ADAMS RESOURCES & ENERGY, INC. - Annual Report: 2019 (Form 10-K)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2019

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___ to ___.

Commission file number: 1-7908

ADAMS RESOURCES & ENERGY, INC.

(Exact name of Registrant as Specified in Its Charter)

Delaware

74-1753147

(State or Other Jurisdiction of

Incorporation or Organization)

(I.R.S. Employer Identification No.)

17 SOUTH BRIAR HOLLOW LANE, SUITE 100, HOUSTON, Texas 77027

(Address of Principal Executive Offices) (Zip Code)

(713) 881-3600

(Registrant’s Telephone Number, Including Area Code)

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Stock, $0.10 Par Value

NYSE American LLC

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o Accelerated filer þ Non-accelerated filer o Smaller reporting company ☑ Emerging growth company ☐

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No þ

The aggregate market value of the Company’s voting and non-voting common shares held by non-affiliates as of the close of business on June 28, 2019 was $74,219,902 based on the closing price of $34.28 per one share of common stock as reported on the NYSE American LLC for such date. There were 4,235,533 shares of Common Stock outstanding at March 2, 2020.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Shareholders to be held May 6, 2020 are incorporated by reference into Part III of this annual report on Form 10-K.

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ADAMS RESOURCES & ENERGY, INC.

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Page

Number

PART I

Item 1 and 2.

Business and Properties.

Item 1A.

Risk Factors.

Item 1B.

Unresolved Staff Comments.

Item 3.

Legal Proceedings.

Item 4.

Mine Safety Disclosures.

PART II

Item 5.

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

Item 6.

Selected Financial Data.

Item 7.

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

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk.

Item 8.

Financial Statements and Supplementary Data.

Item 9.

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

Item 9A.

Controls and Procedures.

Directors, Executive Officers and Corporate Governance.

Item 11.

Executive Compensation.

Item 12.

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

Item 13.

Certain Relationships and Related Transactions, and Director Independence.

Item 14.

Principal Account ing Fees and Services.

PART IV

Item 15.

Exhibits, Financial Statement Schedules.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This annual report on Form 10-K for the year ended December 31, 2019 (our “annual report”) contains various forward-looking statements and information that are based on our beliefs, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “would,” “will,” “believe,” “may,” “potential” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements. Although we believe that our expectations reflected in such forward-looking statements are reasonable, we cannot give any assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions as described in more detail under Part I, Item 1A of this annual report. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements. The forward-looking statements in this annual report speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.

PART I

Items 1 and 2. Business and Properties.

General

Adams Resources & Energy, Inc. (“AE”) is a publicly traded Delaware corporation organized in 1973, the common shares of which are listed on the NYSE American LLC (“NYSE American”) under the ticker symbol “AE”. We, 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 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. Our headquarters are located in 27,932 square feet of office space located at 17 South Briar Hollow Lane, Suite 100, Houston, Texas 77027, and the telephone number of that address is (713) 881-3600. 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.

We operate and report in two business segments: (i) crude oil marketing, transportation and storage, and (ii) tank truck transportation of liquid chemicals and dry 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.

For detailed financial information regarding our business segments, see Note 10 in the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

2019 Developments

Asset Acquisition

On May 6, 2019, we completed the purchase of the assets of EH Transport, Inc. and affiliates (collectively, “EH Transport”), a Houston, Texas based bulk carrier trucking company, for approximately $6.4 million. This acquisition added approximately 39 tractors and 51 trailers to our existing transportation fleet, and is included in our transportation segment. See Note 7 in the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for further information.

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Business Segments

Crude Oil Marketing

Our crude oil marketing segment consists of the operations of our wholly owned subsidiary, GulfMark Energy, Inc. (“GulfMark”). Our crude oil marketing activities generate revenue from the sale and delivery of crude oil purchased either directly from producers or from others on the open market. We also derive revenue from third party transportation contracts. We purchase crude oil and arrange sales and deliveries to refiners and other customers, primarily onshore in Texas, Oklahoma, North Dakota, Michigan and Louisiana.

Our crude oil marketing activities includes a fleet of 256 tractor-trailer rigs, the majority of which we own and operate, used to transport crude oil. We also maintain approximately 179 pipeline inventory locations or injection stations. We have the ability to barge crude oil from four crude oil storage facilities along the Intercoastal Waterway of Texas and Louisiana, and we have access to approximately 691,000 barrels of storage capacity at the dock facilities in order to access waterborne markets for our products.

The following table shows the age of our owned and leased tractors and trailers within our crude oil marketing segment at December 31, 2019:


	Tractors ⁽¹⁾	Trailers

Model Year:
2020	35	—
2019	38	—
2018	15	—
2017	4	—
2015	85	29
2014	29	34
2013	26	39
2012	17	31
2011	7	110
2010 and earlier	—	69
Total	256	312

____________________

(1)Includes thirty 2019 tractors and fifteen 2018 tractors that we lease from a third party under a finance lease agreement. See Note 16 in the Notes to Consolidated Financial Statements for further information.

We purchase crude oil at the field (wellhead) level. Volume and price information were as follows for the periods indicated:


	Year Ended December 31,
	2019		2018		2017
Field level purchase volumes – per day ^{(1) (2)}
Crude oil – barrels	107,383		79,361		67,447

Average purchase price
Crude oil – per barrel	$	56.28	$	64.53	$	49.88

____________________

(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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Field level purchase volumes depict our day-to-day operations of acquiring crude oil at the wellhead, transporting crude oil, and delivering it to market sales points. We held crude oil inventory at a weighted average composite price as follows at the dates indicated (in barrels):


	December 31,
	2019				2018					2017
		Average			Average			Average
	Barrels	Price		Barrels	Price		Barrels	Price

Crude oil inventory	426,397	$	61.93	415,523	$	54.82	198,011	$	61.57

We deliver physical supplies to refinery customers or enter into commodity exchange transactions from time to time to protect from a decline in inventory valuation. During the year ended December 31, 2019, we had sales to two customers that comprised approximately 37.3 percent and 11.4 percent, respectively, of total consolidated revenues. We believe alternative market outlets for our commodity sales are readily available and a loss of any of these customers would not have a material adverse effect on our operations. See Note 18 in the Notes to Consolidated Financial Statements for further information regarding credit risk.

Operating results for our crude oil marketing segment are sensitive to a number of factors. These factors include commodity location, grades of product, individual customer demand for grades or location of product, localized market price structures, availability of transportation facilities, actual delivery volumes that vary from expected quantities, and the timing and costs to deliver the commodity to the customer.

Transportation

Our transportation segment consists of the operations of our wholly owned subsidiary, Service Transport Company (“STC”). STC transports liquid chemicals and, to a lesser extent, dry bulk on a “for hire” basis throughout the continental U.S., and into Canada and Mexico. We do not own any of the products that we haul; rather we act as a third party carrier to deliver our customers’ products from point A to point B, using predominately our employees and our owned tractors and trailers. However, we also use contracted independent owner operators to provide transportation services. Transportation services are provided to customers under multiple load contracts in addition to loads covered under STC’s standard price list. Our customers include major oil and chemical companies and large and mid-sized industrial companies.

On May 6, 2019, we completed the EH Transport asset acquisition, which added new customers and new product lines to our transportation segment portfolio. As a result of the acquisition, in addition to general chemical products, we haul liquefied petroleum gas, asphalt and bleach for customers.

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The following table shows the age of our owned and leased tractors and trailers within our transportation segment at December 31, 2019:


	Tractors ^{(1) (2)}	Trailers ⁽²⁾

Model Year:
2020	128	70
2019	82	—
2018	1	—
2016	29	6
2015	20	76
2014	1	35
2013	18	—
2012	—	30
2011	2	—
2008 and earlier	—	390
Total	281	607

____________________

(1)Excludes 61 contracted independent owner operator tractors.

(2)In May 2019, we acquired 39 tractors and 51 trailers in connection with our EH Transport acquisition. Of the 39 tractors purchased as part of the acquisition, 35 tractors were sold through December 31, 2019, and as such, are not included in the numbers of units noted in the table.

