
Oil and Gas [Member]
Segment Reporting Information [Line Items]
Revenues										1,427	3,410	5,063
Depreciation, depletion and amortization										423	1,546	5,066
Property and equipment additions										1,825	295	2,369
Property impairments												12,100
Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating earnings (losses)										11,209	16,464	7,580
Operating Segments [Member] | Marketing [Member]
Segment Reporting Information [Line Items]
Operating earnings (losses)										11,700	17,045	22,895
Operating Segments [Member] | Transportation [Member]
Segment Reporting Information [Line Items]
Operating earnings (losses)										(544)	(48)	3,701
Operating Segments [Member] | Oil and Gas [Member]
Segment Reporting Information [Line Items]
Operating earnings (losses)										$ 53	$ (533)	$ (19,016)

Segment Reporting - Reconciliat

Segment Reporting - Reconciliation of segment earnings to earnings before income taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Operating earnings (losses)	$ 1,502	$ 6,054	$ (2,359)
Loss on deconsolidation of subsidiary	(3,505)	0	0
Impairment of investment in unconsolidated affiliate	(2,500)	0	0
Interest income	1,103	582	327
Interest expense	(27)	(2)	(13)
(Losses) earnings before income taxes and investment in unconsolidated affiliate	(3,427)	6,634	(2,045)
Operating Segments [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Operating earnings (losses)	11,209	16,464	7,580
Corporate, Non-Segment [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Operating earnings (losses)	(9,707)	(10,410)	(9,939)
Segment Reconciling Items [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Loss on deconsolidation of subsidiary	(3,505)	0	0
Impairment of investment in unconsolidated affiliate	(2,500)	0	0
Interest income	1,103	582	327
Interest expense	$ (27)	$ (2)	$ (13)

Segment Reporting - Identifiabl

Segment Reporting - Identifiable assets by industry segment (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Assets	$ 282,704	$ 246,872
Operating Segments [Member]
Segment Reporting Information [Line Items]
Assets	282,704	246,872	$ 243,215
Operating Segments [Member] | Marketing [Member]
Segment Reporting Information [Line Items]
Assets	134,745	107,257	96,723
Operating Segments [Member] | Transportation [Member]
Segment Reporting Information [Line Items]
Assets	29,069	32,120	35,010
Operating Segments [Member] | Oil and Gas [Member]
Segment Reporting Information [Line Items]
Assets	425	7,279	8,930
Corporate, Non-Segment [Member]
Segment Reporting Information [Line Items]
Assets	$ 118,465	$ 100,216	$ 102,552

Transactions with Affiliates (D

Transactions with Affiliates (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Interest income on DIP financing	$ 100
Bencap LLC [Member]
Related Party Transaction [Line Items]
Percentage of equity method investment	0.00%
Affiliated Entities [Member]
Related Party Transaction [Line Items]
Overhead recoveries (1)	$ 0	$ 32	$ 97
Affiliate billings to us	81	65	68
Billings to affiliates	4	5	35
Rentals paid to affiliate	583	628	618
Fees paid to Bencap	$ 108	$ 583	$ 0

Derivative Instruments and Fa57

Derivative Instruments and Fair Value Measurements - Use of derivative instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivative, Fair Value, Net [Abstract]
As reported fair value contracts	$ 166	$ 112
As reported fair value contracts	145	64
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Current Assets [Member]
Derivative, Fair Value, Net [Abstract]
Asset derivatives:	166	378
Liability derivatives:	0	0
Less counterparty offsets	0	(266)
As reported fair value contracts	166	112
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Other Assets [Member]
Derivative, Fair Value, Net [Abstract]
Asset derivatives:	0	0
Liability derivatives:	0	0
Less counterparty offsets	0	0
As reported fair value contracts	0	0
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Current Liabilities [Member]
Derivative, Fair Value, Net [Abstract]
Asset derivatives:	0	0
Liability derivatives:	145	330
Less counterparty offsets	0	(266)
As reported fair value contracts	145	64
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Other Liabilities [Member]
Derivative, Fair Value, Net [Abstract]
Asset derivatives:	0	0
Liability derivatives:	0	0
Less counterparty offsets	0	0
As reported fair value contracts	$ 0	$ 0

