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

As an integral part of our crude oil marketing and transportation businesses, we operate approximately 492 tractors, and diesel fuel costs are a significant component of our operating expenses. These costs generally fluctuate with increasing and decreasing world crude oil prices. In our transportation segment, we typically incorporate a fuel surcharge provision in our customer contracts. During periods of high prices, we attempt to recoup rising diesel fuel costs through the pricing of our services; however to the extent these costs escalate, our operating earnings will generally be adversely affected.

The financial soundness of customers could affect our business and operating results.

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

Counterparty credit default could have an adverse effect on us.

Our revenues are generated under contracts with various counterparties, and our results of operations could be adversely affected by non-performance under the various contracts. A counterparty’s default or non-performance could be caused by factors beyond our control. A default could occur as a result of circumstances relating directly to the counterparty, or due to circumstances caused by other market participants having a direct or indirect relationship with the counterparty. We seek to mitigate the risk of default by evaluating the financial strength of potential counterparties; however, despite mitigation efforts, contractual defaults may occur from time to time.

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

As an integral part of our marketing and transportation businesses, we operate approximately 390 truck-tractors, and diesel fuel costs are a significant component of our operating expenses. These costs generally fluctuate with increasing and decreasing world crude oil prices. During periods of high prices, we attempt to recoup rising diesel fuel costs through the pricing of our services; however to the extent these costs escalate, our operating earnings will generally be adversely affected.

Revenues are generated under contracts that must be renegotiated periodically.

Substantially all of our revenues are generated under contracts which expire periodically or which must be frequently renegotiated, extended or replaced. Whether these contracts are renegotiated, extended or replaced is often subject to factors beyond our control. These factors include sudden fluctuations in crude oil and natural gas prices, counterparty ability to pay for or accept the contracted volumes and, most importantly, an extremely competitive marketplace for the services we offer. We cannot assure you that the costs and pricing of our services can remain competitive in the marketplace or that we will be successful in renegotiating our contracts.

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

Our crude oil marketing business purchases initial production of crude oil at the wellhead under contracts requiring us to accept the actual volume produced. The resale of this production is generally under contracts requiring a fixed volume to be delivered. We estimate our anticipated supply and match that supply estimate for both volume and pricing formulas with committed sales volumes. Since actual wellhead volumes produced will never equal anticipated supply, our marketing margins may be adversely impacted. In many instances, any losses resulting from the difference between actual supply volumes compared to committed sales volumes must be absorbed by us.

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

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

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Environmental laws and regulations govern many aspects of our business, such as ~~drilling and exploration, production,~~ transportation and waste management. Compliance with environmental laws and regulations can require significant costs or may require a decrease in ~~production.~~business activities. Moreover, noncompliance with these laws and regulations could subject us to significant administrative, civil, and/or criminal fines and/or penalties, as well as potential injunctive relief. See discussion under Item 1 and 2. Business and Properties —Regulatory Matters, and in the sections that follow, for additional detail.

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

Transportation of hazardous materials involves certain operating hazards such as automobile accidents, explosions, fires and pollution. Any of these operating hazards could cause serious injuries, fatalities or property damage, which could expose us to liability. The payment of any of these liabilities could reduce, or even eliminate, the funds available for other areas.

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

We could be adversely affected by changes in tax laws or regulations.

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

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

Our business is subject to changing government regulations.

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

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

We transport liquid combustible materials including petrochemicals, and these materials may be a target for terrorist attacks. While we employ a variety of security measures to mitigate risks, we cannot assure you that such events will not occur.

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

We are currently involved in certain administrative and civil legal proceedings as part of the ordinary course of our business. Moreover, as incidental to operations, we sometimes become involved in various lawsuits and/or disputes. Lawsuits and other legal proceedings can involve substantial costs, including the costs associated with investigation, litigation and possible settlement, judgment, penalty or fine. Although we maintain insurance to mitigate these costs, we cannot assure you that costs associated with lawsuits or other legal proceedings will not exceed the limits of insurance policies. Our results of operations could be adversely affected if a judgment, penalty or fine is not fully covered by insurance.

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

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

In May 2016, the EPA finalized rules to reduce methane emissions from new, modified or reconstructed sources in the crude oil and natural gas ~~sector, although~~sector. The EPA later proposed in June 2017 to stay the rules ~~are currently~~for two (2) years. Both the stay and the underlying rules have been the subject of ~~litigation and in June 2017,~~litigation. In September 2018, the EPA proposed ~~a 2-year stay of~~revisions to the 2016 rules. ~~The~~Regarding existing sources in the crude oil and natural gas section, the EPA announced in March 2016 that it ~~also intends~~intended to develop rules to reduce methane emissions for existing sources, ~~but~~although the EPA later announced in March 2017 that it no longer intends to pursue regulation of methane emissions from existing sources. In November 2016, the Bureau of Land Management (“BLM”) issued final rules to reduce methane emissions from venting, flaring and leaks during crude oil and natural gas operations on public lands, ~~although~~which the ~~present administration is proposing to delay the implementation dates applicable to requirements under these rules.~~BLM later revised in rules promulgated in September 2018. Several states are pursuing similar measures to regulate emissions of methane from new and existing sources within the crude oil and natural gas source category.

In addition, the U.S. Congress has considered legislation to reduce emissions of GHGs, and many states and regions have already taken legal measures to reduce or measure GHG emission levels, often involving the planned development of GHG emission inventories and/or regional cap and trade programs. Most of these cap and trade programs require major sources of emissions or major producers of fuels to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to reduce overall GHG emissions, and the cost of these allowances could escalate significantly over time. In the markets in which we currently operate, our operations are not affected by such GHG cap and trade programs. On an international level, almost 200 nations agreed in December 2015 to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and to be transparent about the measures each country will use to achieve its GHG emissions targets. Although the present administration ~~has~~ announced in June 2017 its intention to withdraw from the Paris accord, such withdrawal has not yet been finalized. Further, several states and local governments remain committed to ~~its~~the principles of the international climate agreement in their effectuation of policy and regulations. It is not possible at this time to predict how or when the U.S. might impose restrictions on GHGs as a result of the international climate change agreement. The adoption and implementation of any legislation or regulatory programs imposing GHG reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations including costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to GHG emissions and administer and manage a GHG emissions program. Such programs also could adversely affect demand for the crude oil and natural gas that we market and transport.

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We are subject to risks associated with climate change.

In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland and water availability and quality. If such effects were to occur, our operations have the potential to be adversely affected. Potential adverse effects could include disruption of our marketing and transportation activities, including, for example, damages to our facilities from powerful winds or floods, or increases in our costs of operation or reductions in the efficiency of our operations, as well as potentially increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process related services provided by companies or suppliers with whom we have a business relationship. In addition, the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, could have a material adverse effect on our business, financial condition, results of operations and cash flows. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.

Cyber-attacks or other disruptions to our information technology systems could lead to reduced revenue, increased costs, liability claims, fines or harm to our competitive position.

We are subject to cybersecurity risks and may incur increasing costs in connection with our efforts to enhance and ensure security and in response to actual or attempted cybersecurity attacks. Substantial aspects of our business depend on the secure operation of our computer systems and websites. Security breaches could expose us to a risk of loss, misuse or interruption of sensitive and critical information and functions, including our own proprietary information and that of our customers, suppliers and employees. Such breaches could result in operational impacts, reputational harm, competitive disadvantage, litigation, regulatory enforcement actions and liability. While we devote substantial resources to maintaining adequate levels of cybersecurity, we cannot assure you that we will be able to prevent all of the rapidly evolving types of cyberattacks. Actual or anticipated attacks and risks may cause us to incur increasing costs for technology, personnel and services to enhance security or to respond to occurrences.

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

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

Item 1B. Unresolved Staff Comments.

None.

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Item 3. Legal Proceedings.

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, workers’ compensation claims and other items of general liability as would be typical for the industry. We are currently 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.

See Note 1315 in the Notes to Consolidated Financial Statements for further discussion.

Item 4. Mine Safety Disclosures.

Not applicable.

PART II


~~Item 5.~~	~~Market for Registrant’s Common Stock, Related Stockholder Matters, and Issuer Purchases of Equity Securities.~~

Item 5. Market for Registrant’s Common Stock, Related Stockholder Matters, and Issuer Purchases of Equity Securities.

Our common stock is traded on the NYSE ~~MKT~~American under the ticker symbol “AE”. As of ~~February 28, 2018,~~March 1, 2019, there were approximately ~~140~~132 shareholders of record of our common shares. ~~The following table presents high and low sales prices for our common stock for the periods presented as reported by the NYSE MKT and the amount, record date and payment date~~

Unregistered Sales of ~~the quarterly cash dividends we paid on each of our common shares with respect to such periods.~~Securities.

Cash Dividend History
Price Ranges Per Record Payment
High Low Share Date Date
2015
1st Quarter $73.28 $47.31 $0.22 6/3/2015 6/17/2015
2nd Quarter $70.00 $39.00 $0.22 9/3/2015 9/17/2015
3rd Quarter $48.60 $38.88 $0.22 12/2/2015 12/16/2015
4th Quarter $46.86 $33.55 $0.22 3/11/2016 3/23/2016

2016
1st Quarter $43.00 $30.00 $0.22 6/3/2016 6/17/2016
2nd Quarter $44.27 $35.25 $0.22 9/6/2016 9/19/2016
3rd Quarter $39.47 $29.64 $0.22 12/5/2016 12/19/2016
4th Quarter $44.00 $35.17 $0.22 3/10/2017 3/24/2017

2017
1st Quarter $41.99 $34.23 $0.22 6/2/2017 6/16/2017
2nd Quarter $43.80 $35.64 $0.22 9/6/2017 9/20/2017
3rd Quarter $42.77 $32.80 $0.22 12/5/2017 12/19/2017
4th Quarter $50.59 $40.36 $0.22 3/9/2018 3/23/2018
None.

Issuer Purchases of Equity Securities

None.

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Performance Graph

The following graph compares the total shareholder return performance of our common stock with the performance of: (i) the Standard & Poor’s 500 Stock Index (“S&P 500”) and (ii) the S&P 500 Integrated Oil and Gas Index. The graph assumes that $100 was invested in our common stock and each comparison index beginning on December 31, ~~2012~~2013 and that all dividends were reinvested on a quarterly basis on the ex-dividend dates. The graph was prepared under the applicable rules of the SEC based on data supplied by Research Data Group. The stock performance shown on the graph is not necessarily indicative of future price performance.


	December 31,
	2013		2014		2015		2016		2017		2018

Adams Resources & Energy, Inc.	$	100.00	$	74.02	$	57.97	$	61.28	$	68.75	$	62.45
S&P 500	100.00		113.69		115.26		129.05		157.22		150.33
S&P Integrated Oil & Gas	100.00		93.27		80.34		99.74		101.81		88.61

December 31,
2012 2013 2014 2015 2016 2017

Adams Resources & Energy, Inc. $ 100.00
$ 197.45
$ 146.15
$ 114.46
$ 120.99
$ 135.74
S&P 500 100.00
132.39
150.51
152.59
170.84
208.14
S&P Integrated Oil & Gas 100.00
121.53
113.35
97.64
121.21
123.73

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Item 6. Selected Financial Data.

The following table presents our selected historical consolidated financial data. This information has been derived from and should be read in conjunction with our audited financial statements included under Part II, Item 8 of this annual report, which presents our audited balance sheets as of December 31, ~~2017~~2018 and ~~2016~~2017 and related consolidated statements of operations, cash flows and shareholders’ equity for the three years ended December 31, 2018, 2017 ~~2016~~ and ~~2015,~~2016, respectively. As presented in the table, amounts are in thousands (except per share data).


	Year Ended December 31,
	2018		2017		2016		2015		2014
Statements of operations data:
Revenues:
Marketing	$	1,694,437	$	1,267,275	$	1,043,775	$	1,875,885	$	4,050,497
Transportation	55,776		53,358		52,355		63,331		68,968
Oil and natural gas ⁽¹⁾	—		1,427		3,410		5,063		13,361
Total revenues	1,750,213		1,322,060		1,099,540		1,944,279		4,132,826

Costs and expenses:
Marketing	1,681,045		1,247,763		1,016,733		1,841,893		4,020,017
Transportation	48,169		48,538		45,154		52,076		56,802
Oil and natural gas ⁽¹⁾	—		948		2,084		6,931		7,817
Oil and natural gas property impairments ⁽²⁾	—		3		313		12,082		8,009
Oil and natural gas property sale ⁽³⁾	—		—		—		—		(2,528)
General and administrative	8,937		9,707		10,410		9,939		8,613
Depreciation, depletion and amortization	10,654		13,599		18,792		23,717		24,615

Operating earnings (losses)	1,408		1,502		6,054		(2,359)		9,481

Loss on deconsolidation of subsidiary ⁽¹⁾	—		(3,505)		—		—		—
Impairment of investment in unconsolidated
affiliate ⁽⁴⁾	—		(2,500)		—		—		—
Interest income	2,046		1,076		580		314		299

Earnings (losses) from continuing operations	3,454		(3,427)		6,634		(2,045)		9,780

Income tax (provision) benefit	(509)		2,945		(2,691)		770		(3,561)

Earnings (losses) before investment in
unconsolidated affiliate
and discontinued operations	2,945		(482)		3,943		(1,275)		6,219

Discontinued operations, net of taxes	—		—		—		—		304
Losses from investment in unconsolidated
affiliate, net of tax ⁽⁵⁾	—		—		(1,430)		—		—
Net (losses) earnings	$	2,945	$	(482)	$	2,513	$	(1,275)	$	6,523