Miles traveled was as follows for the periods indicated (in thousands):


	Year Ended December 31,
	2019	2018	2017

Mileage	20,535	19,177	21,836

During 2019, STC opened a truck terminal in Charlotte, North Carolina as a result of customer demand. STC also operates truck terminals in Houston, Corpus Christi, Nederland and Freeport, Texas; in Baton Rouge (St. Gabriel), St. Rose and Boutte, Louisiana; and in Mobile (Saraland), Alabama. Transportation operations are headquartered at a terminal facility situated on 26.5 acres that we own in Houston, Texas. This property includes maintenance facilities, administrative offices and terminal facility, tank wash rack facilities and a water treatment system. The St. Gabriel, Louisiana and the Corpus Christi, Texas terminals are situated on 11.5 acres and 3.5 acres, respectively, that we own, and both include an office building, maintenance bays and tank cleaning facilities. Pursuant to regulatory requirements, STC holds a Hazardous Materials Certificate of Registration issued by the U.S. Department of Transportation (“DOT”).

STC is a recognized certified partner with the American Chemistry Council’s Responsible Care Management System (“RCMS”). The scope of this RCMS certification covers the carriage of bulk liquids throughout STC’s area of operations as well as the tank trailer cleaning facilities and equipment maintenance. STC’s quality management process is one of its major assets. The practice of using statistical process control covering safety, on-time performance and customer satisfaction aids continuous improvement in all areas of quality service. Certified RCMS partners serve the chemical industry and implement and monitor the seven Codes of Management Practices. The seven codes address compliance and continuing improvement in (1) Community Awareness and Emergency Response, (2) Pollution Prevention, (3) Process Safety, (4) Distribution, (5) Employee Health and Safety, (6) Product Stewardship, and (7) Security.

STC is a Charter Partner in the EPA’s SmartWay Transport Partnership, a national voluntary program developed by the EPA and freight industry representatives to reduce greenhouse gasses and air pollution and promote cleaner, more efficient ground freight transportation.

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Our strategy is to build long-term relationships with our customers based upon the highest level of customer service, safety and reliability. We believe that our commitment to safety, flexibility, size and capabilities provide us with a competitive advantage over other carriers.

Investment in Unconsolidated Affiliates

We own an approximate 15 percent equity interest (less than 3 percent voting interest) in VestaCare, Inc., a California corporation (“VestaCare”), through Adams Resources Medical Management, Inc. (“ARMM”), a wholly owned subsidiary. We acquired our interest in VestaCare in April 2016 for a $2.5 million cash payment, which we impaired during the third quarter of 2017. 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 do not currently have any plans to pursue additional medical-related investments. See Note 9 in the Notes to Consolidated Financial Statements for further information.

Competition

In all phases of our operations, we encounter strong competition from a number of entities. Many of these competitors possess financial resources substantially in excess of ours and may have a more expansive geographic footprint than we have. We face competition principally in establishing trade credit, pricing of available materials, quality of service and location of service. Our strategy is to build long-term partnerships with our customers based upon the safety of our operations, reliability and superior customer service.

Our crude oil marketing segment competes with major crude oil companies and other large industrial concerns that own or control significant refining, midstream and marketing facilities. These major crude oil companies may offer their products to others on more favorable terms than those available to us.

In the trucking industry, the tank lines transportation business is extremely competitive and fragmented. Price, service and location are the major competitive factors in each local market.

Seasonality

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

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

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Regulatory Matters

We are subject to an extensive variety of evolving federal, state and local laws, rules and regulations governing the storage, transportation, manufacture, use, discharge, release and disposal of product and contaminants into the environment, or otherwise relating to the protection of the environment. Below is a non-exclusive listing of the environmental laws that potentially impact our business.

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

•The Clean Water Act of 1972, as amended.

•The Clean Air Act of 1970, as amended.

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

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

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

•Texas Clean Air Act.

•Texas Solid Waste Disposal Act.

•Texas Water Code.

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

Railroad Commission of Texas (“RRC”)

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

Louisiana Office of Conservation

The Louisiana Office of Conservation has primary statutory responsibility for regulation and conservation of crude oil, natural gas, and other natural resources in the State of Louisiana. Their objectives are to (i) regulate the exploration and production of crude oil, natural gas and other hydrocarbons, (ii) control and allocate energy supplies and distribution thereof, and (iii) protect public safety and the environment from oilfield waste, including the regulation of underground injection and disposal practices.

State and Local Government Regulation

Many states are authorized by the U.S. Environmental Protection Agency (“EPA”) to enforce regulations promulgated under various federal statutes. In addition, there are numerous other state and local authorities that regulate the environment, some of which impose more stringent environmental standards than federal laws and regulations. The penalties for violations of state law vary, but typically include injunctive relief and recovery of damages for injury to air, water or property as well as fines for non-compliance.

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Trucking Activities

Our crude oil marketing and transportation businesses operate truck fleets pursuant to the authority of the DOT and various state authorities. Trucking operations must be conducted in accordance with various laws relating to pollution and environmental control as well as safety requirements prescribed by states and by the DOT. Matters such as weight and dimension of equipment are also subject to federal and state regulations. These regulations also require mandatory drug testing of drivers and require certain tests for alcohol levels in drivers and other safety personnel. The trucking industry is subject to possible regulatory and legislative changes, such as increasingly stringent environmental requirements or limits on vehicle weight and size. Regulatory change may affect the economics of the industry by requiring changes in operating practices or by changing the demand for private and common or contract carrier services or the cost of providing truckload services. In addition, our tank wash facilities are subject to increasingly stringent local, state and federal environmental regulations.

We have implemented security procedures for drivers and terminal facilities. Satellite tracking transponders installed in the power units are used to communicate emergencies to us and to maintain constant information as to the unit’s location. If necessary, our terminal personnel will notify local law enforcement agencies. In addition, we are able to advise a customer of the status and location of their loads. Remote cameras and enhanced lighting coverage in the staging and parking areas have augmented terminal security. We have a focus on safety in the communities in which we operate, including leveraging camera technology to enhance driver behavior and awareness. Our crude oil marketing and transportation businesses are Charter Partners in the EPA’s SmartWay Transport Partnership, a national voluntary program developed by the EPA and freight industry representatives to reduce greenhouse gasses and air pollution and promote cleaner, more efficient ground freight transportation.

Regulatory Status and Potential Environmental Liability

Our operations and facilities are subject to numerous federal, state and local environmental laws and regulations including those described above, as well as associated permitting and licensing requirements. We regard compliance with applicable environmental regulations as a critical component of our overall operation, and devote significant attention to providing quality service and products to our customers, protecting the health and safety of our employees, and protecting our facilities from damage. We believe we have obtained or applied for all permits and approvals required under existing environmental laws and regulations to operate our current business. We are not subject to any pending or threatened environmental litigation or enforcement actions which could materially and adversely affect our business.

We have, where appropriate, implemented operating procedures at each of our facilities designed to assure compliance with environmental laws and regulation. However, given the nature of our business, we are subject to environmental risks, and the possibility remains that our ownership of our facilities and our operations and activities could result in civil or criminal enforcement and public as well as private actions against us, which may necessitate or generate mandatory cleanup activities, revocation of required permits or licenses, denial of application for future permits, and/or significant fines, penalties or damages, any and all of which could have a material adverse effect on us. See “Item 1A. Risk Factors” for further discussion. At December 31, 2019, we are not aware of any unresolved environmental issues for which additional accounting accruals are necessary.

Employees

At December 31, 2019, we employed 664 persons. None of our employees are represented by a union. We believe our employee relations are satisfactory.

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Federal and State Taxation

We are subject to the provisions of the Internal Revenue Code of 1986, as amended (the “Code”). In accordance with the Code, we computed our income tax provision based on a 21 percent tax rate for the year ended December 31, 2019. We conduct a significant amount of business within the State of Texas. Texas operations are subject to a one-half percent state tax on its revenues net of cost of goods sold as defined by the state. We believe we are currently in compliance with all federal and state tax regulations.