Derivative Instruments and Fa58

Derivative Instruments and Fair Value Measurements - Narrative (Details) - Commodity Contract [Member] bbl in Thousands	12 Months Ended
	Dec. 31, 2017barrel_of_oil_per_daycontract	Dec. 31, 2016barrel_of_oil_per_daycontractbbl
Derivative [Line Items]
Number of contracts held | contract	20	2
Reported Value Measurement [Member]
Derivative [Line Items]
Number of contracts held | contract	4
January 2018 [Member]
Derivative [Line Items]
Production per day	452
February through May 2018 [Member]
Derivative [Line Items]
Production per day	322
June 2018 [Member]
Derivative [Line Items]
Production per day	258
July 2018 [Member]
Derivative [Line Items]
Production per day	646
August through September 2018 [Member]
Derivative [Line Items]
Production per day	322
October through December 2018 [Member]
Derivative [Line Items]
Production per day	258
January through March 2017 [Member]
Derivative [Line Items]
Production per day		65
January through April 2017 [Member]
Derivative [Line Items]
Production per month | bbl		145

Derivative Instruments and Fa59

Derivative Instruments and Fair Value Measurements - Forward month commodity contracts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Commodity Contract [Member] | Revenues - Marketing [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Revenues – Marketing	$ (26)	$ 243	$ (188)

Derivative Instruments and Fa60

Derivative Instruments and Fair Value Measurements - Derivatives by hedging relationship and fair value measurements (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivatives:
Current assets	$ 166	$ 112
Current assets, counterparty offsets	0	(266)
Current liabilities	(145)	(64)
Current liabilities, counterparty offsets	0	266
Net value	21	48
Net value, counterparty offsets	0	0
Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) [Member]
Derivatives:
Current assets	0	0
Current liabilities	0	0
Net value	0	0
Significant Unobservable Inputs (Level 3) [Member]
Derivatives:
Current assets	166	378
Current liabilities	(145)	(330)
Net value	21	48
Significant Unobservable Inputs (Level 3) [Member]
Derivatives:
Current assets	0	0
Current liabilities	0	0
Net value	$ 0	$ 0

Derivative Instruments and Fa61

Derivative Instruments and Fair Value Measurements - Nonrecurring fair value measurements (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Non-cash impairment loss	$ 3,505	$ 0	$ 0
Fair Value, Measurements, Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Non-cash impairment loss	6,005	2,513
Fair Value, Measurements, Nonrecurring [Member] | AREC [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	425
Non-cash impairment loss	3,505
Fair Value, Measurements, Nonrecurring [Member] | VestaCare, Inc. [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0
Non-cash impairment loss	2,500
Fair Value, Measurements, Nonrecurring [Member] | Bencap LLC [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments		0
Non-cash impairment loss		2,200
Fair Value, Measurements, Nonrecurring [Member] | Oil and Gas Properties [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments		62,784	77,117
Non-cash impairment loss		313	12,082
Fair Value, Measurements, Nonrecurring [Member] | Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) [Member] | AREC [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0
Fair Value, Measurements, Nonrecurring [Member] | Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) [Member] | VestaCare, Inc. [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0
Fair Value, Measurements, Nonrecurring [Member] | Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) [Member] | Bencap LLC [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments		0
Fair Value, Measurements, Nonrecurring [Member] | Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) [Member] | Oil and Gas Properties [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments		0	0
Fair Value, Measurements, Nonrecurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | AREC [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	425
Fair Value, Measurements, Nonrecurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | VestaCare, Inc. [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0
Fair Value, Measurements, Nonrecurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Bencap LLC [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments		0
Fair Value, Measurements, Nonrecurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Oil and Gas Properties [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments		0	0
Fair Value, Measurements, Nonrecurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | AREC [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0
Fair Value, Measurements, Nonrecurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | VestaCare, Inc. [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	$ 0
Fair Value, Measurements, Nonrecurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Bencap LLC [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments		0
Fair Value, Measurements, Nonrecurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Oil and Gas Properties [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments		$ 62,784	$ 77,117

Income Taxes - Components of th

Income Taxes - Components of the company's income tax (provision) benefit (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current:
Federal	$ (1,418)	$ (2,103)	$ (3,883)
State	523	(675)	(190)
Total current	(895)	(2,778)	(4,073)
Deferred:
Federal	3,722	777	5,011
State	118	80	(168)
Total deferred	3,840	857	4,843
Total provision for (benefit from) income taxes (1)	2,945	(1,921)	770
Tax benefit from investments in unconsolidated affiliates	$ 0	$ (770)	$ 0