Earnings (losses) per share:
From continuing operations	$	0.70	$	(0.11)	$	0.94	$	(0.30)	$	1.48
From investment in unconsolidated
affiliate	—		—		(0.34)		—		—
From discontinued operations	—		—		—		—		0.07
Basic and diluted earnings (losses) per share	$	0.70	$	(0.11)	$	0.60	$	(0.30)	$	1.55

Dividends per common share	$	0.88	$	0.88	$	0.88	$	0.88	$	0.88

Year Ended December 31,
2017 2016 2015 2014 2013
Statements of operations data:
Revenues:
Marketing $ 1,267,275
$ 1,043,775
$ 1,875,885
$ 4,050,497
$ 3,863,057
Transportation 53,358
52,355
63,331
68,968
68,783
Oil and natural gas 1,427
3,410
5,063
13,361
14,129
Total revenues 1,322,060
1,099,540
1,944,279
4,132,826
3,945,969

Costs and expenses:
Marketing 1,247,763
1,016,733
1,841,893
4,020,017
3,815,006
Transportation 48,538
45,154
52,076
56,802
56,504
Oil and natural gas 948
2,084
6,931
7,817
6,117
Oil and natural gas property impairments ⁽¹⁾
3
313
12,082
8,009
2,631
Oil and natural gas property sale ⁽²⁾
—
—
—
(2,528 ) —
General and administrative 9,707
10,410
9,939
8,613
9,060
Depreciation, depletion and amortization 13,599
18,792
23,717
24,615
22,275

Operating earnings (losses) 1,502
6,054
(2,359 ) 9,481
34,376

Loss on deconsolidation of subsidiary ⁽³⁾
(3,505 ) —
—
—
—
Impairment of investment in unconsolidated
affiliate ⁽⁴⁾
(2,500 ) —
—
—
—
Interest income (expense) 1,076
580
314
299
174

Earnings (losses) from continuing operations (3,427 ) 6,634
(2,045 ) 9,780
34,550

Income tax (provision) benefit 2,945
(2,691 ) 770
(3,561 ) (12,429 )

Earnings (losses) before investment in
unconsolidated affiliate
and discontinued operations (482 ) 3,943
(1,275 ) 6,219
22,121

Discontinued operations, net of taxes —
—
—
304
(511 )
Losses from investment in unconsolidated
affiliate, net of tax ⁽⁵⁾
—
(1,430 ) —
—
—
Net (losses) earnings $ (482 ) $ 2,513
$ (1,275 ) $ 6,523
$ 21,610

Earnings (losses) per share:
From continuing operations $ (0.11 ) $ 0.94
$ (0.30 ) $ 1.48
$ 5.24
From investment in unconsolidated
affiliate —
(0.34 ) —
—
—
From discontinued operations —
—
—
0.07
(0.12 )
Basic and diluted earnings per share $ (0.11 ) $ 0.60
$ (0.30 ) $ 1.55
$ 5.12

Dividends per common share $ 0.88
$ 0.88
$ 0.88
$ 0.88
$ 0.66

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	December 31,											December 31,
	2017		2016		2015		2014		2013			2018		2017		2016		2015		2014
Balance sheet data:											Balance sheet data:
Cash	$	109,393	$	87,342	$	91,877	$	80,184	$	60,733	Cash	$	117,066	$	109,393	$	87,342	$	91,877	$	80,184
Total assets	282,704		246,872		243,215		340,814		448,082		Total assets	278,870		282,704		246,872		243,215		340,814
Long-term debt	—		—		—		—		—		Long-term debt	—		—		—		—		—
Shareholders’ equity	147,119		151,312		152,510		157,497		154,685		Shareholders’ equity	146,598		147,119		151,312		152,510		157,497
Dividends on common shares	3,711		3,711		3,712		3,711		2,783		Dividends on common shares	3,711		3,711		3,711		3,712		3,711

________________________


~~(1)~~	~~During 2015, we recognized an impairment of $10.3 million on producing properties, and an impairment of $1.8 million on non-producing properties.~~


~~(2)~~	~~During 2014, we sold certain crude oil and natural gas producing properties for $4.1 million, producing a net gain of $2.5 million.~~


~~(3)~~	~~During 2017, we recognized an impairment related to the bankruptcy, deconsolidation and sale of our upstream crude oil and natural gas exploration and production subsidiary.~~


~~(4)~~	~~During 2017, we recognized an impairment on our medical investment in VestaCare.~~


~~(5)~~	During 2016, we recognized losses and an impairment on our medical investment in Bencap LLC (“Bencap”). We have no other medical-related investments, and we currently do not have any plans to pursue additional medical-related investments.

(1) During 2017, we deconsolidated our upstream crude oil and natural gas exploration and production subsidiary upon its bankruptcy filing. We recognized an impairment related to the bankruptcy, deconsolidation and sale of this subsidiary during 2017.

(2) During 2015, we recognized an impairment of $10.3 million on producing properties, and an impairment of $1.8 million on non-producing properties.

(3) During 2014, we sold certain crude oil and natural gas producing properties for $4.1 million, producing a net gain of $2.5 million.

(4) During 2017, we recognized an impairment on our medical investment in VestaCare.

(5) During 2016, we recognized losses and an impairment on our medical investment in Bencap LLC (“Bencap”). Other than our remaining ownership interest in VestaCare, we have no other medical-related investments, and we currently do not have any plans to pursue additional medical-related investments.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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

Overview of Business

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

~~Historically, we have operated~~We operate and ~~reported~~report in ~~three~~two business segments: (i) crude oil marketing, transportation and storage, and (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.~~bulk. We exited the upstream crude oil and natural gas exploration and production business during 2017 with the sale of our upstream crude oil and natural gas exploration and production assets.

~~2017 Developments~~

~~Subsidiary Bankruptcy, Deconsolidation and Sale~~

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

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

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

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

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~~Voluntary Early Retirement Program~~

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

~~Impairment of Investment in Unconsolidated Affiliate~~

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

Results of Operations

Crude Oil Marketing

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


	Year Ended December 31,											Year Ended December 31,
	2017		2016		Change ⁽¹⁾		2015		Change ⁽¹⁾			2018		2017		Change ⁽¹⁾	2016		Change ⁽¹⁾

Revenues	$	1,267,275	$	1,043,775	21.4	%	$	1,875,885	(44.4	%)	Revenues	$	1,694,437	$	1,267,275	33.7%	$	1,043,775	21.4%
Operating earnings	11,700		17,045		(31.4	%)	22,895		(25.6	%)	Operating earnings	7,008		11,700		(40.1%)	17,045		(31.4%)
Depreciation and amortization	7,812		9,997		(21.9	%)	11,097		(9.9	%)	Depreciation and amortization	6,384		7,812		(18.3%)	9,997		(21.9%)
Driver commissions	13,058		14,933		(12.6	%)	22,262		(32.9	%)	Driver commissions	14,567		13,058		11.6%	14,933		(12.6%)
Insurance	4,509		7,442		(39.4	%)	8,732		(14.8	%)	Insurance	6,248		4,509		38.6%	7,442		(39.4%)
Fuel	5,278		5,397		(2.2	%)	9,928		(45.6	%)	Fuel	7,435		5,278		40.9%	5,397		(2.2%)

____________________


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

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

Volume and price information were as follows for the periods indicated:


								Year Ended December 31,
	Year Ended December 31,							2018		2017		2016
	2017		2016		2015
Field level purchase volumes – per day ⁽¹⁾
Field level purchase volumes – per day ⁽¹⁾⁽²⁾							Field level purchase volumes – per day ⁽¹⁾⁽²⁾
Crude oil – barrels	67,447		72,900		106,400		Crude oil – barrels	79,361		67,447		72,900

Average purchase price							Average purchase price
Crude oil – per barrel	$	49.88	$	39.30	$	45.41	Crude oil – per barrel	$	64.53	$	49.88	$	39.30

____________________


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

(2) Effective October 1, 2018, in connection with the Red River acquisition, we entered into a new revenue contract to purchase crude oil. The 2018 amount includes the additional volumes purchased during the fourth quarter of 2018.

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2018 compared to 2017. Crude oil marketing revenues increased by $427.2 million during the year ended December 31, 2018 as compared to 2017 primarily as a result of an increase in the market price of crude oil, which increased revenues by approximately $172.8 million, and higher crude oil volumes, which increased revenues by approximately $254.4 million. The average crude oil price received was $49.88 for 2017, which increased to $64.53 for 2018. On October 1, 2018, we acquired trucking assets in the Red River area of North Texas and South Central Oklahoma, and subsequently entered into a new revenue agreement, which has increased our crude oil volumes during the fourth quarter of 2018.

Our crude oil marketing operating earnings for the year ended December 31, 2018 decreased by $4.7 million as compared to 2017, primarily as a result of inventory valuation losses of $5.4 million (as shown in the following table), partially offset by increases in crude oil volumes and the average market price of crude oil. During 2018, volumes increased as activity in certain marketing areas increased primarily as a result of increased wellhead purchases.

Driver commissions increased by $1.5 million during the year ended December 31, 2018 as compared to 2017, primarily as a result of the increase in crude oil marketing volumes in 2018. Insurance costs increased by $1.7 million during the year ended December 31, 2018 as compared to 2017, primarily as a result of higher insurance costs during 2018, including higher insurance as a result of the Red River acquisition in 2018. Fuel costs increased by $2.2 million during the year ended December 31, 2018 as compared to 2017 consistent with increased marketing volumes and higher crude oil prices during 2018, and an increase in the price of diesel fuel during 2018 as compared to 2017.

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

~~Table of Contents~~

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

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

~~2016 compared to 2015~~. Crude oil marketing revenues decreased by $832.1 million during the year ended December 31, 2016 as compared to 2015, primarily as a result of lower crude oil volumes, which decreased revenues by approximately $475.5 million and a decrease in the market price of crude oil, which decreased revenues by approximately $356.6 million. The average crude oil price received was $45.41 for 2015, which decreased to $39.30 for 2016. Lower crude oil prices resulted in curtailed drilling efforts in most areas. Crude marketing volumes decreased as a result of lower wellhead purchases in 2016 as compared to 2015.

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

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

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

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Crude oil marketing operating earnings can be affected by the valuations of our forward month commodity contracts (derivative instruments). These non-cash valuations are calculated and recorded at each period end based on the underlying data existing as of such date. We generally enter into these derivative contracts as part of a pricing strategy based on crude oil purchases at the wellhead (field level). The valuation of derivative instruments at period end requires the recognition of non-cash “mark-to-market” gains and losses.

~~Table of Contents~~

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


	Year Ended December 31,									Year Ended December 31,
	2017			2016			2015			2018		2017		2016

As reported segment operating earnings ⁽¹⁾	$	11,700		$	17,045		$	22,895	As reported segment operating earnings ⁽¹⁾	$	7,008	$	11,700	$	17,045
Add (subtract):									Add (subtract):
Inventory liquidation gains	(3,372		)	(8,243		)	—		Inventory liquidation gains	—		(3,372)		(8,243)
Inventory valuation losses	—			—			5,357		Inventory valuation losses	5,363		—		—
Derivative valuation (gains) losses	27			(243		)	188		Derivative valuation (gains) losses	(2)		27		(243)
Field level operating earnings ⁽²⁾	$	8,355		$	8,559		$	28,440	Field level operating earnings ⁽²⁾	$	12,369	$	8,355	$	8,559

____________________


~~(1)~~	Segment operating earnings included inventory liquidation gains of $3.3 million and $8.2 million for the years ended December 31, 2017 and 2016, respectively, and inventory valuation losses of $5.4 million for the year ended December 31, 2015.


~~(2)~~	The use of field level operating earnings is (a) unique to us, (b) not a substitute for a GAAP measure and (c) may not be comparable to any similar measures developed by industry participants. We utilize this data to evaluate the profitability of our operations.

(1) Segment operating earnings included inventory valuation losses of $5.4 million for the year ended December 31, 2018, and inventory liquidation gains of $3.3 million and $8.2 million for the years ended December 31, 2017 and 2016, respectively.

(2) The use of field level operating earnings is unique to us, not a substitute for a GAAP measure and may not be comparable to any similar measures developed by industry participants. We utilize this data to evaluate the profitability of our operations.

Field level operating earnings and field level purchase volumes depict our day-to-day operation of acquiring crude oil at the wellhead, transporting the product and delivering the product to market sales points. Field level operating earnings increased during the year ended December 31, 2018 as compared to 2017, primarily due to higher revenues resulting from an increase in the market price of crude oil, higher crude oil volumes and improved market conditions.

Field level operating earnings decreased during the year ended December 31, 2017 as compared to 2016, primarily due to increased personnel costs related to the voluntary early retirement program, partially offset by increased volumes and the effects of a ~~newly~~ negotiated barge contract, which reduced operating expenses, beginning in the third quarter of 2017.

Field level operating earnings decreased during the year ended December 31, 2016 as compared to 2015 as competition and additional industry infrastructure development progressed in the region. A key factor in unit margins is the value difference between crude oil supplies in the mid-continent region of the U.S. versus crude oil supply costs in the eastern region of the U.S. We have been able to capture some of this value difference by shipping crude oil from the Texas Gulf Coast to other locations.