Available Information

We electronically file certain documents with the U.S. Securities and Exchange Commission (“SEC”). We file Annual Reports on Form 10-K; Quarterly Reports on Form 10-Q; and Current Reports on Form 8-K (as appropriate); along with any related amendments and supplements thereto.

We also make available free of charge our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, simultaneously with or as soon as reasonably practicable after filing such materials with, or furnishing such materials to, the SEC, and on our website www.adamsresources.com. The information on our website, or information about us on any other website, is not incorporated by reference into this report.

Item 1A. Risk Factors.

An investment in our common stock involves certain risks. If any of the following key risks were to occur, it could have a material adverse effect on our financial position, results of operations and cash flows. In any such circumstance and others described below, the trading price of our securities could decline and you could lose part or all of your investment.

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

Potential disruptions in the credit markets and concerns about global economic growth could have a significant adverse impact on global financial markets and commodity prices. These factors could contribute to a decline in our stock price and corresponding market capitalization. If commodity prices experience a period of rapid decline, or a prolonged period of low commodity prices, our future earnings will be reduced. We currently do not have bank debt obligations. If the capital and credit markets experience volatility and the availability of funds become limited, our customers and suppliers may incur increased costs associated with issuing commercial paper and/or other debt instruments and this, in turn, could adversely affect our ability to secure supply and make profitable sales.

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

Customer demand for our products and services is substantially dependent upon the general economic conditions for the U.S., which are cyclical in nature. In particular, demand for liquid chemical truck transportation services is dependent on activity within the petrochemical sector of the U.S. economy. Chemical sector demand typically varies with the housing and auto markets as well as the relative strength of the U.S. dollar to foreign currencies. A relatively strong U.S. dollar exchange rate may be adverse to our transportation operation since it tends to suppress export demand for petrochemicals. Conversely, a weak U.S. dollar exchange rate tends to stimulate export demand for petrochemicals.

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Difficulty in attracting and retaining drivers could negatively affect our operations and limit our growth.

There is substantial competition for qualified personnel, particularly drivers, in the trucking industry. We operate in geographic areas where there is currently a shortage of drivers. Regulatory requirements, including electronic logging, and an improving U.S. jobs market, could continue to reduce the number of eligible drivers in our markets. Any shortage of drivers could result in temporary under-utilization of our equipment, difficulty in meeting our customers’ demands and increased compensation levels, each of which could have a material adverse effect on our business, results of operations and financial condition. A loss of qualified drivers could lead to an increased frequency in the number of accidents, potential claims exposure and, indirectly, insurance costs.

Difficulty in attracting qualified drivers could also require us to limit our growth. Our strategy is to grow in part by expanding existing customer relationships into new markets. However, we may have difficulty finding qualified drivers on a timely basis when presented with new customer opportunities, which could result in our inability to accept or service this business or could require us to increase the wages we pay in order to attract drivers. If we are unable to hire qualified drivers to service business opportunities in new markets, we may have to temporarily send drivers from existing terminals to those new markets, causing us to incur significant costs relating to out-of-town driver pay and expenses. In making acquisitions and converting private fleets, some of the drivers in those fleets may not meet our standards, which would require us to find qualified drivers to replace them. If we are unable to find and retain such qualified drivers on terms acceptable to us, we may be forced to forego opportunities to expand or maintain our business.

Our business is dependent on the ability to obtain trade and other credit.

Our future development and growth depends, in part, on our ability to successfully obtain credit from suppliers and other parties. Trade credit arrangements are relied upon as a significant source of liquidity for capital requirements not satisfied by operating cash flow. If global financial markets and economic conditions disrupt and reduce stability in general, and the solvency of creditors specifically, the availability of funding from credit markets, would be reduced as many lenders and institutional investors would enact tighter lending standards, refuse to refinance existing debt on terms similar to current debt or, in some cases, cease to provide funding to borrowers. These issues coupled with weak economic conditions would make it more difficult for us, our suppliers and our customers to obtain funding. If we are unable to obtain trade or other forms of credit on reasonable and competitive terms, the ability to continue our marketing businesses, pursue improvements, and continue future growth will be limited. We cannot assure you that we will be able to maintain future credit arrangements on commercially reasonable terms.

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

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

•supply and demand for crude oil and expectations regarding supply and demand;

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

•economic conditions in the U.S. and worldwide;

•the impact of public health epidemics, like the coronavirus outbreak beginning in 2020 impacting China and other areas;

•governmental regulations and taxation;

•the impact of energy conservation efforts;

•the price and availability of alternative fuel sources;

•weather conditions;

•availability of local, interstate and intrastate transportation systems; and

•market uncertainty.

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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 540 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.

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 rarely 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 transportation and waste management. Compliance with environmental laws and regulations can require significant costs or may require a decrease in 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.

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.

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 we 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. The EPA later proposed in June 2017 to stay the rules for two years. Both the stay and the underlying rules have been the subject of litigation. In September 2018, the EPA proposed revisions to the 2016 rules. Regarding existing sources in the crude oil and natural gas section, the EPA announced in March 2016 that it intended to develop rules to reduce methane emissions for existing sources, 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, which the 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 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 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 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, the techniques used to obtain unauthorized access change frequently and can be difficult to 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 17 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 Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Our common stock is traded on the NYSE American under the ticker symbol “AE”. As of March 2, 2020, there were approximately 127 shareholders of record of our common shares. We have paid dividends to our common shareholders each year since 1994. Our Board of Directors expects to continue paying dividends in the near future, although the declaration, amount and timing of any dividends falls within the sole discretion of our Board, whose decision will depend on many factors, including our financial condition, earnings, capital requirements and other factors that our Board may deem relevant.

Unregistered Sales of Securities

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 (“S&P Integrated Oil & Gas”). The graph assumes that $100 was invested in our common stock and each comparison index beginning on December 31, 2014 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.

The information under the caption “Performance Graph” above is not deemed to be “filed” as part of the Annual Report on Form 10-K, and is not subject to the liability provisions of Section 18 of the Exchange Act. Such information will not be deemed incorporated by reference into any filing we make under the Securities Act unless we explicitly incorporate it into such filing at such time.


	December 31,
	2014		2015		2016		2017		2018		2019

Adams Resources & Energy, Inc.	$	100.00	$	78.31	$	82.79	$	92.88	$	84.37	$	85.34
S&P 500	100.00		101.38		113.51		138.29		132.23		173.86
S&P Integrated Oil & Gas	100.00		86.14		106.94		109.16		95.00		101.84

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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, 2019 and 2018 and related consolidated statements of operations, cash flows and shareholders’ equity for the three years ended December 31, 2019, 2018 and 2017, respectively. As presented in the table, amounts are in thousands (except per share data).


	Year Ended December 31,
	2019		2018		2017		2016		2015
Statements of operations data:
Revenues:
Marketing	$	1,748,056	$	1,694,437	$	1,267,275	$	1,043,775	$	1,875,885
Transportation	63,191		55,776		53,358		52,355		63,331
Oil and natural gas ⁽¹⁾	—		—		1,427		3,410		5,063
Total revenues	1,811,247		1,750,213		1,322,060		1,099,540		1,944,279

Costs and expenses:
Marketing	1,723,216		1,681,045		1,247,763		1,016,733		1,841,893
Transportation	53,392		48,169		48,538		45,154		52,076
Oil and natural gas ⁽¹⁾	—		—		948		2,084		6,931
Oil and natural gas property impairments ⁽²⁾	—		—		3		313		12,082
General and administrative	10,198		8,937		9,707		10,410		9,939
Depreciation, depletion and amortization	16,641		10,654		13,599		18,792		23,717

Operating earnings (losses)	7,800		1,408		1,502		6,054		(2,359)

Loss on deconsolidation of subsidiary ⁽¹⁾	—		—		(3,505)		—		—
Impairment of investment in unconsolidated
affiliate ⁽³⁾	—		—		(2,500)		—		—
Gain on dissolution of investment ⁽⁴⁾	573		—		—		—		—
Interest income (expense), net	2,130		2,046		1,076		580		314