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of taxes computed at the corporate federal income tax rate to the reported income tax (provision) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
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) benefit	736	(387)	(233)
Federal statutory depletion	153	62	144
Federal tax rate adjustment	2,007	0	0
Valuation allowance	(1,038)	0	0
Other	(78)	(44)	143
Total provision for (benefit from) income taxes (1)	$ 2,945	$ (1,921)	$ 770
Effective income tax rate	86.00%	43.00%	38.00%
Pre-tax losses from investments in unconsolidated affiliates		$ 2,200

Income Taxes - Other matters (D

Income Taxes - Other matters (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Income Tax Disclosure [Abstract]
Effective income tax rate excluding adjustment	58.00%
Tax benefit from remeasurement of deferred tax liabilities	$ 2

Income Taxes - Components of 65

Income Taxes - Components of the federal deferred tax asset (liability) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Long-term deferred tax asset (liability) [Abstract]
Prepaid and other insurance	$ (684)	$ (1,058)
Property	(2,497)	(7,341)
Investments in unconsolidated affiliates	623	606
Valuation allowance related to investments in unconsolidated affiliates	(623)	0
Uniform capitalization	0	729
Other	(121)	(93)
Net long-term deferred tax liability	(3,302)	(7,157)
Net deferred tax liability	$ (3,302)	$ (7,157)

Income Taxes - Earliest tax yea

Income Taxes - Earliest tax years remaining for federal and major states of operations (Details)	12 Months Ended
	Dec. 31, 2017
Federal [Member]
Income Tax Examination [Line Items]
Earliest Open Tax Year	2,013
Texas [Member]
Income Tax Examination [Line Items]
Earliest Open Tax Year	2,013
Louisiana [Member]
Income Tax Examination [Line Items]
Earliest Open Tax Year	2,014
Michigan [Member]
Income Tax Examination [Line Items]
Earliest Open Tax Year	2,013

Supplemental Cash Flow Inform67

Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental Cash Flow Elements [Abstract]
Cash paid for interest	$ 22	$ 2	$ 13
Cash paid for federal and state taxes	459	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 leases	$ 1,808	$ 0	$ 0

Commitments and Contingencies -

Commitments and Contingencies - Schedule of principal contractual commitments outstanding under our capital leases (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
2,018	$ 398
2,019	398
2,020	398
2,021	398
2,022	255
Thereafter	0
Total minimum lease payments	1,847
Less: Amount representing interest	(158)
Present value of capital lease obligations	1,689
Less current portion of capital lease obligations	(338)	$ 0
Total long-term capital lease obligations	$ 1,351	$ 0

Commitments and Contingencies69

Commitments and Contingencies - Narrative (Details)	1 Months Ended	12 Months Ended
	May 31, 2017USD ($)	Dec. 31, 2017USD ($)lawsuit	Dec. 31, 2016USD ($)
Loss Contingencies [Line Items]
Automobile and workers’ compensation claims		$ 500,000
Number of claims alleging subsidence caused by oil and gas production | lawsuit		1
Accrued future legal costs		$ 0	$ 500,000
Release of accrual for future legal costs	$ 500,000
Parental guaranteed obligations		$ 48,200,000
Minimum [Member]
Loss Contingencies [Line Items]
Operating lease term		1 year
Aggregate medical claims for umbrella insurance coverage per calendar year		$ 4,500,000
Maximum [Member]
Loss Contingencies [Line Items]
Operating lease term		8 years

Commitments and Contingencies70

Commitments and Contingencies - Rental expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Rental expense	$ 12,073	$ 11,314	$ 11,168

Commitments and Contingencies71

Commitments and Contingencies - Long-term non-cancelable operating leases and terminal arrangements for the next five years (Details) $ in Thousands	Dec. 31, 2017USD ($)
Commitments and Contingencies Disclosure [Abstract]
2,018	$ 2,758
2,019	463
2,020	68
2,021	63
2,022	32
Thereafter	23
Total	$ 3,407

Commitments and Contingencies72

Commitments and Contingencies - Schedule of expenses and losses incurred but not reported (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Pre-funded premiums for losses incurred but not reported	$ 988	$ 2,657

Commitments and Contingencies73

Commitments and Contingencies - Schedule of accrued medical claims (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Accrued medical claims	$ 1,329	$ 1,411