We held crude oil inventory at a weighted average composite price as follows at the dates indicated (in ~~barrels)~~barrels and price per barrel):


	December 31,
	2018				2017					2016
		Average			Average			Average
	Barrels	Price		Barrels	Price		Barrels	Price

Crude oil inventory	415,523	$	54.82	198,011	$	61.57	255,146	$	51.22

December 31,
2017 2016 2015
Average Average Average
Barrels Price Barrels Price Barrels Price

Crude oil inventory 198,011
$ 61.57
255,146
$ 51.22
261,718
$ 29.31

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

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Transportation

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


	Year Ended December 31,													Year Ended December 31,
	2017			2016			Change ⁽¹⁾		2015		Change ⁽¹⁾			2018		2017		Change ⁽¹⁾	2016		Change ⁽¹⁾

Revenues	$	53,358		$	52,355		1.9	%	$	63,331	(17.3	%)	Revenues	$	55,776	$	53,358	4.5%	$	52,355	1.9%
Operating earnings (losses)	$	(544	)	$	(48	)	1033.3	%	$	3,701	(101.3	%)	Operating earnings (losses)	$	3,337	$	(544)	(713.4%)	$	(48)	1,033.3%
Depreciation and amortization	$	5,364		$	7,249		(26.0	%)	$	7,554	(4.0	%)	Depreciation and amortization	$	4,270	$	5,364	(20.4%)	$	7,249	(26.0%)
Driver commissions	$	11,546		$	11,227		2.8	%	$	13,265	(15.4	%)	Driver commissions	$	11,680	$	11,546	1.2%	$	11,227	2.8%
Insurance	$	5,452		$	4,952		10.1	%	$	4,543	9.0	%	Insurance	$	4,716	$	5,452	(13.5%)	$	4,952	10.1%
Fuel	$	6,401		$	5,688		12.5	%	$	8,134	(30.1	%)	Fuel	$	6,988	$	6,401	9.2%	$	5,688	12.5%
Maintenance expense	$	6,061		$	5,410		12.0	%	$	6,365	(15.0	%)	Maintenance expense	$	5,347	$	6,061	(11.8%)	$	5,410	12.0%
Mileage (000s)	21,836			22,611			(3.4	%)	25,205		(10.3	%)	Mileage (000s)	19,177		21,836		(12.2%)	22,611		(3.4%)

____________________


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

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

Our revenue rate structure includes a component for fuel costs in which fuel cost fluctuations are largely passed through to the customer over time. Revenues, net of fuel cost, were as follows for the periods indicated (in thousands):


	Year Ended December 31,										Year Ended December 31,
	2017			2016			2015				2018		2017		2016

Total transportation revenue	$	53,358		$	52,355		$	63,331		Total transportation revenue	$	55,776	$	53,358	$	52,355
Diesel fuel cost	(6,401		)	(5,688		)	(8,134		)	Diesel fuel cost	(6,988)		(6,401)		(5,688)
Revenues, net of fuel cost ⁽¹⁾	$	46,957		$	46,667		$	55,197		Revenues, net of fuel cost ⁽¹⁾	$	48,788	$	46,957	$	46,667

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Item 7A. Quantitative and Qualitative Disclosures about Market Risk

In the normal course of business, we are exposed to certain risks, including changes in interest rates and commodity prices.

Commodity Price Risk

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

Certain forward contracts are recorded at fair value, depending on our assessments of numerous accounting standards and positions that comply with GAAP in the U.S. The fair value of these contracts is reflected in the balance sheet as fair value assets and liabilities and any revaluation is recognized on a net basis in our results of operations (see ~~Note~~Notes 2 and 11 to the Consolidated Financial Statements for further information).

Historically, prices received for crude oil ~~and natural gas~~ sales have been volatile and unpredictable with price volatility expected to continue. From January 1, ~~2016~~2017 through December 31, ~~2017,~~2018, our crude oil monthly average wholesale purchase costs ranged from an average low of ~~$26.26~~$43.42 per barrel to a monthly average high of ~~$60.16~~$74.74 per barrel during the same period. A hypothetical ten percent additional adverse change in average ~~hydrocarbon~~crude oil prices, assuming no changes in volume levels, would have reduced earnings by approximately ~~$1.2~~$2.3 million and ~~$1.6~~$1.2 million for the years ended December 31, ~~2017~~2018 and ~~2016,~~2017, respectively.

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Item 8. Financial Statements and Supplementary Data.

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


		Page No.
		~~Page No.~~
Reports of Independent Registered Public Accounting Firms	3534

Consolidated Balance Sheets as of December 31, ~~2017~~2018 and ~~2016~~2017		3736

Consolidated Statements of Operations for the Years Ended December 31, 2018, 2017 ~~2016~~ and ~~2015~~2016		3837

Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 ~~2016~~ and ~~2015~~2016		3938

Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2018, 2017 ~~2016~~ and ~~2015~~2016		4039

Notes to Consolidated Financial Statements
Note 1 – Organization and Basis of Presentation		4140
Note 2 – Summary of Significant Accounting Policies		4241
Note 3 – Revenue Recognition		46
Note 4 – Subsidiary Bankruptcy, Deconsolidation and Sale		4749
Note 45 – Prepayments and Other Current Assets		4850
Note 56 – Property and Equipment		4950
Note 67 – Cash Deposits and Other Assets		5052
Note 78 – Investments in Unconsolidated Affiliates		51
~~Note 8 – Segment Reporting~~	53
Note 9 – Segment Reporting		54
Note 10 – Transactions with Affiliates		5456
Note 1011 – Derivative Instruments and Fair Value Measurements		5556
Note 1112 – Income Taxes		5960
Note 1213 – Share-Based Compensation Plan		62
Note 14 – Supplemental Cash Flow Information		6164
Note 1315 – Commitments and Contingencies		6164
Note 1416 – Concentration of Credit Risk		6366
Note 1517 – Quarterly Financial Information (Unaudited)		6567
Note 1618 – Oil and Gas Producing Activities (Unaudited)		6667

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Report of Independent Registered Public Accounting Firm

~~REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM~~

To the Shareholders and Board of Directors

Adams Resources & Energy, Inc.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance ~~sheet~~sheets of Adams Resources & Energy, Inc. and subsidiaries (the ~~“Company”)~~Company) as of December 31, 2018 and 2017, the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the ~~year~~years in the two-year period ended December 31, ~~2017,~~2018, and the related notes (collectively, the ~~“consolidated~~consolidated financial ~~statements”)~~statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the ~~year~~years in the two-year period ended December 31, ~~2017,~~2018, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, ~~2017,~~2018, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March ~~12, 2018~~8, 2019 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG LLP

We have served as the Company’s auditor since 2017.

Houston, Texas

March ~~12, 2018~~8, 2019

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Adams Resources & Energy, Inc.

Houston, Texas

We have audited the accompanying consolidated ~~balance sheet~~statements of operations, shareholders’ equity, and cash flows of Adams Resources & Energy, Inc. and subsidiaries (the “Company”) ~~as of December 31, 2016, and~~for the ~~related consolidated statements of operations, shareholders’ equity, and cash flows for each of the two years in the period~~year ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our ~~audits.~~audit.

We conducted our ~~audits~~audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our ~~audits provide~~audit provides a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the ~~financial position~~results of Adams Resources & Energy, Inc. and subsidiaries ~~as of December 31, 2016, and the results of their~~ operations and their cash flows for ~~each of~~ the ~~two years in the period~~year ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 31, 2017

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands)


	December 31,
	2018		2017
ASSETS
Current assets:
Cash and cash equivalents	$	117,066	$	109,393
Accounts receivable, net of allowance for doubtful accounts of $153 and $303, respectively	85,197		121,353
Accounts receivable – related party	425		—
Inventory	22,779		12,192
Derivative assets	162		166
Income tax receivable	2,404		1,317
Prepayments and other current assets	1,557		1,264
Total current assets	229,590		245,685
Property and equipment, net	44,623		29,362
Investment in unconsolidated affiliate	—		425
Cash deposits and other assets	4,657		7,232
Total assets	$	278,870	$	282,704

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	116,068	$	124,706
Accounts payable – related party	29		5
Derivative liabilities	139		145
Current portion of capital lease obligations	883		338
Other current liabilities	6,148		4,404
Total current liabilities	123,267		129,598
Other long-term liabilities:
Asset retirement obligations	1,525		1,273
Capital lease obligations	3,209		1,351
Deferred taxes and other liabilities	4,271		3,363
Total liabilities	132,272		135,585

Commitments and contingencies (Note 15)

Shareholders’ equity:
Preferred stock – $1.00 par value, 960,000 shares authorized, none outstanding	—		—
Common stock – $0.10 par value, 7,500,000 shares authorized, 4,217,596 shares outstanding	422		422
Contributed capital	11,948		11,693
Retained earnings	134,228		135,004
Total shareholders’ equity	146,598		147,119
Total liabilities and shareholders’ equity	$	278,870	$	282,704

December 31,
2017 2016
ASSETS
Current assets:
Cash and cash equivalents $ 109,393
$ 87,342
Accounts receivable, net of allowance for doubtful
accounts of $303 and $225, respectively
121,353
87,162
Inventory 12,192
13,070
Derivative assets 166
112
Income tax receivable 1,317
2,735
Prepayments and other current assets 1,264
2,097
Total current assets 245,685
192,518
Property and equipment, net 29,362
46,325
Investments in unconsolidated affiliates 425
2,500
Cash deposits and other assets 7,232
5,529
Total assets $ 282,704
$ 246,872

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable $ 124,706
$ 79,897
Accounts payable – related party 5
53
Derivative liabilities 145
64
Current portion of capital lease obligations 338
—
Other current liabilities 4,404
6,060
Total current liabilities 129,598
86,074
Other long-term liabilities:
Asset retirement obligations 1,273
2,329
Capital lease obligations 1,351
—
Deferred taxes and other liabilities 3,363
7,157
Total liabilities 135,585
95,560

Commitments and contingencies (Note 13)

Shareholders’ equity:
Preferred stock – $1.00 par value, 960,000 shares
authorized, none outstanding
—
—
Common stock – $0.10 par value, 7,500,000 shares
authorized, 4,217,596 shares outstanding
422
422
Contributed capital 11,693
11,693
Retained earnings 135,004
139,197
Total shareholders’ equity 147,119
151,312
Total liabilities and shareholders’ equity $ 282,704

$ 246,872

See Notes to Consolidated Financial Statements.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)


	Year Ended Year Ended December 31,
	2018		2017		2016
Revenues:
Marketing	$	1,694,437	$	1,267,275	$	1,043,775
Transportation	55,776		53,358		52,355
Oil and natural gas	—		1,427		3,410
Total revenues	1,750,213		1,322,060		1,099,540

Costs and expenses:
Marketing	1,681,045		1,247,763		1,016,733
Transportation	48,169		48,538		45,154
Oil and natural gas	—		948		2,084
Oil and natural gas property impairments	—		3		313

General and administrative	8,937		9,707		10,410
Depreciation, depletion and amortization	10,654		13,599		18,792
Total costs and expenses	1,748,805		1,320,558		1,093,486

Operating earnings (losses)	1,408		1,502		6,054

Other income (expense):
Loss on deconsolidation of subsidiary (Note 4)	—		(3,505)		—
Impairment of investment in unconsolidated affiliate	—		(2,500)		—

Interest income	2,155		1,103		582
Interest expense	(109)		(27)		(2)
Total other income (expense), net	2,046		(4,929)		580

(Losses) earnings before income taxes and investment
in unconsolidated affiliate	3,454		(3,427)		6,634

Income tax (provision) benefit:
Current	427		(895)		(2,778)
Deferred	(936)		3,840		87
Income tax benefit (provision)	(509)		2,945		(2,691)

Earnings (losses) from continuing operations	2,945		(482)		3,943
Losses from investment in unconsolidated affiliate, net of
tax benefit of $—, $—, and $770, respectively	—		—		(1,430)
Net (losses) earnings	$	2,945	$	(482)	$	2,513

Basic earnings (losses) per common share:
From continuing operations	$	0.70	$	(0.11)	$	0.94
From investment in unconsolidated affiliate	—		—		$	(0.34)
Basic net (losses) earnings per common share	$	0.70	$	(0.11)	$	0.60

Diluted net (losses) earnings per common share	$	0.70	$	(0.11)	$	0.60

Dividends per common share	$	0.88	$	0.88	$	0.88

Year Ended December 31,
2017 2016 2015
Revenues:
Marketing $ 1,267,275
$ 1,043,775
$ 1,875,885
Transportation 53,358
52,355
63,331
Oil and natural gas 1,427
3,410
5,063
Total revenues 1,322,060
1,099,540
1,944,279

Costs and expenses:
Marketing 1,247,763
1,016,733
1,841,893
Transportation 48,538
45,154
52,076
Oil and natural gas 948
2,084
6,931
Oil and natural gas property impairments 3
313
12,082
General and administrative 9,707
10,410
9,939
Depreciation, depletion and amortization 13,599
18,792
23,717
Total costs and expenses 1,320,558
1,093,486
1,946,638

Operating earnings (losses) 1,502
6,054
(2,359 )

Other income (expense):
Loss on deconsolidation of subsidiary (Note 3) (3,505 ) —
—
Impairment of investment in unconsolidated affiliate (2,500 ) —
—
Interest income 1,103
582
327
Interest expense (27 ) (2 ) (13 )
Total other income (expense), net (4,929 ) 580
314

(Losses) earnings before income taxes and investment
in unconsolidated affiliate (3,427 ) 6,634
(2,045 )

Income tax (provision) benefit:
Current (895 ) (2,778 ) (4,073 )
Deferred 3,840
87
4,843
Income tax benefit (provision) 2,945
(2,691 ) 770

Earnings (losses) from continuing operations (482 ) 3,943
(1,275 )
Losses from investment in unconsolidated affiliate, net of
tax benefit of $—, $770 and $—, respectively —
(1,430 ) —
Net (losses) earnings $ (482 ) $ 2,513
$ (1,275 )

Earnings (losses) per share:
From continuing operations $ (0.11 ) $ 0.94
$ (0.30 )
From investment in unconsolidated affiliate —
(0.34 ) —
Basic and diluted net (losses) earnings per common share $ (0.11 ) $ 0.60
$ (0.30 )