Earnings (losses) from continuing operations	10,503		3,454		(3,427)		6,634		(2,045)

Income tax (provision) benefit	(2,296)		(509)		2,945		(2,691)		770

Earnings (losses) before investment in
unconsolidated affiliate	8,207		2,945		(482)		3,943		(1,275)

Losses from investment in unconsolidated
affiliate, net of tax ⁽⁵⁾	—		—		—		(1,430)		—
Net (losses) earnings	$	8,207	$	2,945	$	(482)	$	2,513	$	(1,275)

Earnings (losses) per share:
From continuing operations	$	1.94	$	0.70	$	(0.11)	$	0.94	$	(0.30)
From investment in unconsolidated
affiliate	—		—		—		(0.34)		—
Basic and diluted earnings (losses)
per share	$	1.94	$	0.70	$	(0.11)	$	0.60	$	(0.30)

Dividends per common share	$	0.94	$	0.88	$	0.88	$	0.88	$	0.88

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	December 31,
	2019		2018		2017		2016		2015
Balance sheet data:
Cash and cash equivalents	$	112,994	$	117,066	$	109,393	$	87,342	$	91,877
Total assets	330,842		278,870		282,704		246,872		243,215
Long-term debt	—		—		—		—		—
Shareholders’ equity	151,641		146,598		147,119		151,312		152,510
Dividends on common shares	3,976		3,711		3,711		3,711		3,712

________________________

(1)During 2017, we deconsolidated our upstream crude oil and natural gas exploration and production subsidiary, Adams Resources Exploration Company (“AREC”) upon its bankruptcy filing. We recognized an impairment related to the bankruptcy, deconsolidation and sale of substantially all of the assets of AREC 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 2017, we recognized an impairment on our medical investment in VestaCare.

(4)During 2019, we recognized a gain related to the dissolution of our investment in AREC.

(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 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.

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,
	2019		2018		Change ⁽¹⁾		2017		Change ⁽¹⁾

Revenues	$	1,748,056	$	1,694,437	3.2	%	$	1,267,275	33.7	%
Operating earnings	16,099		7,008		129.7	%	11,700		(40.1	%)
Depreciation and amortization	8,741		6,384		36.9	%	7,812		(18.3	%)
Driver compensation	22,754		14,567		56.2	%	13,058		11.6	%
Insurance	7,772		6,248		24.4	%	4,509		38.6	%
Fuel	8,979		7,435		20.8	%	5,278		40.9	%

____________________

(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,
	2019		2018		2017
Field level purchase volumes – per day ^{(1) (2)}
Crude oil – barrels	107,383		79,361		67,447

Average purchase price
Crude oil – per barrel	$	56.28	$	64.53	$	49.88

____________________

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

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2019 compared to 2018. Crude oil marketing revenues increased by $53.6 million during the year ended December 31, 2019 as compared to 2018, primarily as a result of higher crude oil volumes, which increased revenues by approximately $456.1 million, partially offset by a decrease in the market price of crude oil, which decreased revenues by approximately $402.5 million. The average crude oil price received was $64.53 for 2018, which decreased to $56.28 for 2019. Volumes increased approximately 28,000 barrels per day during the year ended December 31, 2019 as compared to 2018 primarily as a result of the acquisition of a trucking company that owned approximately 113 tractors and 126 trailers operating in the Red River area in North Texas and South Central Oklahoma (the “Red River acquisition”) on October 1, 2018. The purchase price for Red River volumes is based on a contractual price for volumes in North Texas and Oklahoma, which has been slightly lower than the purchase price for legacy volumes. Revenues from legacy volumes are based upon the market price in our other market areas, primarily in the Gulf Coast.

Our crude oil marketing operating earnings for the year ended December 31, 2019 increased by $9.1 million as compared to 2018, primarily as a result of inventory liquidation gains of $3.7 million in 2019 as compared to inventory valuation losses of $5.4 million in 2018 (as shown in the following table) and increases in crude oil volumes in 2019, partially offset by a decrease in the average market price of crude oil. During 2019, volumes increased as activity in certain marketing areas increased primarily as a result of increased wellhead purchases.

Driver compensation increased by $8.2 million during the year ended December 31, 2019 as compared to 2018, primarily as a result of an increase in the number of drivers in 2019 as compared to 2018 due to the Red River acquisition on October 1, 2018. In connection with the Red River acquisition, we hired over one hundred additional drivers.

Insurance costs increased by $1.5 million during the year ended December 31, 2019 as compared to 2018, primarily due to a higher driver count and additional miles driven in 2019, including as a result of the Red River acquisition in 2018. Fuel costs increased by $1.5 million during the year ended December 31, 2019 as compared to 2018 consistent with the higher driver count in the current year and additional miles driven, primarily as a result of the additional drivers hired for the Red River assets.

Depreciation and amortization expense increased by $2.4 million during the year ended December 31, 2019 as compared to 2018, primarily as a result of the acquisition of the Red River assets, consisting of approximately 113 tractors and 126 trailers on October 1, 2018, which resulted in an increase in depreciation expense. In addition, we purchased 43 new tractors and other field equipment during 2019, and retired 48 tractors.

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 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.

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Driver compensation 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.

Depreciation and amortization expense decreased by $1.4 million during the year ended December 31, 2018 as compared to 2017, primarily as a result of certain tractors, trailers and other field equipment being fully depreciated during 2017.

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.

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.

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,
	2019		2018		2017

As reported segment operating earnings ⁽¹⁾	$	16,099	$	7,008	$	11,700
Add (subtract):
Inventory liquidation gains	(3,749)		—		(3,372)
Inventory valuation losses	—		5,363		—
Derivative valuation (gains) losses	24		(2)		27
Field level operating earnings ⁽²⁾	$	12,374	$	12,369	$	8,355

____________________

(1)Segment operating earnings included inventory liquidation gains of $3.7 million and $3.3 million, respectively, for the years ended December 31, 2019 and 2017, and inventory valuation losses of $5.4 million for the year ended December 31, 2018.

(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, 2019 as compared to 2018, primarily due to higher revenues resulting from higher crude oil volumes, partially offset by a decrease in the market price of crude oil.

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.

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


	December 31,
	2019				2018					2017
		Average			Average			Average
	Barrels	Price		Barrels	Price		Barrels	Price

Crude oil inventory	426,397	$	61.93	415,523	$	54.82	198,011	$	61.57

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

Transportation

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


	Year Ended December 31,
	2019		2018		Change ⁽¹⁾		2017		Change ⁽¹⁾

Revenues	$	63,191	$	55,776	13.3	%	$	53,358	4.5	%
Operating earnings (losses)	$	1,899	$	3,337	(43.1	%)	$	(544)	(713.4	%)
Depreciation and amortization	$	7,900	$	4,270	85.0	%	$	5,364	(20.4	%)
Driver commissions	$	10,774	$	11,680	(7.8	%)	$	11,546	1.2	%
Insurance	$	5,938	$	4,716	25.9	%	$	5,452	(13.5	%)
Fuel	$	6,279	$	6,988	(10.1	%)	$	6,401	9.2	%
Maintenance expense	$	3,849	$	5,347	(28.0	%)	$	6,061	(11.8	%)
Mileage (000s)	20,535		19,177		7.1	%	21,836		(12.2	%)

____________________

(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,
	2019		2018		2017

Total transportation revenue	$	63,191	$	55,776	$	53,358
Diesel fuel cost	(6,279)		(6,988)		(6,401)
Revenues, net of fuel cost ⁽¹⁾	$	56,912	$	48,788	$	46,957

____________________

(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.