Concentration of Credit Risk (D

Concentration of Credit Risk (Details) - customer	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Concentration Risk [Line Items]
Percentage of U.S. demand supplied by company	1.00%
Customer Concentration Risk [Member] | Minimum [Member]
Concentration Risk [Line Items]
Number of customers	3
Customer Concentration Risk [Member] | Maximum [Member]
Concentration Risk [Line Items]
Number of customers	5
Accounts Receivable [Member] | Customer Concentration Risk [Member] | Customer One [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	19.10%	20.90%	20.30%
Accounts Receivable [Member] | Customer Concentration Risk [Member] | Customer Two [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	15.00%	14.00%	16.50%
Accounts Receivable [Member] | Customer Concentration Risk [Member] | Customer Three [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	11.10%	10.10%	12.70%
Accounts Receivable [Member] | Customer Concentration Risk [Member] | Customer Four [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	10.40%
Sales Revenue, Goods, Net [Member] | Customer Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	50.00%
Sales Revenue, Goods, Net [Member] | Customer Concentration Risk [Member] | Customer One [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	22.80%	18.20%	24.40%
Sales Revenue, Goods, Net [Member] | Customer Concentration Risk [Member] | Customer Two [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	17.10%	16.50%	13.80%
Sales Revenue, Goods, Net [Member] | Customer Concentration Risk [Member] | Customer Three [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	10.80%	15.90%
Sales Revenue, Goods, Net [Member] | Customer Concentration Risk [Member] | Customer Four [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	10.70%	10.60%

Quarterly Financial Data (Una75

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Selected quarterly financial data and earnings per share [Abstract]
Revenues	$ 408,460	$ 295,311	$ 315,202	$ 303,087	$ 298,969	$ 256,877	$ 293,163	$ 250,531	$ 1,322,060	$ 1,099,540	$ 1,944,279
Operating (losses) earnings	3,757	(1,290)	619	(1,584)	(64)	(1,822)	5,601	2,339
Earnings (losses) from continuing operations	3,693	(3,033)	(282)	(860)	(168)	(983)	3,540	1,554	(482)	3,943	(1,275)
Net (losses) earnings	$ 3,693	$ (3,033)	$ (282)	$ (860)	$ (168)	$ (2,153)	$ 3,404	$ 1,430	$ (482)	$ 2,513	$ (1,275)
Earnings (losses) per share:
From continuing operations (in dollars per share)	$ 0.88	$ (0.72)	$ (0.07)	$ (0.20)	$ (0.04)	$ (0.23)	$ 0.84	$ 0.37	$ (0.11)	$ 0.94	$ (0.30)
From investment in unconsolidated affiliate (in dollars per share)	0	0	0	0	0	(0.28)	(0.03)	(0.03)	0	(0.34)	0
Basic and diluted net (losses) earnings per common share (in dollars per share)	$ 0.88	$ (0.72)	$ (0.07)	$ (0.20)	$ (0.04)	$ (0.51)	$ 0.81	$ 0.34	$ (0.11)	$ 0.60	$ (0.30)

Oil and Gas Producing Activit76

Oil and Gas Producing Activities (Unaudited) - Narrative (Details)	12 Months Ended
	Dec. 31, 2016well
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Producing wells with interest maintained	470
Producing wells operated	6
Period of average estimated price of proved reserves	12 months

Oil and Gas Producing Activit77

Oil and Gas Producing Activities (Unaudited) - Cost incurred in oil and gas exploration and development activities (Details) - USD ($) $ in Thousands	4 Months Ended	12 Months Ended
	Apr. 30, 2017	Dec. 31, 2016	Dec. 31, 2015
Property acquisition costs:
Unproved	$ 4	$ 32	$ 348
Proved	0	0	0
Exploration costs:
Expensed	5	291	1,667
Capitalized	0	0	0
Development costs	1,815	0	370
Total costs incurred	$ 1,824	$ 323	$ 2,385

Oil and Gas Producing Activit78

Oil and Gas Producing Activities (Unaudited) - Capitalized costs relating to oil and gas producing activities (Details) - USD ($) $ in Thousands	Apr. 30, 2017	Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Unproved crude oil and natural gas properties	$ 0	$ 0
Proved crude oil and natural gas properties	0	62,784
Subtotal	0	62,784
Accumulated depreciation, depletion and amortization	0	(56,426)
Net capitalized cost	$ 0	$ 6,358

Oil and Gas Producing Activit79

Oil and Gas Producing Activities (Unaudited) - Proved developed and undeveloped oil and gas reserves (Details) bbl in Thousands, MMcf in Thousands	4 Months Ended	12 Months Ended
	Apr. 30, 2017bblMMcf	Dec. 31, 2016bblMMcf	Dec. 31, 2015bblMMcf
Natural Gas [Member]
Total proved reserves:
Beginning of year | MMcf	4,214	4,835	5,611
Revisions of previous estimates | MMcf	0	65	27
Crude oil and natural gas reserves sold | MMcf	(4,067)	(175)	0
Extensions, discoveries and other reserve additions | MMcf	42	151	86
Production | MMcf	(189)	(662)	(889)
End of year | MMcf	0	4,214	4,835
Crude Oil [Member]
Total proved reserves:
Beginning of year | bbl	187	226	318
Revisions of previous estimates | bbl	0	24	(2)
Crude oil and natural gas reserves sold | bbl	(170)	(4)	(3)
Extensions, discoveries and other reserve additions | bbl	6	18	13
Production | bbl	(23)	(77)	(100)
End of year | bbl	0	187	226