Weighted average number of common shares outstanding 4,218
4,218
4,218

Dividends per common share $ 0.88
$ 0.88
$ 0.88

See Notes to Consolidated Financial Statements.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Year Ended December 31,										Year Ended Year Ended December 31,
	2017			2016			2015				2018		2017		2016
Operating activities:										Operating activities:
Net (losses) earnings	$	(482	)	$	2,513		$	(1,275	)	Net (losses) earnings	$	2,945	$	(482)	$	2,513
Adjustments to reconcile net (losses) earnings to net cash										Adjustments to reconcile net (losses) earnings to net cash
provided by operating activities:										provided by operating activities:
Depreciation, depletion and amortization	13,599			18,792			23,717			Depreciation, depletion and amortization	10,654		13,599		18,792
Gains on sale of property	(594		)	(1,966		)	(535		)
Dry hole costs incurred	—			—			817
Gains on sales of property										Gains on sales of property	(1,240)		(594)		(1,966)
Impairment of oil and natural gas properties	3			313			12,082			Impairment of oil and natural gas properties	—		3		313
Provision for doubtful accounts	78			19			27			Provision for doubtful accounts	(150)		78		19
Share-based compensation expense										Share-based compensation expense	255		—		—
Deferred income taxes	(3,840		)	(857		)	(4,843		)	Deferred income taxes	936		(3,840)		(857)
Net change in fair value contracts	27			(243		)	188			Net change in fair value contracts	(2)		27		(243)
Losses from equity investment	—			468			—			Losses from equity investment	—		—		468
Impairment of investments in unconsolidated affiliates	2,500			1,732			—			Impairment of investments in unconsolidated affiliates	—		2,500		1,732
Loss on deconsolidation of subsidiary (Note 3)	3,505			—			—
Loss on deconsolidation of subsidiary (Note 4)										Loss on deconsolidation of subsidiary (Note 4)	—		3,505		—
Changes in assets and liabilities:										Changes in assets and liabilities:
Accounts receivable	(34,935		)	(15,368		)	72,594			Accounts receivable	36,350		(34,935)		(15,368)
Accounts receivable/payable, affiliates	271			—			—			Accounts receivable/payable, affiliates	24		271		—
Inventories	878			(5,399		)	5,810			Inventories	(10,587)		878		(5,399)
Income tax receivable	1,418			(148		)	(1,617		)	Income tax receivable	(1,087)		1,418		(148)
Prepayments and other current assets	831			492			8,351			Prepayments and other current assets	(293)		831		492
Accounts payable	44,790			6,984			(87,404		)	Accounts payable	(10,252)		44,790		6,984
Accrued liabilities	(991		)	52			(166		)	Accrued liabilities	1,744		(991)		52
Other	(962		)	(440		)	(2,269		)	Other	1,717		(962)		(440)
Net cash provided by operating activities	26,096			6,944			25,477			Net cash provided by operating activities	31,014		26,096		6,944

Investing activities:										Investing activities:
Property and equipment additions	(2,644		)	(8,484		)	(11,074		)	Property and equipment additions	(11,731)		(2,644)		(8,484)
Asset acquisition										Asset acquisition	(10,272)		—		—
Proceeds from property sales	720			3,706			719			Proceeds from property sales	2,038		720		3,706
Proceeds from sales of AREC assets	2,775			—			—			Proceeds from sales of AREC assets	—		2,775		—
Investments in unconsolidated affiliates	—			(4,700		)	—			Investments in unconsolidated affiliates	—		—		(4,700)
Insurance and state collateral (deposits) refunds	(1,067		)	1,710			283			Insurance and state collateral (deposits) refunds	830		(1,067)		1,710
Net cash used in investing activities	(216		)	(7,768		)	(10,072		)	Net cash used in investing activities	(19,135)		(216)		(7,768)

Financing activities:										Financing activities:
Principal repayments of capital lease obligations	(118		)	—			—			Principal repayments of capital lease obligations	(495)		(118)		—
Dividends paid on common stock	(3,711		)	(3,711		)	(3,712		)	Dividends paid on common stock	(3,711)		(3,711)		(3,711)
Net cash used in financing activities	(3,829		)	(3,711		)	(3,712		)	Net cash used in financing activities	(4,206)		(3,829)		(3,711)

Increase (decrease) in cash and cash equivalents	22,051			(4,535		)	11,693			Increase (decrease) in cash and cash equivalents	7,673		22,051		(4,535)
Cash and cash equivalents at beginning of period	87,342			91,877			80,184			Cash and cash equivalents at beginning of period	109,393		87,342		91,877
Cash and cash equivalents at end of period	$	109,393		$	87,342		$	91,877		Cash and cash equivalents at end of period	$	117,066	$	109,393	$	87,342

See Notes to Consolidated Financial Statements.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(In thousands)


							Total
	Common		Contributed		Retained		Shareholders’
	Stock		Capital		Earnings		Equity

Balance, January 1, 2016	$	422	$	11,693	$	140,395	$	152,510
Net earnings	—		—		2,513		2,513
Dividends declared:
Common stock, $0.88/share	—		—		(3,711)		(3,711)
Balance, December 31, 2016	422		11,693		139,197		151,312
Net losses	—		—		(482)		(482)
Dividends declared:
Common stock, $0.88/share	—		—		(3,711)		(3,711)
Balance, December 31, 2017	422		11,693		135,004		147,119
Net earnings	—		—		2,945		2,945
Stock-based compensation expense	—		255		—		255
Dividends declared:
Common stock, $0.88/share	—		—		(3,711)		(3,711)
Awards under LTIP, $0.44/share	—		—		(10)		(10)
Balance, December 31, 2018	$	422	$	11,948	$	134,228	$	146,598

Total
Common Contributed Retained Stockholders’
Stock Capital Earnings Equity

Balance, January 1, 2015 $ 422
$ 11,693
$ 145,382
$ 157,497
Net losses —
—
(1,275 ) (1,275 )
Dividends paid on common stock —
—
(3,712 ) (3,712 )
Balance, December 31, 2015 422
11,693
140,395
152,510
Net earnings —
—
2,513
2,513
Dividends paid on common stock —
—
(3,711 ) (3,711 )
Balance, December 31, 2016 422
11,693
139,197
151,312
Net losses —
—
(482 ) (482 )
Dividends paid on common stock —
—
(3,711 ) (3,711 )
Balance, December 31, 2017 $ 422
$ 11,693
$ 135,004
$ 147,119

See Notes to Consolidated Financial Statements.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. 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~~American LLC ~~(“NYSE MKT”)~~ under the ticker symbol “AE”. We, ~~and~~through 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 34 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 34 for further information). We obtained approval of a confirmed plan in December 2017, and ~~we expect~~ the case ~~to be~~was dismissed ~~during the first half of~~in October 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 34 for further information).

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

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Use of Estimates

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

Note 2. Summary of Significant Accounting Policies

We adhere to the following significant accounting policies in the preparation of our consolidated financial statements.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable associated with crude oil marketing activities comprise approximately 90 percent of our total receivables, and industry practice requires payment for these sales to occur within 20 days of the end of the month following a transaction. Our customer makeup, credit policies and the relatively short duration of receivables mitigate the uncertainty typically associated with receivables management. An allowance for doubtful accounts is provided where appropriate.

Our allowance for doubtful accounts is determined based on specific identification combined with a review of the general status of the aging of all accounts. We consider the following factors in our review of our allowance for doubtful accounts: (i) historical experience with customers, (ii) the perceived financial stability of customers based on our research, (iii) the levels of credit we grant to customers, and (iv) the duration of the receivable. We may increase the allowance for doubtful accounts in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties. On a routine basis, we review estimates associated with the allowance for doubtful accounts to ensure that we have recorded sufficient reserves to cover potential losses. See Note 1416 for further information regarding credit risk.

The following table presents our allowance for doubtful accounts activity for the periods indicated (in thousands):


	December 31,
	2018		2017		2016

Balance at beginning of period	$	303	$	225	$	206
Charges to costs and expenses	43		137		100
Deductions	(193)		(59)		(81)
Balance at end of period	$	153	$	303	$	225

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.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Basic earnings (losses) per share is computed by dividing our net earnings (losses) by the weighted average number of shares of common stock outstanding during the period. Diluted earnings (losses) per share is computed by giving effect to all potential shares of common stock outstanding, including our stock related to unvested restricted stock unit awards. Unvested restricted stock unit awards granted under the Adams Resources & Energy, Inc. 2018 Long-Term Incentive Plan (“2018 LTIP”) are not considered to be participating securities as the holders of these shares do not have non-forfeitable dividend rights in the event of our declaration of a dividend for common shares (see Note 13 for further discussion).

A reconciliation of the calculation of basic and diluted earnings (losses) per share is as follows (in thousands, except per share data):


	Year Ended December 31,
	2018		2017		2016
Earnings (losses) per share – numerator:
Earnings (losses) from continuing operations	$	2,945	$	(482)	$	3,943
Losses from investment in unconsolidated affiliate, net of tax	—		—		(1,430)
Net (losses) earnings	$	2,945	$	(482)	$	2,513

Denominator:
Basic weighted average number of shares outstanding	4,218		4,218		4,218

Basic earnings (losses) per share:
From continuing operations	$	0.70	$	(0.11)	$	0.94
From investment in unconsolidated affiliate	—		—		(0.34)
Basic earnings (losses) per share	$	0.70	$	(0.11)	$	0.60

Diluted earnings (losses) per share:

Diluted weighted average number of shares outstanding:
Common shares	4,218		4,218		4,218
Restricted stock unit awards ⁽¹⁾	—		—		—
Performance share unit awards ⁽²⁾	—		—		—
Total	4,218		4,218		4,218

Diluted earnings (losses) per share:
From continuing operations	$	0.70	$	(0.11)	$	0.94
From investment in unconsolidated affiliate	—		—		(0.34)
Diluted earnings (losses) per share	$	0.70	$	(0.11)	$	0.60

________________________

(1) The dilutive effect of restricted stock unit awards for the year ended December 31, 2018 is de minimis.

(2) The dilutive effect of performance share awards will be included in the calculation of diluted earnings per share when the performance share award performance conditions have been achieved.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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,
	2018		2017		2016

Contributory expenses	$	808	$	734	$	757

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. Marketable securities are recorded at fair value based on market quotations from actively traded liquid markets.

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.

~~Table of Contents~~

~~ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

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 1011 for further information).

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 1011 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 1112 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~~impacts our ~~deferred~~income tax ~~assets and liabilities.~~provision or benefit.

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~~ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

Inventory

Inventory consists of crude oil held in storage tanks and at third-party pipelines as part of our crude oil marketing operations. Crude oil inventory is carried at the lower of ~~average~~ cost or net realizable value. At the end of each reporting period, we assess the carrying value of our inventory and make adjustments necessary to reduce the carrying value to the applicable net realizable value. Any resulting adjustments are a component of marketing costs and expenses on our consolidated statements of operations. During the year ended December 31, 2018, we recorded a charge of $5.4 million related to the write-down of our crude oil inventory due to declines in prices. There were no charges recognized during the years ended December 31, 2017 and 2016.

Letter of Credit Facility

We maintain a Credit and Security Agreement with Wells Fargo Bank, National Association to provide for the issuance of up to a $60 million in stand-by ~~letter~~letters of credit ~~facility~~primarily 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~~letters 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,~~30, 2019.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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~~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. However, per the terms of our letter of credit agreement, we were in default of certain nonfinancial covenants at December 31, 2018, and we obtained a waiver whereby the creditor will not exercise any of its rights or remedies. At December 31, 2018 and 2017, we had $4.6 million and $2.2 million, respectively, of letters of credit 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~~two to ~~twenty~~thirty-nine 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 56 for additional information regarding our property and equipment and AROs.

Recent Accounting Pronouncements

Lease accounting standard. In February 2016, the Financial Accounting Standards Board issued Accounting Standards Codification (“ASC”) 842, Leases (“ASC 842”), which requires substantially all leases to be recorded on the balance sheet. We adopted the new standard on January 1, 2019 and expect to apply it to all existing lease contracts as of January 1, 2019. We also plan to apply it to all new leases entered into after January 1, 2019. ASC 842 supersedes existing lease accounting guidance under ASC 840, Leases (“ASC 840”).

We expect to adopt the new standard using the modified retrospective approach and apply certain optional transitional practical expedients. We elected an optional transition method that allowed application of the new standard at the adoption date and the recognition of a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption with no adjustment to previously reported results. In accordance with this approach, our consolidated financial statements for periods prior to January 1, 2019 will not be revised to reflect the new lease accounting guidance. We also elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allowed the carry forward of historical lease classification. We did not elect the practical expedient related to hindsight.

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ASC 842 will result in changes to the way our operating leases are recorded, presented and disclosed in our consolidated financial statements. Upon adoption of ASC 842 on January 1, 2019, we expect to recognize a right-of-use (“ROU”) asset and a corresponding lease liability based on the present value of then existing operating lease obligations. In addition, there are several key accounting policy elections that we will make upon adoption of ASC 842 including:

•We will not recognize ROU assets and lease liabilities for short-term leases and will instead record them in a manner similar to operating leases under ASC 840 lease accounting guidelines. A short term lease is one with a maximum lease term of 12 months or less and does not include a purchase option or renewal option the lessee is reasonably certain to exercise.

•We will also elect the non-lease component for any asset class where lease and non-lease components are comingled and the non-lease component is determined to be insignificant when compared to the lease component.

Upon adoption of this new guidance, we expect to recognize a ROU asset and lease liability for operating leases of approximately $11.4 million on our consolidated balance sheet based upon discounted amounts on January 1, 2019.