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2019 compared to 2018. Transportation revenues increased $7.4 million during the year ended December 31, 2019 as compared to 2018, primarily as a result of the EH Transport asset acquisition (see Note 7 in the Notes to Consolidated Financial Statements), increased miles traveled in 2019, and higher transportation rates in full effect in 2019 as a result of negotiations during 2018 with customers. Revenues, net of fuel cost, increased by $8.1 million during the year ended December 31, 2019 as compared to 2018, primarily as a result of the higher transportation revenues and miles traveled during 2019. Although the overall market has softened from 2018 levels, transportation activity has continued to increase for our transportation segment as we continue to pursue our strategy of streamlining operations and diversifying offerings in our transportation segment. We continue to work with customers to maintain our increased transportation rates as well as streamline operations in low margin areas.

Our transportation operating earnings for the year ended December 31, 2019 decreased by $1.4 million as compared to 2018, primarily due to higher depreciation and amortization expense related to the EH Transport asset acquisition and new assets placed into service and higher insurance expense as a result of more miles traveled during the current year, partially offset by higher revenues as noted above, and lower other operating expenses.

Fuel costs decreased by $0.7 million during the year ended December 31, 2019 as compared to 2018, primarily as a result of an decrease in the price of diesel during 2019 as compared to 2018, partially offset by an increase in miles traveled. Depreciation and amortization expense increased by $3.6 million during the year ended December 31, 2019 as compared to 2018, primarily as a result of the acquisition of the assets of EH Transport during the second quarter of 2019 and the purchase of new tractors in 2018 and 2019. Maintenance expense decreased $1.5 million during the year ended December 31, 2019 as compared to 2018, as a result of the purchase of new tractors and the retirement of older tractors, as the age of our fleet has decreased.

2018 compared to 2017. Transportation revenues increased $2.4 million during the year ended December 31, 2018 as compared to 2017, primarily as a result of a new transportation agreement entered into in January 2018 and higher transportation rates in 2018. Revenues, net of fuel cost, increased by $1.8 million during the year ended December 31, 2018 as compared to 2017, primarily as a result of higher revenues in 2018, partially offset by an increase in the price of diesel fuel and lower miles traveled during 2018.

Our transportation operating earnings for the year ended December 31, 2018 increased by $3.9 million as compared to 2017, primarily due to higher revenues as noted above, partially offset by higher other operating expenses and higher fuel costs as a result of an increase in the price of diesel in 2018.

Fuel costs increased by $0.6 million during the year ended December 31, 2018 as compared to 2017, primarily as a result of an increase in the price of diesel during 2018 as compared to 2017, partially offset by a decrease in miles traveled. Depreciation and amortization expense decreased by $1.1 million during the year ended December 31, 2018 as compared to 2017, primarily as a result of certain tractors, trailers and field equipment being fully depreciated during 2017, partially offset by the purchase of new tractors in the second, third and fourth quarters of 2018, which will result in increased depreciation expense in future periods. Maintenance expense decreased $0.7 million during the year ended December 31, 2018 as compared to 2017, as a result of the purchase of new tractors and the retirement of older tractors, as the age of our fleet has decreased.

Our operating results for 2017 were also adversely impacted by Hurricane Harvey, which affected the Gulf Coast area in late August and early September of 2017, resulting in decreased revenues and lower mileage during 2017.

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Equipment additions and retirements for the transportation fleet were as follows for the periods indicated:

Year Ended December 31,

2019

2018

2017

New tractors purchased ⁽¹⁾

151 units

60 units

—

Tractors retired ⁽¹⁾

107 units

67 units

21 units

New trailers purchased ⁽¹⁾

77 units

—

Trailers retired

20 units

12 units

—

________________

(1)2019 amounts do not include 39 tractors and 51 trailers purchased in connection with the EH Transport acquisition in May 2019. Of the 39 tractors purchased as part of the EH Transport acquisition, 35 tractors have been retired and are not included in the number of units noted in the table.

The sales of retired equipment produced gains of approximately $0.5 million, $0.8 million and less than $0.1 million during the years ended December 31, 2019, 2018 and 2017, respectively.

Our customers are primarily in the domestic petrochemical industry. Customer demand is affected by low natural gas prices (a basic feedstock cost for the petrochemical industry) and high export demand for petrochemicals. During 2017, the competitive landscape in the transportation sector remained difficult and led to lower revenues in this segment. During late 2017, we saw an increase in customer demand for chemical tank trucking, and we worked to capture those opportunities. During 2018, we began a strategy of streamlining operations and diversifying offerings in our transportation segment. We have continued to work with customers to increase our transportation rates as well as streamlining operations in low margin areas.

Crude Oil and Natural Gas

Prior to AREC’s bankruptcy filing, our upstream crude oil and natural gas exploration and production segment revenues and operating earnings were primarily a function of crude oil and natural gas prices and volumes. We accounted for our upstream operations under the successful efforts method of accounting. As a result of AREC’s bankruptcy filing in April 2017 and our loss of control of this subsidiary, we deconsolidated AREC effective with its bankruptcy filing and recorded our investment in AREC under the cost method of accounting. Our results for 2017 for this segment are only for the period from January 1, 2017 through April 30, 2017, the period in which AREC was consolidated.

Our upstream crude oil and natural gas exploration and production segment revenues, operating earnings and selected costs were as follows for the period from January 1, 2017 through April 30, 2017 (in thousands):



Revenues	$	1,427
Operating earnings	53
Depreciation and depletion	423
Prospect impairments	3

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Volume and price information were as follows for the period from January 1, 2017 through April 30, 2017 (volumes in thousands):


Crude oil:
Volume – barrels	11,643
Average price per barrel	$	49.44

Natural gas:
Volume – Mcf	189,488
Average price per Mcf	$	2.86

Natural gas liquids:
Volume – barrels	11,204
Average price per barrel	$	26.77

During the period from January 1, 2017 through April 30, 2017, we participated in the drilling of six wells in the Permian Basin and one well in the Haynesville Shale with no dry holes.

Capitalized crude oil and natural gas property costs were amortized in expense as the underlying crude oil and natural gas reserves were produced (units-of-production method).

General and Administrative Expense

General and administrative expenses increased by $1.3 million during the year ended December 31, 2019 as compared to 2018, primarily due to the receipt in 2018 of approximately $0.6 million in insurance proceeds related to Hurricane Harvey insurance claims, which reduced expenses in the prior year, and higher outside service fees, audit fees and personnel costs in 2019, partially offset by lower insurance costs and legal fees.

General and administrative expenses decreased by $0.8 million during the year ended December 31, 2018 as compared to 2017, primarily due to the receipt in 2018 of approximately $0.6 million in insurance proceeds related to Hurricane Harvey insurance claims, which reduced expenses, lower personnel costs in 2018, and the reversal in 2017 of certain legal accruals of approximately $0.7 million related to legal matters. 2017 also included approximately $1.0 million of additional personnel expenses related to a voluntary early retirement program for certain employees. These decreases in expenses were partially offset by an increase in expenses related to the amortization of equity awards (see Note 14 in the Notes to Consolidated Financial Statements) and an increase in legal and outside service fees in 2017.

Gain on Dissolution of Investment and Investments in Unconsolidated Affiliates

AREC. In April 2017, we deconsolidated AREC effective with its bankruptcy filing on April 21, 2017 and recorded our investment in AREC under the cost method of accounting. Based upon bids received in the auction process (see Note 4 in the Notes to Consolidated Financial Statements for further information), we determined that the fair value of our investment in AREC was expected to be lower than its net book value immediately prior to the deconsolidation. As a result, during the second quarter of 2017, we recorded a non-cash charge of 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, as a result of the sale of substantially all of AREC’s assets, we recognized an additional loss of $1.9 million, which represented the difference between the net proceeds we 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.

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During 2019, we received a cash payment from AREC totaling approximately $1.0 million, related to the final settlement of its bankruptcy and dissolution. Of the amount received, approximately $0.4 million was offset against a receivable that had been set up as of December 31, 2018 and $0.6 million was recorded as a gain in our consolidated statements of operations.

VestaCare. 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 our investment. As a result, we recognized a pre-tax impairment charge of $2.5 million during the third quarter of 2017 and wrote-off our investment in VestaCare.