Oil and Gas Producing Activit80

Oil and Gas Producing Activities (Unaudited) - Components of proved oil and gas reserves (Details) bbl in Thousands, MMcf in Thousands	Apr. 30, 2017bblMMcf	Dec. 31, 2016bblMMcf	Dec. 31, 2015bblMMcf	Dec. 31, 2014bblMMcf
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	0	4,214	4,813
Proved undeveloped reserves | MMcf	0	0	22
Total proved reserves | MMcf	0	4,214	4,835	5,611
Crude Oil [Member]
Reserve Quantities [Line Items]
Proved developed reserves | bbl	0	187	223
Proved undeveloped reserves | bbl	0	0	3
Total proved reserves | bbl	0	187	226	318

Oil and Gas Producing Activit81

Oil and Gas Producing Activities (Unaudited) - Standardized measure of discounted future net cash flows (Details) - USD ($) $ in Thousands	Apr. 30, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future gross revenues	$ 0	$ 17,938	$ 23,040
Future costs:
Lease operating expenses	0	(12,421)	(14,524)
Development costs	0	(38)	(103)
Future net cash flows before income taxes	0	5,479	8,413
Discount at 10% per annum	0	(2,002)	(2,987)
Discounted future net cash flows before income taxes	0	3,477	5,426
Future income taxes, net of discount at 10% per annum	0	(1,217)	(1,899)
Standardized measure of discounted future net cash flows	$ 0	$ 2,260	$ 3,527	$ 15,744

Oil and Gas Producing Activit82

Oil and Gas Producing Activities (Unaudited) - Assumed market prices of oil and natural gas reserves and future net revenues (Details)	4 Months Ended	12 Months Ended
	Apr. 30, 2017$ / MMcf$ / bbl	Dec. 31, 2016$ / MMcf$ / bbl	Dec. 31, 2015$ / MMcf$ / bbl
Crude Oil
Market Price [Abstract]
Average sales price | $ / bbl	0	38.34	45.83
Natural gas
Market Price [Abstract]
Average sales price | $ / MMcf	0	2.56	2.62

Oil and Gas Producing Activit83

Oil and Gas Producing Activities (Unaudited) - Effect of income taxes and discounting on the standardized measure of discounted future net cash flows (Details) - USD ($) $ in Thousands	Apr. 30, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future net cash flows before income taxes	$ 0	$ 5,479	$ 8,413
Future income taxes	0	(1,918)	(2,945)
Future net cash flows	0	3,561	5,468
Discount at 10% per annum	0	(1,301)	(1,941)
Standardized measure of discounted future net cash flows	$ 0	$ 2,260	$ 3,527	$ 15,744

Oil and Gas Producing Activit84

Oil and Gas Producing Activities (Unaudited) - Principal sources of changes in the standardized measure of discounted future net flows (Details) - USD ($) $ in Thousands	4 Months Ended	12 Months Ended
	Apr. 30, 2017	Dec. 31, 2016	Dec. 31, 2015
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
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	0	(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	0	181	38
Accretion of discount	130	194	1,116
Production rate changes and other	(493)	(945)	(3,603)
Net change in income taxes	1,217	682	6,578
End of year	$ 0	$ 2,260	$ 3,527

Oil and Gas Producing Activit85

Oil and Gas Producing Activities (Unaudited) - Results of operations for oil and gas producing activities (Details) - USD ($) $ in Thousands	4 Months Ended	12 Months Ended
	Apr. 30, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Revenues	$ 1,427	$ 3,410	$ 5,063
Costs and expenses:
Production	(951)	(3,337)	(7,022)
Producing property impairment	0	(30)	(10,324)
Exploration	0	0	(1,667)
Depreciation, depletion and amortization	(423)	(1,546)	(5,066)
Operating loss before income taxes	53	(1,503)	(19,016)
Income tax benefit (expense)	(19)	526	6,656
Operating earnings (losses)	$ 34	$ (977)	$ (12,360)