Stock-Based Compensation

We measure all share-based payment, including the issuance of restricted stock units and performance share units to employees and board members, using a fair-value based method. The cost of services received from employees and non-employee board members in exchange for awards of equity instruments is recognized in the consolidated statement of operations based on the estimated fair value of those awards on the grant date and amortized on a straight-line basis over the requisite service period. The fair value of restricted stock unit awards and performance share unit awards is based on the closing price of our common stock on the grant date. We account for forfeitures as they occur. See Note 13 for additional information regarding our 2018 LTIP.

Note 3. Revenue Recognition

Adoption of ASC 606

On January 1, 2018, we adopted ASC 606, Revenue from Contracts with Customers (“ASC 606”) and all related Accounting Standards Updates by applying the modified retrospective method to all contracts that were not completed on January 1, 2018. The modified retrospective approach required us to recognize the cumulative effect of initially applying the new standard as an adjustment to the opening balance of retained earnings on January 1, 2018. Comparative information has not been restated and continues to be reported under the historical accounting standards in effect for those periods. The adoption of the new revenue standard did not result in a cumulative effect adjustment to our retained earnings since there was no significant impact upon adoption of the new standard. There was also no material impact to revenues, or any other financial statement line items for the year ended December 31, 2018 as a result of applying ASC 606. We expect the impact of the adoption of ASC 606 to remain immaterial to our net earnings on an ongoing basis.

Revenue Recognition

~~Certain commodity purchase~~The new revenue standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The new revenue standard requires entities to recognize revenue through the application of a five-step model, which includes: identification of the contract; identification of the performance obligations; determination of the transaction price; allocation of the transaction price to the performance obligations; and ~~sale~~recognition of revenue as the entity satisfies the performance obligations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Our revenues are primarily generated from the marketing, transportation and storage of crude oil and other related products and the tank truck transportation of liquid chemicals and dry bulk. A performance obligation is a promise in a contract to transfer a distinct good or service to the customer and is the unit of account in ASC 606. To identify the performance obligations, we considered all of the products or services promised in the contracts ~~utilized by~~with customers, whether explicitly stated or implied based on customary business practices. Revenue is recognized when, or as, each performance obligation is satisfied under terms of the contract. Payment is typically due in full within 30 days of the invoice date.

For our crude oil marketing ~~business qualify as derivative instruments with certain specifically identified contracts also designated as trading activities. From the time~~segment, most 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~~our 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, generally upon delivery of the product to the customer. Revenue is recognized based on the transaction price and the quantity delivered.

The majority of our crude oil sales contracts have multiple distinct performance obligations as the promise to transfer the individual goods (e.g., barrels of crude oil) is separately identifiable from the other goods promised within the contracts. Our performance obligations are satisfied at a point in time. For normal sales arrangements, revenue is recognized in the month in which control of the physical product is transferred to the customer, generally upon delivery of the product to the customer.

For our transportation segment, each sales order associated with our master transportation agreements is considered a distinct performance obligation. The performance obligations associated with this segment are satisfied over time as the goods and services are delivered.

Practical Expedients

In connection with our adoption of ASC 606, we reviewed our revenue contracts for impact upon adoption. For example, our revenue contracts often include promises to transfer various goods and services to a customer. Determining whether goods and services are considered distinct performance obligations that should be accounted for separately versus together will continue to require continual assessment. We also used practical expedients permitted by ASC 606 when applicable. These ~~sales~~practical expedients included:

•Applying the new guidance only to contracts that were not completed as of January 1, 2018; and

•Not accounting for the effects of significant financing components if the company expects that the period between when the entity transfers a promised good or service to a customer and when the customer pays for that good or service will be one year or less.

Contract Balances

The timing of revenue recognition, billings and cash collections results in billed accounts receivable and customer advances and deposits (contract liabilities) on our consolidated balance sheet. Currently, we do not record any contract assets in our financial statements due to the timing of revenue recognized and when our customers are billed. Our crude oil marketing customers are generally billed monthly based on contractually agreed upon terms. However, we sometimes receive advances or deposits from customers before revenue is recognized, resulting in contract liabilities. These contract assets and liabilities, if any, are reported on our consolidated balance sheets at the end of each reporting period.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Revenue Disaggregation

The following table disaggregates our revenue by segment and by major source for the period indicated (in thousands):


	Year Ended December 31, 2018
	Reporting Segments
	Marketing		Transportation		Total

Revenues from contracts with customers	$	1,580,997	$	55,776	$	1,636,773
Other ⁽¹⁾	113,440		—		113,440
Total revenues	$	1,694,437	$	55,776	$	1,750,213

Timing of revenue recognition:
Goods transferred at a point in time	$	1,580,997	$	—	$	1,580,997
Services transferred over time	—		55,776		55,776
Total revenues from contracts with customers	$	1,580,997	$	55,776	$	1,636,773

_______________

(1) Other crude oil marketing revenues are recognized under ASC 815, Derivatives and Hedging, and ASC 845, Nonmonetary Transactions – Purchases and Sales of Inventory with the Same Counterparty.

Other Marketing Revenue

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

Certain of our 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,
	2018		2017		2016

Revenue gross-up	$	448,846	$	203,095	$	314,270

Year Ended December 31,
2017 2016 2015

Revenue gross-up $ 203,095
$ 314,270
$ 480,111

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

~~Recent Accounting Pronouncements~~

~~Revenue Recognition. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Codification Topic 606,~~ ~~Revenue from Contracts with Customers~~ (“ASC 606”). The new accounting standard, along with its related amendments, replaces the current rules-based GAAP governing revenue recognition with a principles-based approach. Under the new standard, a company recognizes revenue when it satisfies a performance obligation by transferring a promised good or service to a customer at an amount that reflects the consideration it expects to receive in exchange for those goods and services. The standard also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments. ASC 606 is effective for interim and annual reporting periods beginning after December 15, 2017 and may be applied on either a full or modified retrospective basis.

We adopted the new standard and all related amendments on January 1, 2018 using the modified retrospective approach. This approach required us to apply the new revenue standard to (i) all new revenue contracts entered into after January 1, 2018 and (ii) all existing revenue contracts open as of January 1, 2018, with a cumulative adjustment to retained earnings, if applicable. In accordance with this approach, our consolidated revenues for periods prior to January 1, 2018 will not be restated. In addition, no cumulative adjustment will be required to be made to our retained earnings, as there are no material differences in the nature, amount, timing or uncertainty of revenues recognized following our adoption of this new standard on January 1, 2018. We have also evaluated our business processes, systems and controls to ensure the accuracy and timeliness of the recognition and disclosure requirements under the new revenue guidance.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

~~Leases. In February 2016, the FASB issued ASC 842,~~ ~~Leases~~ (“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.

Note 3.4. 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.

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~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

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

In October 2017, AREC submitted its liquidation plan to the Bankruptcy Court for approval. In connection with the sales of these assets and 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~~expected 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~~case was dismissed during October 2018, and we expect final settlement and liquidation to ~~be completed with~~occur during 2019. At December 31, 2018, we have a ~~confirmed plan during 2018.~~receivable from AREC of approximately $0.4 million related to the final settlement of AREC.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 4.5. Prepayments and Other Current Assets

The components of prepayments and other current assets were as follows at the dates indicated (in thousands):


	December 31,
	2018		2017

Insurance premiums	$	677	$	425
Rents, licenses and other	880		839
Total	$	1,557	$	1,264

December 31,
2017 2016

Insurance premiums $ 425
$ 1,403
Rents, licenses and other 839
694
Total $ 1,264
$ 2,097

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~~ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

Note 5.6. 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								Estimated
	Useful Life	December 31,							Useful Life	December 31,
	in Years	2017			2016				in Years	2018		2017

Tractors and trailers ⁽¹⁾	5 – 6	$	88,065		$	89,576		Tractors and trailers ⁽¹⁾	5 – 6	$	96,523	$	88,065
Oil and gas (successful efforts)		—			62,784
Field equipment	2 – 5	18,490			18,282			Field equipment	2 – 5	20,725		18,490
Buildings	5 – 39	15,727			15,707			Buildings	5 – 39	15,746		15,727
Office equipment	1 – 5	1,929			1,913			Office equipment	2 – 5	1,863		1,929
Land		1,790			1,790			Land		1,790		1,790
Construction in progress		275			596			Construction in progress		2,794		275
Total		126,276			190,648			Total		139,441		126,276
Less accumulated depreciation		(96,914		)	(144,323		)	Less accumulated depreciation		(94,818)		(96,914)
Property and equipment, net		$	29,362		$	46,325		Property and equipment, net		$	44,623	$	29,362

______________


~~(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).

(1) Amounts include tractors held under capital leases in our crude oil marketing segment. At December 31, 2018 and 2017, gross property and equipment associated with assets held under capital leases were $4.7 million and $1.8 million, respectively. Accumulated amortization associated with assets held under capital leases were $0.7 million and $0.1 million at December 31, 2018 and 2017, respectively (see Note 15 for further information).

Components of depreciation, depletion and amortization expense were as follows for the periods indicated (in thousands):


	Year Ended December 31,
	2018		2017		2016
Depreciation, depletion and amortization, excluding amounts
under capital leases	$	10,112	$	13,478	$	18,792
Amortization of property and equipment under capital leases	542		121		—
Total depreciation, depletion and amortization	$	10,654	$	13,599	$	18,792

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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
Asset Acquisition

On October 1, 2018, we completed the purchase of a trucking company for $10.0 million that owned approximately 113 tractors and 126 trailers operating in the Red River area in North Texas and South Central Oklahoma. This acquisition is included in our crude oil marketing segment from the date of the acquisition. We incurred approximately $0.3 million of acquisition costs in connection with this acquisition, which was included in the allocation of the purchase price to the assets acquired. The purchase price of approximately $10.3 million was allocated on October 1, 2018 as follows (in thousands):



Tractors	$	4,799
Trailers	4,901
Field equipment	381
Materials and supplies	191
Total	$	10,272

Gains on Sales of Assets

We sold certain used trucks and equipment and recorded net pre-tax gains as follows for the periods indicated (in thousands):


	Year Ended December 31,
	2018		2017		2016

Gains on sales of used trucks and equipment	$	1,240	$	594	$	1,966

Crude Oil and Natural Gas Exploration and Production Assets

Our subsidiary that owned the upstream crudeoil and natural gas exploration and production assets was deconsolidated effective with its bankruptcy filing in April 2017 and subsequently accounted for as a cost method investment (see Note 3)4). 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~~included 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,
	2018		2017		2016

Producing property impairments	$	—	$	—	$	30
Non-producing property impairments	—		3		283
Total crude oil and natural gas impairments	$	—	$	3	$	313

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

~~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,										Year Ended December 31,
	2017			2016			2015				2018		2017		2016

ARO liability beginning balance	$	2,329		$	2,469		$	2,464		ARO liability beginning balance	$	1,273	$	2,329	$	2,469
Liabilities incurred	18			162			39			Liabilities incurred	252		18		162
Accretion of discount	58			92			93			Accretion of discount	36		58		92
Liabilities settled	(261		)	(394		)	(127		)	Liabilities settled	(36)		(261)		(394)
Deconsolidation of subsidiary ⁽¹⁾	(871		)	—			—			Deconsolidation of subsidiary ⁽¹⁾	—		(871)		—
ARO liability ending balance	$	1,273		$	2,329		$	2,469		ARO liability ending balance	$	1,525	$	1,273	$	2,329

_______________


~~(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~~ (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 4 for further information).

Note 6.7. Cash Deposits and Other Assets

Components of cash deposits and other assets were as follows at the dates indicated (in thousands):


	December 31,
	2018		2017

Amounts associated with liability insurance program:
Insurance collateral deposits ⁽¹⁾	$	1,453	$	3,767
Excess loss fund	1,916		2,284
Accumulated interest income	788		814
Other amounts:
State collateral deposits	57		57
Materials and supplies	443		273
Other	—		37
Total	$	4,657	$	7,232

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
_______________

(1) During 2018, we issued a letter of credit of approximately $4.2 million to the insurance companies in connection with our liability insurance program, and as a result, our cash collateral deposit was refunded to us.

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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. Insurance collateral deposits are invested at the discretion of our insurance carrier. 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~~

Table 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).Contents

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 7.8. Investments in Unconsolidated Affiliates

At December 31, ~~2017,~~2018, 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~~we 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,~~2018, 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,~~a result, 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,~~2018, we continue to own an approximate 15 percent equity interest in VestaCare.