Income Taxes

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

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. At December 31, 2019 and 2018, we had deferred tax liabilities of approximately $6.3 million and $4.2 million, respectively.

See Note 13 in the Notes to Consolidated Financial Statements for further information.

Liquidity and Capital Resources

Liquidity

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

At December 31, 2019, 2018 and 2017, we had no bank debt or other forms of debenture obligations. We maintain cash balances in order to meet the timing of day-to-day cash needs. Cash and working capital, the excess of current assets over current liabilities, were as follows at the dates indicated (in thousands):


	December 31,
	2019		2018		2017

Cash and cash equivalents	$	112,994	$	117,066	$	109,393
Working capital	87,747		106,323		116,087

We believe current cash balances, together with expected cash generated from future operations, and the ease of financing tractor and trailer additions through leasing arrangements (should the need arise) will be sufficient to meet our short-term and long-term liquidity needs.

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

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

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Cash Flows from Operating, Investing and Financing Activities

Our consolidated cash flows from operating, investing and financing activities were as follows for the periods indicated (in thousands):


	Year Ended December 31,
	2019		2018		2017

Cash provided by (used in):
Operating activities	$	46,899	$	31,014	$	26,096
Investing activities	(36,037)		(19,135)		(216)
Financing activities	(5,673)		(4,206)		(3,829)

Operating activities. Net cash flows provided by operating activities for the year ended December 31, 2019 increased by $15.9 million when compared to 2018. This increase was primarily due to an increase in revenues and a decrease in general and administrative expenses, partially offset by increased operating expenses, and the timing of collections of accounts receivable and payments of accounts payable.

Net cash flows provided by operating activities for the year ended December 31, 2018 increased by $4.9 million when compared to 2017. This increase was primarily due to an increase in revenues and a decrease in general and administrative expenses, partially offset by increased operating expenses.

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

Early payments were as follows at the dates indicated (in thousands):


	December 31,
	2019		2018		2017

Early payments received	$	54,108	$	38,539	$	20,078


Early payments to suppliers	—		—		6,100

We rely heavily on our ability to obtain open-line trade credit from our suppliers especially with respect to our crude oil marketing operations. During 2019, we received several early payments from certain customers in our crude oil marketing operations. Our cash balance increased by approximately $4.1 million at December 31, 2019 relative to the year ended December 31, 2018 primarily as a result of the timing of the receipt of these early payments received during each year.

Investing activities. Net cash flows used in investing activities for the year ended December 31, 2019 increased by $16.9 million when compared to 2018. This increase was primarily due to an increase of $24.0 million in capital spending for property and equipment (see “Capital Projects” below) and a decrease of $0.2 million in insurance and state collateral refunds in 2019. These increases in net cash flows used in investing activities were partially offset by a decrease in cash paid for asset acquisitions ($5.6 million was paid in 2019 for the purchase of the EH Transport assets in May 2019 in our transportation segment while $10.3 million was paid in 2018 for the purchase of the Red River assets in October 2019 in our crude oil marketing segment (see Note 7 in the Notes to Consolidated Financial Statements for further information)), an increase of $1.6 million in cash proceeds from the sales of assets and the receipt of $1.0 million in cash proceeds related to the final settlement of AREC’s bankruptcy in 2019 (see Note 4 in the Notes to Consolidated Financial Statements for further information).

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Net cash flows used in investing activities for the year ended December 31, 2018 increased by $18.9 million when compared to 2017. This increase was primarily due to the payment of $10.3 million for the purchase of Red River assets in our crude oil marketing segment (see Note 7 in the Notes to Consolidated Financial Statements for further information), an increase of $9.1 million in capital spending for property and equipment (see “Capital Projects” below) and the receipt of $2.8 million in proceeds in 2017 related to the partial settlement of AREC’s bankruptcy. These increases in net cash flows used in investing activities were partially offset by an increase of $1.9 million in insurance and state collateral refunds and an increase of $1.3 million in cash proceeds from the sales of assets.

Financing activities. Cash used in financing activities for the year ended December 31, 2019 increased by $1.5 million when compared to 2018. This increase was primarily due to an increase of $1.2 million in principal repayments made for finance lease obligations in our crude oil marketing segment for certain of our tractors and a tank storage and throughput arrangement. See “Other Items” below for information regarding our finance lease obligations. During the years ended December 31, 2019 and 2018, we paid aggregate cash dividends of $0.94 per common share, or a total of $4.0 million, and $0.88 per common share, or a total of $3.7 million, respectively.

Cash used in financing activities for the year ended December 31, 2018 increased by $0.4 million when compared to 2017. This increase was primarily due to an increase of $0.4 million in principal repayments made for finance lease obligations in our crude oil marketing segment for certain of our tractors. During each of the years ended December 31, 2018 and 2017, we paid cash dividends of $0.88 per common share, or a total of $3.7 million.

Capital Projects

We use cash from operations and existing cash balances to make discretionary investments in our crude oil marketing and transportation businesses. Capital spending for the past five years was as follows for the periods indicated (in thousands):


	Year Ended December 31,
	2019		2018		2017		2016		2015

Crude oil marketing ^{(1) (2)}	$	7,249	$	1,540	$	468	$	1,321	$	2,126
Transportation ⁽³⁾	28,472		10,178		351		6,868		6,579
Crude oil and natural gas exploration	—		—		1,825		295		2,369
Medical management	—		—		—		4,700		—
Other	22		13		—		—		—
Capital spending	$	35,743	$	11,731	$	2,644	$	13,184	$	11,074

_______________

(1)Our crude oil marketing segment amounts for the years ended December 31, 2019, 2018 and 2017, do not include approximately $4.1 million, $2.9 million and $1.8 million, respectively, of tractors acquired under finance leases.

(2)2018 amount does not include approximately $10.3 million of capital spending related to the Red River acquisition.

(3)2019 amount does not include approximately $6.4 million of capital spending related to the EH Transport acquisition.

Crude oil marketing. During 2015, 2016 and 2017, capital expenditures were primarily related to the purchase of tractors, trailers and other field equipment, and spending was reduced as a result of the low crude oil prices. During 2018, capital expenditures were primarily related to construction of a pipeline connection and a truck loading/unloading facility. During 2019, capital expenditures were primarily related to the purchase of 43 tractors and other field equipment.

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Transportation. During 2015, capital expenditures were primarily related to the purchase of tractors and trailers, and during 2016, for improvements to our existing Houston terminal facility and for tractors. Spending was curtailed in 2017, and in late 2017, we began to see increased demand in our transportation segment. As a result, we began to pursue a strategy of streamlining operations and diversifying offerings in this segment. Beginning in 2018, we implemented a plan to improve the age of our transportation fleet. During 2018, we purchased 60 new tractors, and during 2019, we purchased 152 new tractors and 77 new trailers.

Crude oil and natural gas exploration and production. During 2017, we exited the crude oil and natural gas exploration and production business with the April 2017 bankruptcy filing and subsequent sale of our crude oil and natural gas assets.

Medical management. During 2016, we invested $4.7 million in two medical-related investments, Bencap and VestaCare. During 2016, we wrote off our investment in Bencap, and in February 2017, we forfeited our interest in the entity. During 2017, we wrote off our investment in VestaCare, but continue to own an approximate 15 percent equity interest in the entity. We currently do not have any plans to pursue additional medical-related investments.

Other Items

Contractual Obligations

The following table summarizes our significant contractual obligations at December 31, 2019 (in thousands):


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

Finance lease obligations ⁽¹⁾	$	7,023	$	2,426	$	3,918	$	679	$	—
Operating lease obligations ⁽²⁾	10,717		2,660		4,170		3,444		443
Purchase obligations:
Crude oil marketing — crude oil ⁽³⁾	145,824		145,824		—		—		—
Crude oil marketing — tractors ⁽⁴⁾	940		940		—		—		—

Total contractual obligations	$	164,504	$	151,850	$	8,088	$	4,123	$	443

___________________

(1)Amounts represent our principal contractual commitments, including interest, outstanding under finance leases for certain tractors and tank storage and throughput arrangements in our crude oil marketing segment.