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~~ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

AREC

As a result of AREC’s voluntary bankruptcy filing in April 2017 and our loss of control of ~~AREC,~~this subsidiary, 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~~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, net of estimated transaction costs. AsDuring the third quarter of 2017, 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~~represented the difference between the net proceeds we ~~expect~~expected 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. The bankruptcy case was dismissed during October 2018, and we expect final settlement and liquidation of the company to occur during 2019. At December 31, 2018, we have a receivable from AREC of approximately $0.4 million ~~(see Note 3 for further information). The remaining investment will be removed upon~~related to the final settlement of ~~the bankruptcy, which is anticipated during the first half of 2018.~~AREC.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 8.9. 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 34 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
	Reporting Segments											Marketing		Transportation		Oil and Gas and Other		Total
	Marketing		Transportation			Oil and Gas			Total
Year Ended December 31, 2018											Year Ended December 31, 2018
Revenues											Revenues	$	1,694,437	$	55,776	$	—	$	1,750,213
Segment operating (losses) earnings ⁽¹⁾											Segment operating (losses) earnings ⁽¹⁾	7,008		3,337		—		10,345
Depreciation, depletion and amortization											Depreciation, depletion and amortization	6,384		4,270		—		10,654
Property and equipment additions ^{(3) (4)}											Property and equipment additions ^{(3) (4)}	1,540		10,178		13		11,731

Year Ended December 31, 2017											Year Ended December 31, 2017
Revenues	$	1,267,275	$	53,358		$	1,427		$	1,322,060	Revenues	$	1,267,275	$	53,358	$	1,427	$	1,322,060
Segment operating (losses) earnings ^{(1) (2)}	11,700		(544		)	53			11,209		Segment operating (losses) earnings ^{(1) (2)}	11,700		(544)		53		11,209
Depreciation, depletion and amortization	7,812		5,364			423			13,599		Depreciation, depletion and amortization	7,812		5,364		423		13,599
Property and equipment additions ⁽³⁾	468		351			1,825			2,644		Property and equipment additions ⁽³⁾	468		351		1,825		2,644

Year Ended December 31, 2016											Year Ended December 31, 2016
Revenues	$	1,043,775	$	52,355		$	3,410		$	1,099,540	Revenues	$	1,043,775	$	52,355	$	3,410	$	1,099,540
Segment operating (losses) earnings ⁽¹⁾	17,045		(48		)	(533		)	16,464		Segment operating (losses) earnings ⁽¹⁾	17,045		(48)		(533)		16,464
Depreciation, depletion and amortization	9,997		7,249			1,546			18,792		Depreciation, depletion and amortization	9,997		7,249		1,546		18,792
Property and equipment additions	1,321		6,868			295			8,484		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 gassegment’s operating earnings included property impairments of $12.1 million for the year ended December 31, 2015.~~

(1) Our crude oil marketing segment’s operating earnings included inventory valuation losses of $5.4 million for the year ended December 31, 2018, and inventory liquidation gains of $3.3 million and $8.2 million for the years ended December 31, 2017 and 2016, respectively.

(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 crude oil marketing segment’s property and equipment additions do not include approximately $2.9 million and $1.8 million of tractors acquired during the years ended December 31, 2018 and 2017, respectively, under capital leases. See Note 15 for further information.

(4) During the year ended December 31, 2018, we had $13 thousand of property and equipment additions for leasehold improvements at our corporate headquarters, which is not attributed or allocated to any of our reporting segments.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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,										Year Ended December 31,
	2017			2016			2015				2018		2017		2016

Segment operating earnings	$	11,209		$	16,464		$	7,580		Segment operating earnings	$	10,345	$	11,209	$	16,464
General and administrative ⁽¹⁾	(9,707		)	(10,410		)	(9,939		)	General and administrative ⁽¹⁾	(8,937)		(9,707)		(10,410)
Operating earnings (losses)	1,502			6,054			(2,359		)	Operating earnings (losses)	1,408		1,502		6,054
Loss on deconsolidation of subsidiary	(3,505		)	—			—			Loss on deconsolidation of subsidiary	—		(3,505)		—
Impairment of investment in unconsolidated affiliate	(2,500		)	—			—			Impairment of investment in unconsolidated affiliate	—		(2,500)		—
Interest income	1,103			582			327			Interest income	2,155		1,103		582
Interest expense	(27		)	(2		)	(13		)	Interest expense	(109)		(27)		(2)
(Losses) earnings before income taxes and investment										(Losses) earnings before income taxes and investment
in unconsolidated affiliate	$	(3,427	)	$	6,634		$	(2,045	)	in unconsolidated affiliate	$	3,454	$	(3,427)	$	6,634

_______________


~~(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.~~

(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,							December 31,
	2017		2016		2015			2018		2017		2016

Reporting segment:							Reporting segment:
Marketing	$	134,745	$	107,257	$	96,723	Marketing	$	119,370	$	134,745	$	107,257
Transportation	29,069		32,120		35,010		Transportation	34,112		29,069		32,120
Oil and Gas ⁽¹⁾	425		7,279		8,930		Oil and Gas ⁽¹⁾	—		425		7,279
Cash and other	118,465		100,216		102,552		Cash and other	125,388		118,465		100,216
Total assets	$	282,704	$	246,872	$	243,215	Total assets	$	278,870	$	282,704	$	246,872

____________________


~~(1)~~	~~At December 31, 2017, amount represents our remaining cost method investment in this segment. See Note 3~~ (1) At December 31, 2017, amount represents our remaining cost method investment in this segment. See Note 4 for further information.

~~Intersegment~~

There were no intersegment sales ~~are~~during the year ended December 31, 2018, and intersegment sales during the years ended December 31, 2017 and 2016 were 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.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9.10. 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 1315 for further information). Bencap earns a fee from us for providing such services at a discounted amount from its standard charge to non-affiliates. We had an equity method investment in Bencap, which was forfeited during the first quarter of 2017. As ~~discussed in Note 7, at December 31, 2017,~~a result, we have no further ownership interest in ~~Bencap.~~Bencap (see Note 8).

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~~ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

Activities with affiliates were as follows for the periods indicated (in thousands):


	Year Ended December 31,							Year Ended December 31,
	2017		2016		2015			2018		2017		2016

Overhead recoveries ⁽¹⁾	$	—	$	32	$	97	Overhead recoveries ⁽¹⁾	$	—	$	—	$	32
Affiliate billings to us	81		65		68		Affiliate billings to us	75		81		65
Billings to affiliates	4		5		35		Billings to affiliates	6		4		5
Rentals paid to affiliate	583		628		618		Rentals paid to affiliate	487		583		628
Fee paid to Bencap ⁽²⁾	108		583		—		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.~~

(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 34 for further information).

Note ~~10.~~11. Derivative Instruments and Fair Value Measurements

Derivative Instruments

At December 31, 2018, we had in place ten commodity purchase and sale contracts with fair value associated with them as the contractual prices of crude oil were outside of the range of prices specified in the agreements. These commodity purchase and sale contracts encompassed approximately:

•322 barrels per day of crude oil during January 2019 through April 2019;

•258 barrels per day of crude oil during May 2019;

•322 barrels per day of crude oil during June 2019 through August 2019; and

•258 barrels per day of crude oil during September 2019 through December 2019.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2018
	Balance Sheet Location and Amount
	Current		Other		Current		Other
	Assets		Assets		Liabilities		Liabilities
Asset derivatives:
Fair value forward hydrocarbon commodity
contracts at gross valuation	$	162	$	—	$	—	$	—
Liability derivatives:
Fair value forward hydrocarbon commodity
contracts at gross valuation	—		—		139		—
Less counterparty offsets	—		—		—		—
As reported fair value contracts	$	162	$	—	$	139	$	—

At December 31, 2017, we had in place 20twenty 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 commodity purchase and sale contracts encompassed approximately:

•452 barrels per day of crude oil during January 2018;

•322 barrels per day of crude oil during February through May 2018;

•258 barrels per day of crude oil during June 2018;

•646 barrels per day of crude oil during July 2018;

•322 barrels per day of crude oil during August through September 2018; and

•258 barrels per day of crude oil during October through December 2018.

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~~ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

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	$	—

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~~2018 and ~~2016,~~2017, 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.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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,
	2018		2017		2016

Revenues – marketing	$	2	$	(26)	$	243

Gains (Losses)
Year Ended December 31,
2017 2016 2015

Revenues – marketing $ (26 ) $ 243
$ (188 )

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~~ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

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, 2018
	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	$	—	$	162	$	—	$	—	$	162
Current liabilities	—		(139)		—		—		(139)
Net value	$	—	$	23	$	—	$	—	$	23

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, 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~~2018 and ~~2016,~~2017, 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.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. During the year ended December 31, 2018, we had no long-lived assets that were subject to non-recurring fair value measurements.

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

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

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note ~~11.~~12. Income Taxes

The components of our income tax (provision) benefit were as follows for the periods indicated (in thousands):


	Year Ended December 31,										Year Ended December 31,
	2017			2016			2015				2018		2017		2016
Current:										Current:
Federal	$	(1,418	)	$	(2,103	)	$	(3,883	)	Federal	$	388	$	(1,418)	$	(2,103)
State	523			(675		)	(190		)	State	39		523		(675)
Total current	(895		)	(2,778		)	(4,073		)	Total current	427		(895)		(2,778)
Deferred:										Deferred:
Federal	3,722			777			5,011			Federal	(752)		3,722		777
State	118			80			(168		)	State	(184)		118		80
Total deferred	3,840			857			4,843			Total deferred	(936)		3,840		857
Total provision for (benefit from) income taxes⁽¹⁾	$	2,945		$	(1,921	)	$	770
Total (provision for) benefit from income taxes⁽¹⁾										Total (provision for) benefit from income taxes⁽¹⁾	$	(509)	$	2,945	$	(1,921)

______________


~~(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.~~

(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)~~(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,
	Year Ended December 31,										2018		2017		2016
	2017			2016			2015

Pre-tax net book income ⁽¹⁾	$	(3,427	)	$	4,434		$	(2,045	)
Pre-tax net book income (loss) ⁽¹⁾										Pre-tax net book income (loss) ⁽¹⁾	$	3,454	$	(3,427)	$	4,434

Statutory federal income tax (provision) benefit	$	1,165		$	(1,552	)	$	716		Statutory federal income tax (provision) benefit	$	(725)	$	1,165	$	(1,552)
State income tax (provision) benefit	736			(387		)	(233		)	State income tax (provision) benefit	(145)		736		(387)
Federal statutory depletion	153			62			144			Federal statutory depletion	—		153		62
Federal tax rate adjustment	2,007			—			—			Federal tax rate adjustment	—		2,007		—
Valuation allowance	(1,038		)	—			—			Valuation allowance	—		(1,038)		—
Reverse valuation allowance										Reverse valuation allowance	98		—		—
Return to provision adjustments										Return to provision adjustments	388		—		—
Other	(78		)	(44		)	143			Other	(125)		(78)		(44)
Total provision for (benefit from) income taxes	$	2,945		$	(1,921	)	$	770
Effective income tax rate ⁽²⁾	86		%	43		%	38		%
Total (provision for) benefit from income taxes										Total (provision for) benefit from income taxes	$	(509)	$	2,945	$	(1,921)
Effective income tax rate ⁽²⁾⁽³⁾										Effective income tax rate ⁽²⁾⁽³⁾	15%		86%		43%

_______________


~~(1)~~	(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~~.

(2) Excluding the adjustment related to the federal tax rate change, the effective income tax rate for 2017 is 58 percent.

(3) Excluding the adjustment related to the return to provision, the effective income tax rate for 2018 is 26 percent.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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,							December 31,
	2017			2016				2018		2017

Long-term deferred tax asset (liability): ⁽¹⁾							Long-term deferred tax asset (liability): ⁽¹⁾
Prepaid and other insurance	$	(684	)	$	(1,058	)	Prepaid and other insurance	$	(170)	$	(684)
Property	(2,497		)	(7,341		)	Property	(5,259)		(2,497)
Investments in unconsolidated affiliates	623			606			Investments in unconsolidated affiliates	525		623
Valuation allowance related to investments in unconsolidated affiliates	(623		)	—			Valuation allowance related to investments in unconsolidated affiliates	(525)		(623)
Uniform capitalization	—			729
Net operating loss							Net operating loss	1,436		—
Other	(121		)	(93		)	Other	(245)		(121)
Net long-term deferred tax liability	(3,302		)	(7,157		)	Net long-term deferred tax liability	(4,238)		(3,302)
Net deferred tax liability	$	(3,302	)	$	(7,157	)	Net deferred tax liability	$	(4,238)	$	(3,302)

______________


~~(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.~~

(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		~~Earliest Open~~2014
Texas		~~Tax Year~~2014
Louisiana		2015
~~Federal~~Michigan		~~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.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 13. Share-Based Compensation Plan

In May 2018, our shareholders approved the 2018 LTIP, a long-term incentive plan under which any employee or non-employee director who provides services to us is eligible to participate in the plan. The 2018 LTIP, which is overseen by the Compensation Committee of our Board of Directors, provides for the grant of various types of equity awards, of which restricted stock unit awards and performance-based compensation awards were granted during the second quarter of 2018. The maximum number of shares authorized for issuance under the 2018 LTIP is 150,000 shares, and the 2018 LTIP is effective until May 8, 2028. We began awarding share-based compensation to eligible employees and directors in June 2018. After giving effect to awards granted under the 2018 LTIP and assuming the potential achievement of the maximum amounts of the performance factors through December 31, 2018, a total of 120,403 shares were available for issuance. During the year ended December 31, 2018, we recognized $0.3 million of compensation expense in connection with equity-based awards.

If dividends are paid with respect to our common shares during the vesting period, an equivalent amount will accrue and be held by us without interest until the restricted stock unit awards and performance share unit awards vest, at which time the amount will be paid to the recipient. If the award is forfeited prior to vesting, the accrued dividends will also be forfeited. At December 31, 2018, we had $10.0 thousand of accrued dividend amounts for awards granted under the 2018 LTIP.

Restricted Stock Unit Awards

A restricted stock unit award is a grant of a right to receive our common shares in the future at no cost to the recipient apart from fulfilling service and other conditions once a defined vesting period expires, subject to customary forfeiture provisions. A restricted stock unit award will either be settled by the delivery of common shares or by the payment of cash based upon the fair market value of a specified number of shares, at the discretion of the Compensation Committee, subject to the terms of the applicable award agreement. The Compensation Committee intends for these awards to vest with the settlement of common shares. Restricted stock unit awards generally vest at a rate of approximately 33 percent per year beginning one year after the grant date and are non-vested until the required service periods expire.

The fair value of a restricted stock unit award is based on the market price per share of our common shares on the date of grant. Compensation expense is recognized based on the grant date fair value over the requisite service or vesting period.

The following table presents restricted stock unit award activity for the periods indicated:


		Weighted-
		Average Grant
	Number of	Date Fair Value
	Shares	per Share ⁽¹⁾

Restricted stock unit awards at January 1, 2018	—	$	—
Granted ⁽²⁾	13,733	$	43.00
Vested	—	$	—
Forfeited	—	$	—
Restricted stock unit awards at December 31, 2018	13,733	$	—

____________________

(1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.

(2) The aggregate grant date fair value of restricted stock unit awards issued during 2018 was $0.6 million based on a grant date market price of our common shares of $43.00 per share.

Unrecognized compensation cost associated with restricted stock unit awards was approximately $0.4 million at December 31, 2018. Due to the graded vesting provisions of these awards, we expect to recognize the remaining compensation cost for these awards over a weighted-average period of 1.5 years.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Performance Share Unit Awards

An award granted as performance-based compensation is awarded to a participant contingent upon attainment of our future performance goals during a performance cycle. The performance goals were pre-established by the Compensation Committee. Following the end of the performance period, the holder of a performance-based compensation award is entitled to receive payment of an amount not exceeding the number of shares of common stock subject to, or the maximum value of, the performance-based compensation award, based on the achievement of the performance measures for the performance period. The performance share unit awards generally vest in full approximately three years after grant date, and are non-vested until the required service period expires.

The fair value of a performance share unit award is based on the market price per share of our common shares on the date of grant. Compensation expense is recognized based on the grant date fair value over the requisite service or vesting period. Compensation expense will be adjusted for the performance goals on a quarterly basis.

The following table presents performance share unit award activity for the periods indicated:


		Weighted-
		Average Grant
	Number of	Date Fair Value
	Shares	per Share ⁽¹⁾

Performance share unit awards at January 1, 2018	—	$	—
Granted ⁽²⁾	7,932	$	43.00
Performance factor decrease ⁽³⁾	(3,966)	$	43.00
Vested	—	$	—
Forfeited	—	$	—
Performance share unit awards at December 31, 2018	3,966	$	—

____________________

(1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.

(2) The aggregate grant date fair value of performance share unit awards issued during 2018 was $0.2 million based on a grant date market price of our common share of $43.00 per share and assuming a performance factor of 100 percent.

(3) The performance factor was lowered to 50 percent at the end of 2018 based upon a comparison of actual results to performance goals.

Unrecognized compensation cost associated with performance share unit awards was approximately $0.1 million at December 31, 2018. We expect to recognize the remaining compensation cost for these awards over a weighted-average period of 2.4 years.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note ~~12.~~14. Supplemental Cash Flow Information

Supplemental cash flows and non-cash transactions were as follows for the periods indicated (in thousands):


	Year Ended December 31,
	2018		2017		2016

Cash paid for interest	$	109	$	22	$	2
Cash paid for federal and state income taxes	787		459		2,589

Non-cash transactions:
Change in accounts payable related to property and equipment additions	1,685		70		679
Property and equipment acquired under capital leases	2,898		1,808		—

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
—
—

Note ~~13.~~15. Commitment and Contingencies

Capital Lease Obligations

During ~~the third quarter of~~ 2017 and 2018, we entered into capital leases for certain of our tractors in our crude oil marketing segment. The following table summarizes our principal contractual commitments outstanding under our capital leases at December 31, ~~2017~~2018 for the next five years, and in total thereafter (in thousands):


2018	$	398
2019	398			2019	$	1,052
2020	398			2020	1,052
2021	398			2021	1,052
2022	255			2022	909
2023				2023	451
Thereafter	—			Thereafter	—
Total minimum lease payments	1,847			Total minimum lease payments	4,516
Less: Amount representing interest	(158		)	Less: Amount representing interest	(424)
Present value of capital lease obligations	1,689			Present value of capital lease obligations	4,092
Less current portion of capital lease obligations	(338		)	Less current portion of capital lease obligations	(883)
Total long-term capital lease obligations	$	1,351		Total long-term capital lease obligations	$	3,209

Operating Lease Obligations

We lease certain property and equipment under ~~noncancellable~~noncancelable 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~~seven years.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Lease expense is charged to operating costs and expenses on a straight-line basis over the period of expected economic benefit. Contingent rental payments are expensed as incurred. We are generally required to perform routine maintenance on the underlying leased assets. Maintenance and repairs of leased assets resulting from our operations are charged to expense as incurred. Rental expense was as follows for the periods indicated (in thousands):


	Year Ended December 31,
	2018		2017		2016

Rental expense	$	11,078	$	12,073	$	11,314

Year Ended December 31,
2017 2016 2015

Rental expense $ 12,073
$ 11,314
$ 11,168

At December 31, ~~2017,~~2018, 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):


2019	$	4,242
2020	2,258
2021	2,107
2022	1,782
2023	1,495
Thereafter	1,488
Total operating lease payments	$	13,372

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~~are presented in the ~~dates indicated (in thousands):~~

December 31,
2017 2016

Pre-funded premiums for losses incurred but not reported $ 988
$ 2,657

table below. 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,~~The amount of pre-funded insurance premiums left to cover potential future losses and our ~~accrual~~accruals for automobile and workers’ compensation claims ~~was $0.5 million.~~were as follows at the dates indicated (in thousands):


	December 31,
	2018		2017

Pre-funded premiums for losses incurred but not reported	$	427	$	988
Accrued automobile and workers’ compensation claims	2,246		450

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~~$6.0 million. Medical accrual amounts were as follows at the dates indicated (in thousands):


	December 31,
	2018		2017

Accrued medical claims	$	1,181	$	1,329

December 31,
2017 2016

Accrued medical claims $ 1,329
$ 1,411

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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~~these obligations, the parent would first look to the assets of the defaulting subsidiary company.

At December 31, ~~2017,~~2018, parental guaranteed obligations were approximately ~~$48.2~~$22.3 million. Currently, neither AE nor any of its subsidiaries has any other types of guarantees outstanding that require liability recognition.

Note ~~14.~~16. 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.

~~Table of Contents~~

~~ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

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,~~companies, 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
Year Ended December 31,										December 31,
2018		2017		2016		2018		2017		2016

27.3	%	22.8	%	18.2	%	18.4	%	19.1	%	20.9	%
14.1	%	17.1	%	16.5	%	11.9	%	15.0	%	14.0	%
		10.8	%	15.9	%			11.1	%	10.1	%
		10.7	%	10.6	%			10.4	%

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 %

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note ~~15.~~17. 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, 2018
Revenues	$	387,256	$	452,417	$	467,891	$	442,649
Operating (losses) earnings ⁽¹⁾	1,077		4,298		2,239		(6,206)
Net (losses) earnings	1,138		3,620		2,035		(3,848)

Earnings (losses) per share:
Basic net (losses) earnings per share	$	0.27	$	0.86	$	0.48	$	(0.91)
Diluted net (losses) earnings per share	$	0.27	$	0.86	$	0.48	$	(0.91)

Year Ended December 31, 2017
Revenues	$	303,087	$	315,202	$	295,311	$	408,460
Operating (losses) earnings	(1,584)		619		(1,290)		3,757
Net (losses) earnings	(860)		(282)		(3,033)		3,693

Earnings (losses) per share:
Basic and diluted net (losses) earnings per share	$	(0.20)	$	(0.07)	$	(0.72)	$	0.88

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 )
____________________

(1) The fourth quarter of 2018 includes inventory valuation losses of approximately $7.9 million in our crude oil marketing segment.

~~Table of Contents~~

~~ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

Note ~~16.~~18. 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.~~Houston. As discussed further in Note 3,4, 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. There is no further exploration and development activity after April 30, 2017.

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
Property acquisition costs:
Unproved	$	4	$	32
Exploration costs:
Expensed	5		291
Development costs	1,815		—
Total costs incurred	$	1,824	$	323

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

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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
	Natural	Crude	Natural	Crude
	Gas	Oil	Gas	Oil
	(Mcf)	(Bbls)	(Mcf)	(Bbls)
Total proved reserves:
Beginning of year	4,214	187	4,835	226
Revisions of previous estimates	—	—	65	24
Crude oil and natural gas reserves sold	(4,067)	(170)	(175)	(4)
Extensions, discoveries and other reserve additions	42	6	151	18
Production	(189)	(23)	(662)	(77)
End of year	—	—	4,214	187

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
	Natural	Crude	Natural	Crude
	Gas	Oil	Gas	Oil
	(Mcf)	(Bbls)	(Mcf)	(Bbls)

Proved developed reserves	—	—	4,214	187
Proved undeveloped reserves	—	—	—	—
Total proved reserves	—	—	4,214	187

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.

Table of Contents

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.~~2016. 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

Future gross revenues	$	—	$	17,938
Future costs:
Lease operating expenses	—		(12,421)
Development costs	—		(38)
Future net cash flows before income taxes	—		5,479
Discount at 10% per annum	—		(2,002)
Discounted future net cash flows before income taxes	—		3,477
Future income taxes, net of discount at 10% per annum	—		(1,217)
Standardized measure of discounted future net cash flows	$	—	$	2,260

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~~these estimates, our independent petroleum engineers assumed market prices as ~~presented in~~follows for the ~~table below:~~periods indicated:


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

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

Table of Contents

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

These prices were based on the unweighted arithmetic average of the prices in effect on the first day of the month for each month of the respective twelve month periods as required by SEC regulations. The prices reported in the reserve disclosures for natural gas 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

Future net cash flows before income taxes	$	—	$	5,479
Future income taxes	—		(1,918)
Future net cash flows	—		3,561
Discount at 10% per annum	—		(1,301)
Standardized measure of discounted future net cash flows	$	—	$	2,260

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

Beginning of year	$	2,260	$	3,527
Sale of crude oil and natural gas reserves	(2,732)		(350)
Net change in prices and production costs	—		(1,391)
New field discoveries and extensions, net of future production costs	94		275
Sales of crude oil and natural gas produced, net of production costs	(476)		87
Net change due to revisions in quantity estimates	—		181
Accretion of discount	130		194
Production rate changes and other	(493)		(945)
Net change in income taxes	1,217		682
End of year	$	—	$	2,260

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

Revenues	$	1,427	$	3,410
Costs and expenses:
Production	(951)		(3,337)
Producing property impairment	—		(30)
Depreciation, depletion and amortization	(423)		(1,546)
Operating earnings (losses) before income taxes	53		(1,503)
Income tax benefit (expense)	(19)		526
Operating earnings (losses)	$	34	$	(977)

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 )

~~Table~~able of Contents


~~Item 9.~~	~~Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.~~

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

On June 7, 2017, we dismissed Deloitte & Touche, LLP (“Deloitte”) as our independent registered public accounting firm. There was no dispute or disagreement with the firm on any issue. On June 7, 2017, we appointed KPMG LLP as our new independent registered public accounting firm to perform independent audit services for the fiscal year ended December 31, 2017.

None.

Item 9A. Controls and Procedures.

Disclosure Controls and Procedures

As of the end of the period covered by this annual report, our management carried out an evaluation, with the participation of our Executive Chairman and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15(e) and 15d-15(e) of the Exchange Act. Based on this evaluation, as of the end of the period covered by this annual report, our Executive Chairman and our Chief Financial Officer concluded:

~~(i)~~

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

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


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

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

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) during the fourth quarter of ~~2017,~~2018, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL

OVER FINANCIAL REPORTING AS OF DECEMBER 31, ~~2017~~2018

Management of Adams Resources & Energy, Inc. and its consolidated subsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is a process designed under the supervision of our Executive Chairman and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States.

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

Management, including the Company’s Executive Chairman and Chief Financial Officer, assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, ~~2017.~~2018. In making this assessment, management used the criteria described in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on this assessment, management, including the Company’s Executive Chairman and Chief Financial Officer, concluded that internal control over financial reporting was effective as of December 31, ~~2017.~~2018.

~~Table of Contents~~

KPMG LLP has issued its attestation report regarding our internal control over financial reporting. That report is included within this Item 9A (See “Report of Independent Registered Public Accounting Firm”).

T able of Contents

Pursuant to the requirements of Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended, this annual report on Internal Control Over Financial Reporting has been signed below by the following persons on behalf of the registrant and in their respective capacities indicated below on March ~~12, 2018.~~8, 2019.



/s/ Townes G. Pressler						/s/ ~~Josh C. Anders~~Tracy E. Ohmart
Townes G. Pressler						~~Josh C. Anders~~Tracy E. Ohmart
Executive Chairman						Chief Financial Officer

~~REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM~~Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors

Adams Resources & Energy, Inc.:

Opinion on Internal Control Over Financial Reporting

We have audited Adams Resources & Energy, Inc.’s and ~~subsidiaries~~subsidiaries’ (the ~~“Company”)~~Company) internal control over financial reporting as of December 31, ~~2017,~~2018, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, ~~2017,~~2018, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance ~~sheet~~sheets of the Company as of December 31, 2018 and 2017, the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the ~~year~~years in the two-year period ended December 31, ~~2017,~~2018, and the related notes (collectively, the consolidated financial statements), and our report dated March ~~12, 2018~~8, 2019 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting as of December 31, ~~2017.~~2018. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

~~Table~~T able of Contents

Definition and Limitations of Internal Control Over Financial Reporting

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

/s/ KPMG LLP

Houston, Texas

March ~~12, 2018~~8, 2019

Item 9B. Other Information.

None.

PART III


~~Item 10.~~	~~Directors, Executive Officers and Corporate Governance.~~

Item 10. Directors, Executive Officers and Corporate Governance.

The information required by this item will be included in our definitive Proxy Statement in connection with our ~~2018~~2019 Annual Meeting of Shareholders (the ~~“2018~~“2019 Proxy Statement”), which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, ~~2017,~~2018, under the headings “Election of Directors” and “Executive Officers” and is incorporated herein by reference.


~~Item 11.~~	~~Executive Compensation.~~

Item 11. Executive Compensation.

The information required by this item will be set forth in our ~~2018~~2019 Proxy Statement, which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, ~~2017,~~2018, under the heading “Executive Compensation” and is incorporated herein by reference.