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

(3)Amount represents commitments to purchase certain quantities of crude oil substantially in January 2020 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 these purchase obligations.

(4)Amount represents commitments to purchase six new tractors in our crude oil marketing segment.

We maintain certain lease arrangements with independent truck owner-operators for use of their equipment and driver services on a month-to-month basis. In addition, we enter into office space and certain lease and terminal access contracts in order to provide tank storage and dock access for our crude oil marketing business. These storage and access contracts require certain minimum monthly payments for the term of the contracts.

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Rental expense was as follows for the periods indicated (in thousands):


	Year Ended December 31,
	2019		2018		2017

Rental expense	$	14,662	$	11,078	$	12,073

Insurance

Our primary insurance needs are workers’ compensation, automobile and umbrella liability coverage for our trucking fleet and medical insurance for our employees. See Note 17 in the Notes to Consolidated Financial Statements for further information. Insurance costs were as follows for the periods indicated (in thousands):


	Year Ended December 31,
	2019		2018		2017

Insurance costs	$	14,149	$	11,374	$	10,438

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements that have or are reasonably expected to have a material current or future effect on our financial position, results of operations or cash flows.

Related Party Transactions

For information regarding our related party transactions, see Note 11 in the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Recent Accounting Developments

For information regarding recent accounting developments, see Note 2 in the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Outlook

Our focus in 2020 will be to continue to expand our core businesses while delivering value to our shareholders. We will work to achieve positive results in markets with strong competition and margin pressures throughout all segments of our business.

Our major objectives for 2020 are as follows:

•Crude oil marketing – We look forward to naming a new President of GulfMark that will help us continue to focus on increasing margins to maximize cash flow and capturing midstream opportunities in an increasingly volatile market. In addition, we will look for opportunities to increase our trucking fleet to add to our overall ability to gather and distribute crude oil.

•Transportation – With the appointment of our new President of STC, we plan to continue to increase truck utilization, upgrade our fleet quality and enhance driver retention and recruitment. The transportation segment is uniquely positioned to take advantage of major downstream infrastructure projects that are taking place across the Gulf Coast. We plan to look for ways to expand our terminal footprint to put us in a position to better compete for new business.

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•Strategic business development – Collectively with new subsidiary presidents and our newly appointed CEO, we will deploy a disciplined investment approach to growth in our two core segments and funding new growth opportunities that are adjacent and complimentary to existing operating activities.

Critical Accounting Policies and Estimates

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

Fair Value Accounting

We enter into certain forward commodity contracts that are required to be recorded at fair value, and these contracts are recorded as either an asset or liability measured at its fair value. Changes in fair value are recognized immediately in earnings unless the derivatives qualify for, and we elect, cash flow hedge accounting. We had no contracts designated for hedge accounting during the years ended December 31, 2019, 2018 and 2017.

We utilize a market approach to valuing our commodity contracts. On a contract by contract, forward month by forward month basis, we obtain observable market data for valuing our contracts that typically have durations of less than 18 months. At December 31, 2019, all of our market value measurements were based on inputs based on observable market data (Level 2 inputs). See discussion under “Fair Value Measurements” in Note 2 and Note 12 in the Notes to Consolidated Financial Statements.

Our fair value contracts give rise to market risk, which represents the potential loss that may result from a change in the market value of a particular commitment. We monitor and manage our exposure to market risk to ensure compliance with our risk management policies. These risk management policies are regularly assessed to ensure their appropriateness given our objectives, strategies and current market conditions.

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. We manage our crude oil marketing receivables by participating in a monthly settlement process with each of our counterparties. Ongoing account balances are monitored monthly, and we reconcile outstanding balances with counterparties. We also place great emphasis on collecting cash balances due.

We maintain and monitor our allowance for doubtful accounts. 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. Customer payments are regularly monitored. However, a degree of risk remains due to the custom and practices of the industry. See Note 2 in the Notes to Consolidated Financial Statements for further information.

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Liability and Contingency Accruals

From time to time as incidental to our operations, we become involved in various accidents, lawsuits and/or disputes. As an operator of an extensive trucking fleet, we are a party to motor vehicle accidents, worker compensation claims or other items of general liability as are typical for the industry. In addition, we have extensive operations that must comply with a wide variety of tax laws, environmental laws and labor laws, among others. Should an incident occur, we evaluate the claim based on its nature, the facts and circumstances and the applicability of insurance coverage. When our assessment indicates that it is probable that a liability has occurred and the amount of the liability can be reasonably estimated, we make appropriate accruals or disclosure. We base our estimates on all known facts at the time and our assessment of the ultimate outcome, including consultation with external experts and counsel. We revise these estimates as additional information is obtained or resolution is achieved.

During 2019, we received a notice from the IRS regarding a proposed penalty of approximately $1.2 million for our 2017 tax year information returns. See Note 17 in the Notes to Consolidated Financial Statements for further information. At December 31, 2019, we do not believe any of our outstanding legal matters would have a material adverse effect on our financial position, results of operations or cash flows.

Revenue Recognition

On January 1, 2018, we adopted Financial Accounting Standards Board Accounting Standards Codification 606, Revenue from Contracts with Customers (“ASC 606”) and all related Accounting Standards Updates by applying the modified retrospective approach to all contracts that were not completed on January 1, 2018. 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 recognition of revenue as the entity satisfies the performance obligations.

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 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 segment, most of 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. See Note 3 in the Notes to Consolidated Financial Statements for further information.

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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 crude oil marketing segment. Realized pricing is primarily driven by the prevailing spot prices applicable to crude 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. 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 2 and Note 12 in the Notes to Consolidated Financial Statements for further information).

Historically, prices received for crude oil sales have been volatile and unpredictable with price volatility expected to continue. From January 1, 2018 through December 31, 2019, our crude oil monthly average wholesale purchase costs ranged from an average low of $43.42 per barrel to a monthly average high of $74.74 per barrel during the same period. A hypothetical ten percent additional adverse change in average crude oil prices, assuming no changes in volume levels, would have reduced earnings by approximately $2.7 million and $2.3 million for the years ended December 31, 2019 and 2018, 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.
Report of Independent Registered Public Accounting Firm			35

Consolidated Balance Sheets as of December 31, 2019 and 2018			36

Consolidated Statements of Operations for the Years Ended December 31, 2019, 2018 and 2017			37

Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017			38

Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2019, 2018 and 2017			39

Notes to Consolidated Financial Statements
Note 1 – Organization and Basis of Presentation			40
Note 2 – Summary of Significant Accounting Policies			41
Note 3 – Revenue Recognition			47
Note 4 – Subsidiary Bankruptcy, Deconsolidation and Sale			49
Note 5 – Prepayments and Other Current Assets			50
Note 6 – Property and Equipment			51
Note 7 – Asset Acquisitions			52
Note 8 – Cash Deposits and Other Assets			54
Note 9 – Investments in Unconsolidated Affiliates			55
Note 10 – Segment Reporting			56
Note 11 – Transactions with Affiliates			58
Note 12 – Derivative Instruments and Fair Value Measurements			58
Note 13 – Income Taxes			61
Note 14 – Stock-Based Compensation Plan			63
Note 15 – Supplemental Cash Flow Information			66
Note 16 – Leases			66
Note 17 – Commitments and Contingencies			69
Note 18 – Concentration of Credit Risk			71
Note 19 – Quarterly Financial Information (Unaudited)			72
Note 20 – Oil and Gas Producing Activities (Unaudited)			72

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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 sheets of Adams Resources & Energy, Inc. and subsidiaries (the Company) as of December 31, 2019 and 2018, the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2019, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2019, 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, 2019, 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 6, 2020 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Change in Accounting Principle

As discussed in Note 16 to the consolidated financial statements, the Company has changed its method of accounting for leases as of January 1, 2019 due to the adoption of Accounting Standards Codification 842, Leases.