~~Item 12.~~	~~Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.~~

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The information required by this item will be set forth in our ~~2018~~2019 Proxy Statement, which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, ~~2017,~~2018, under the heading “Voting Securities and Principal Holders Thereof” and is incorporated herein by reference.

~~Table~~able of Contents


~~Item 13.~~	~~Certain Relationships and Related Transactions, and Director Independence.~~

Item 13. Certain Relationships and Related Transactions, and Director Independence.

The information required by this item will be set forth in our ~~2018~~2019 Proxy Statement, which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, ~~2017,~~2018, under the headings “Transactions with Related Parties” and “Director Independence” and is incorporated herein by reference.


~~Item 14.~~	~~Principal Accounting Fees and Services~~

Item 14. Principal Accounting Fees and Services

The information required by this item will be set forth in our ~~2018~~2019 Proxy Statement, which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, ~~2017,~~2018, under the heading “Principal Accounting Fees and Services” and is incorporated herein by reference.

PART IV


~~Item 15.~~	~~Exhibits, Financial Statement Schedules~~

Item 15. Exhibits, Financial Statement Schedules

(a) The following documents are filed as a part of this annual report:

(1) Financial Statements: See “Index to Consolidated Financial Statements” beginning on page 33 of this annual report for the financial statements included herein.

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

(3) Exhibits:


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


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


~~(3)~~	~~Exhibits:~~



Exhibit Number		Exhibit


	3.1		Certificate of Incorporation of Adams Resources & Energy, Inc., as amended (incorporated by reference to Exhibit 3(a) to Form 10-K for the year ended December 31, 1987).
	3.2	Bylaws of Adams Resources & Energy, Inc., as amended (incorporated by reference to Exhibit 3(b) to Form 10-K for the year ended December 31, 2012).
	3.3	Adams Resources & Energy, Inc. and Subsidiaries’ Code of Ethics (incorporated by reference to Exhibit 3(d) to Form 10-K for the year ended December 31, 2002).
4.1		Specimen common stock certificate (incorporated by reference to Exhibit 4(a) to Form 10-K for the fiscal year ended December 31, 1991).
	4.2	Credit and Security Agreement between ~~Gulfmark~~GulfMark Energy, Inc., Adams Resources Marketing, Ltd., and Wells Fargo Bank, National Association dated August 27, 2009 (incorporated by reference to Exhibit 4(b) to Quarterly Report on Form 10-Q for the period ended September 30, 2009).
	10.1+	Form of Indemnification Agreement for directors and executive officers (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed on May 15, 2015).
	10.2+	Retirement Agreement, dated February 26, 2015, by and between Adams Resources Energy, Inc. and Frank T. “Chip” Webster (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed on February 26, 2015).
	~~10.3~~10.3*	First Amendment to Credit and Secu rity Agreement dated as of June 23, 2011 between GulfMark Energy, Inc., Adams Resources Marketing, Ltd., and Wells Fargo Bank, National Association.

T able of Contents


Exhibit Number			Exhibit

10.4*			Second Amendment to Credit and Security Agreement dated as of J anuary 1 3, 201 2 between GulfMark Energy, Inc., Adams Resources Marketing, Ltd., and Wells Fargo Bank, National Association.
10.5*			Third Amendment to Credit and Security Agreement dated as of August 13 , 201 3 between GulfMark Energy, Inc., Adams Resources Marketing, Ltd., and Wells Fargo Bank, National Association.
10.6*			Fourth Amendment to Credit and Security Agreement dated as of November 16 , 201 5 between GulfMark Energy, Inc., Adams Resources Marketing, Ltd., and Wells Fargo Bank, National Association.
10.7*			F ifth Amendment to Credit and Security Agreement dated as of August 31 , 201 7 between GulfMark Energy, Inc., and Wells Fargo Bank, National Association.
10.8			Sixth Amendment to Credit and Security Agreement dated as of September 28, 2017 between ~~Gulfmark~~Gulf M ark Energy, Inc., and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q for the period ended September 30, 2017).

~~Table of Contents~~


10.9					Seventh Amendment to Credit and Security Agreement dated as of March 19, 2018 between GulfMark Energy, Inc. and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 10.2 to Quarterly Report on Form 10-Q for the period ended March 31, 2018).
10.10			~~Exhibit~~ ~~Number~~		~~Exhibit~~

	10.4*	Debtor in Possession Credit and Security Agreement dated as of April 25, 2017 by and among Adams Resources Exploration Corporation, as Borrower, and Adams Resources & Energy, Inc., as ~~Lender.~~Lender (incorporated by reference to Exhibit 10.4 to Form 10-K for the year ended December 31, 2017).
10.11+			Adams Resources & Energy, Inc. 2018 Long-Term Incentive Plan, effective as of May 8, 2018 (incorporated by reference to Exhibit 10.1 to Quarterly Report Form 10-Q for the period ended March 31, 2018).
10.12+			Form of Director Restricted Stock Unit Award Agreement under the Adams Resources & Energy, Inc. 2018 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q for the period ended June 30, 2018).
10.13+			Form of Employee Restricted Stock Unit Award Agreement under the Adams Resources & Energy, Inc. 2018 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Quarterly Report on Form 10-Q for the period ended June 30, 2018).
10.14+			Form of Employee Performance Share Unit Award Agreement under the Adams Resources & Energy, Inc. 2018 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to Quarterly Report on Form 10-Q for the period ended June 30, 2018).
10.15			Purchase and Sale Agreement by and between ARB Oklahoma Holdings, LLC as Seller and GulfMark Energy, Inc. as Buyer, dated as of August 15, 2018 (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q for the period ended September 30, 2018).
21*			Subsidiaries of the registrant.
			23.1*	Consent of KPMG LLP .
23.2*			Consent of De loitte & Touche LLP.
23.3*			Consent of Ryder Scott Company.
			31.1*	Sarbanes-Oxley Section 302 Certification of Chief Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
			31.2*	Sarbanes-Oxley Section 302 Certification of Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
			32.1*	Sarbanes-Oxley Section 906 Certification of Chief Executive Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
			32.2*	Sarbanes-Oxley Section 906 Certification of Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

T able of Contents


Exhibit Number		Exhibit

99.1		Ryder Scott Company Report as of December 31, 2016 (incorporated by reference to Exhibit 99.1 to Annual Report on Form 10-K for the year ended December 31, 2016).
	101.CAL*		XBRL Calculation Linkbase Document
		101.DEF*	XBRL Definition Linkbase Document
		101.INS*	XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
	101.LAB*		XBRL Labels Linkbase Document
		101.PRE*	XBRL Presentation Linkbase Document
	101.SCH*		XBRL Schema Document

* Filed for furnished (in the case of Exhibits 32.1 and 32.2) with this report.

+ Management contract or compensation plan or arrangement.


~~Item 16.~~	~~Form 10-K Summary~~

Item 16. Form 10-K Summary

Not applicable.

~~Table~~able of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on March ~~12, 2018.~~8, 2019.



						ADAMS RESOURCES & ENERGY, INC.
						(Registrant)


			By:			/s/ Townes G. Pressler
						Townes G. Pressler
						Executive Chairman
						(Principal Executive Officer)

			By:			/s/ ~~Josh C. Anders~~Tracy E. Ohmart
						~~Josh C. Anders~~Tracy E. Ohmart
						Chief Financial Officer
						(Principal Financial Officer and Principal
						Accounting Officer)

~~Table~~T able of Contents

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated below on March ~~12, 2018.~~8, 2019.


Signature		Title

~~Signature~~	~~Title~~

/s/ Townes G. Pressler	Director and ~~Executive~~ Chairman of the Board
Townes G. Pressler
~~/s/ Larry E. Bell~~	~~Director~~
~~Larry E. Bell~~
/s/ Murray E. Brasseux	Director
Murray E. Brasseux
/s/ Michelle A. Earley		Director
Michelle A. Earley
/s/ Richard C. Jenner		Director
Richard C. Jenner
~~/s/ E.C. Reinauer, Jr.~~	~~Director~~
~~E.C. Reinauer, Jr.~~
/s/ W.R. Scofield	Director
W.R. Scofield



Title of Each Class			Name of Each Exchange On Which Registered
Common Stock, $0.10 Par Value			NYSE ~~MKT~~American LLC


					Year Ended December 31,
	Year Ended December 31,				2018	2017	2016
	2017	2016	2015

New truck-tractors purchased	—	30 units	60 units
Truck-tractors retired	21 units	—	—
New tractors purchased				New tractors purchased	60 units	—	30 units
Tractors retired				Tractors retired	67 units	21 units	—
New trailers purchased	—	54 units	12 units	New trailers purchased	—	—	54 units
Trailers retired	—	50 units	—	Trailers retired	12 units	—	50 units


	Year Ended December 31,
	2017		2016

Crude oil:
Volume – barrels ⁽¹⁾	11,643		34,200
Average price per barrel	$	49.44	$	38.07

Natural gas:
Volume – Mcf ⁽¹⁾	189,488		662,000
Average price per Mcf	$	2.86	$	2.26

Natural gas liquids:
Volume – barrels ⁽¹⁾	11,204		42,500
Average price per barrel	$	26.77	$	14.39



	Year Ended December 31,
	2017		2016		2015

Crude oil
Volume – barrels ⁽¹⁾	11,643		34,200		50,000
Average price per barrel	$	49.44	$	38.07	$	46.51

Natural gas
Volume – Mcf ⁽¹⁾	189,488		662,000		889,000
Average price per Mcf	$	2.86	$	2.26	$	2.46

Natural gas liquids
Volume – barrels ⁽¹⁾	11,204		42,500		42,100
Average price per barrel	$	26.77	$	14.39	$	12.70


	December 31,
	2018		2017		2016

Early payments received	$	38,539	$	20,078	$	15,032


Early payments to suppliers	—		6,100		14,382


	Tractors ⁽¹⁾	Trailers		Tractors ^{(1) (2)}	Trailers ⁽²⁾

Model Year:			Model Year:
2019			2019	24	—
2018	16	—	2018	15	—
2017	4	—	2017	4	—
2015	19	3	2015	86	29
2014	39	23	2014	37	34
2013	59	41	2013	41	41
2012	7	14	2012	25	31
2011	—	75	2011	23	112
2008 and earlier	—	45
2010 and earlier			2010 and earlier	—	69
Total	144	201	Total	255	316


~~(1)~~	~~Includes 15 tractors that we lease from a third party under a capital lease agreement. See Note 13 in the Notes to Consolidated Financial Statements for further information.~~


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



			Cash Dividend History
	Price Ranges		Per	Record	Payment
	High	Low	Share	Date	Date
2015
1st Quarter	$73.28	$47.31	$0.22	6/3/2015	6/17/2015
2nd Quarter	$70.00	$39.00	$0.22	9/3/2015	9/17/2015
3rd Quarter	$48.60	$38.88	$0.22	12/2/2015	12/16/2015
4th Quarter	$46.86	$33.55	$0.22	3/11/2016	3/23/2016

2016
1st Quarter	$43.00	$30.00	$0.22	6/3/2016	6/17/2016
2nd Quarter	$44.27	$35.25	$0.22	9/6/2016	9/19/2016
3rd Quarter	$39.47	$29.64	$0.22	12/5/2016	12/19/2016
4th Quarter	$44.00	$35.17	$0.22	3/10/2017	3/24/2017

2017
1st Quarter	$41.99	$34.23	$0.22	6/2/2017	6/16/2017
2nd Quarter	$43.80	$35.64	$0.22	9/6/2017	9/20/2017
3rd Quarter	$42.77	$32.80	$0.22	12/5/2017	12/19/2017
4th Quarter	$50.59	$40.36	$0.22	3/9/2018	3/23/2018


~~(1)~~	(1) Revenues, net of fuel cost, is a non-GAAP financial measure and is utilized for internal analysis of the results of our transportation segment.


~~(2)~~	~~Results for 2017 represents amounts for the period from January 1, 2017 through April 30, 2017.~~


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


~~(1)~~	~~Our marketing segment amount for 2017 does not include approximately $1.8 million of tractors acquired under capital leases.~~


														Payments due by period
			Payments due by period
	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Contractual Obligations											Contractual Obligations	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years

Capital lease obligations ⁽¹⁾	$	1,847	$	398	$	796	$	653	$	—	Capital lease obligations ⁽¹⁾	$	4,516	$	1,052	$	2,104	$	1,360	$	—
Operating lease obligations ⁽²⁾	3,407		2,758		531		95		23		Operating lease obligations ⁽²⁾	13,372		4,242		4,365		3,277		1,488
Purchase obligations ⁽³⁾	123,238		123,238		—		—		—
Purchase obligations:											Purchase obligations:
Crude oil marketing ⁽³⁾											Crude oil marketing ⁽³⁾	106,706		106,706		—		—		—
Transportation ⁽⁴⁾											Transportation ⁽⁴⁾	6,805		6,805		—		—		—
Total contractual obligations	$	128,492	$	126,394	$	1,327	$	748	$	23	Total contractual obligations	$	131,399	$	118,805	$	6,469	$	4,637	$	1,488


~~(1)~~	(1) Amounts represent our principal contractual commitments, including interest, outstanding under capital leases ~~we entered into during 2017~~ for certain tractors ~~in our marketing segment.~~


~~(1)~~	~~Excludes 35 independent contractor tractors.~~


~~(2)~~	~~Amounts represent rental obligations under non-cancelable operating leases and terminal arrangements with terms in excess of one year.~~


~~(3)~~	Amount represents commitments to purchase certain quantities of crude oil substantially in January 2018 in connection with our crude oil marketing activities. These commodity purchase obligations are the basis for commodity sales, which generate the cash flow necessary to meet such purchase obligations.



	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		$	—