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 6, 2020

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share data)


	December 31,
	2019		2018
ASSETS
Current assets:
Cash and cash equivalents	$	112,994	$	117,066
Restricted cash	9,261		—
Accounts receivable, net of allowance for doubtful accounts of $141 and $153, respectively	94,534		85,197
Accounts receivable – related party	—		425
Inventory	26,407		22,779
Derivative assets	—		162
Income tax receivable	2,569		2,404
Prepayments and other current assets	1,559		1,557
Total current assets	247,324		229,590
Property and equipment, net	69,046		44,623
Operating lease right-of-use assets, net	9,576		—
Intangible assets, net	1,597		—
Cash deposits and other assets	3,299		4,657
Total assets	$	330,842	$	278,870

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	147,851	$	116,068
Accounts payable – related party	5		29
Derivative liabilities	—		139
Current portion of finance lease obligations	2,167		883
Current portion of operating lease liabilities	2,252		—
Other current liabilities	7,302		6,148
Total current liabilities	159,577		123,267
Other long-term liabilities:
Asset retirement obligations	1,573		1,525
Finance lease obligations	4,376		3,209
Operating lease liabilities	7,323		—
Deferred taxes and other liabilities	6,352		4,271
Total liabilities	179,201		132,272

Commitments and contingencies (Note 17)

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, 4,235,533 and 4,217,596 shares outstanding, respectively	423		422
Contributed capital	12,778		11,948
Retained earnings	138,440		134,228
Total shareholders’ equity	151,641		146,598
Total liabilities and shareholders’ equity	$	330,842	$	278,870

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 December 31,
	2019		2018		2017
Revenues:
Marketing	$	1,748,056	$	1,694,437	$	1,267,275
Transportation	63,191		55,776		53,358
Oil and natural gas	—		—		1,427
Total revenues	1,811,247		1,750,213		1,322,060

Costs and expenses:
Marketing	1,723,216		1,681,045		1,247,763
Transportation	53,392		48,169		48,538
Oil and natural gas	—		—		948
Oil and natural gas property impairments	—		—		3
General and administrative	10,198		8,937		9,707
Depreciation, depletion and amortization	16,641		10,654		13,599
Total costs and expenses	1,803,447		1,748,805		1,320,558

Operating earnings	7,800		1,408		1,502

Other income (expense):
Loss on deconsolidation of subsidiary (Note 4)	—		—		(3,505)
Impairment of investment in unconsolidated affiliate (Note 4)	—		—		(2,500)
Gain on dissolution of investment (Note 4)	573		—		—
Interest income	2,766		2,155		1,103
Interest expense	(636)		(109)		(27)
Total other income (expense), net	2,703		2,046		(4,929)

(Losses) earnings before income taxes	10,503		3,454		(3,427)

Income tax (provision) benefit:
Current	(211)		427		(895)
Deferred	(2,085)		(936)		3,840
Income tax benefit (provision)	(2,296)		(509)		2,945

Net (losses) earnings	$	8,207	$	2,945	$	(482)

Earnings (losses) per share:
Basic net (losses) earnings per common share	$	1.94	$	0.70	$	(0.11)
Diluted net (losses) earnings per common share	$	1.94	$	0.70	$	(0.11)

Dividends per common share	$	0.94	$	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,
	2019		2018		2017
Operating activities:
Net (losses) earnings	$	8,207	$	2,945	$	(482)
Adjustments to reconcile net (losses) earnings to net cash
provided by operating activities:
Depreciation, depletion and amortization	16,641		10,654		13,599
Gains on sales of property	(1,400)		(1,240)		(594)
Impairment of oil and natural gas properties	—		—		3
Provision for doubtful accounts	(12)		(150)		78
Stock-based compensation expense	478		255		—
Deferred income taxes	2,085		936		(3,840)
Net change in fair value contracts	23		(2)		27
Gain on dissolution of AREC	(573)		—		—
Impairment of investments in unconsolidated affiliates	—		—		2,500
Loss on deconsolidation of subsidiary	—		—		3,505
Changes in assets and liabilities:
Accounts receivable	(8,373)		36,350		(34,935)
Accounts receivable/payable, affiliates	(24)		24		271
Inventories	(3,628)		(10,587)		878
Income tax receivable	(165)		(1,087)		1,418
Prepayments and other current assets	(2)		(293)		831
Accounts payable	31,795		(10,252)		44,790
Accrued liabilities	1,154		1,744		(991)
Other	693		1,717		(962)
Net cash provided by operating activities	46,899		31,014		26,096

Investing activities:
Property and equipment additions	(35,743)		(11,731)		(2,644)
Asset acquisitions	(5,624)		(10,272)		—
Proceeds from property sales	3,680		2,038		720
Proceeds from sales of AREC assets	—		—		2,775
Proceeds from dissolution of AREC	998		—		—
Insurance and state collateral (deposits) refunds	652		830		(1,067)
Net cash used in investing activities	(36,037)		(19,135)		(216)

Financing activities:
Principal repayments of finance lease obligations	(1,697)		(495)		(118)
Dividends paid on common stock	(3,976)		(3,711)		(3,711)
Net cash used in financing activities	(5,673)		(4,206)		(3,829)

Increase in cash and cash equivalents, including restricted cash	5,189		7,673		22,051
Cash and cash equivalents, including restricted cash, at beginning of period	117,066		109,393		87,342
Cash and cash equivalents, including restricted cash, at end of period	$	122,255	$	117,066	$	109,393

See Notes to Consolidated Financial Statements.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(In thousands, except per share data)


							Total
	Common		Contributed		Retained		Shareholders’
	Stock		Capital		Earnings		Equity

Balance, January 1, 2017	$	422	$	11,693	$	139,197	$	151,312
Net losses	—		—		(482)		(482)
Dividends declared:
Common stock, $0.88 per 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 per share	—		—		(3,711)		(3,711)
Awards under LTIP, $0.44 per share	—		—		(10)		(10)
Balance, December 31, 2018	422		11,948		134,228		146,598
Net earnings	—		—		8,207		8,207
Stock-based compensation expense	—		478		—		478
Issuance of common shares for acquisition	1		391		—		392
Cancellation of shares withheld to cover taxes upon vesting of restricted awards	—		(39)		—		(39)
Dividends declared:
Common stock, $0.94 per share	—		—		(3,976)		(3,976)
Awards under LTIP, $0.94 per share	—		—		(19)		(19)
Balance, December 31, 2019	$	423	$	12,778	$	138,440	$	151,641

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 American LLC under the ticker symbol “AE”. We, 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 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 4 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 4 for further information). We obtained approval of a confirmed plan in December 2017, and the case was dismissed in October 2018. Over the past few years prior to the bankruptcy filing, 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 (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 4 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

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 18 for further information regarding credit risk.

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


	December 31,
	2019		2018		2017

Balance at beginning of period	$	153	$	303	$	225
Charges to costs and expenses	26		43		137
Deductions	(38)		(193)		(59)
Balance at end of period	$	141	$	153	$	303

Cash, Cash Equivalents and Restricted Cash

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

Restricted cash represented an amount held in a segregated bank account by Wells Fargo as collateral for amounts outstanding under our letter of credit facility prior to its termination. In June 2019, the amount of outstanding letters of credit under our letter of credit facility exceeded the borrowing base as defined in the letter of credit facility agreement. As a result, we were required to deposit cash with the lender as security for the outstanding letters of credit. See “Letter of Credit Facility” within this Note 2 for further information. Our borrowing base was based on our net receivable balance, and due to customer prepayments, our borrowing base as outlined in the letter of credit facility did not fully support the outstanding letters of credit that had been issued. As a result, on July 1, 2019, we canceled the letter of credit facility, and secured the outstanding letters of credit with our restricted cash balance.

The following table provides a reconciliation of cash and cash equivalents and restricted cash as reported in the consolidated balance sheets that totals to the amounts shown in the consolidated statements of cash flows (in thousands):


	December 31,
	2019		2018

Cash and cash equivalents	$	112,994	$	117,066
Restricted cash	9,261		—
Total cash, cash equivalents and restricted cash shown in the
consolidated statements of cash flows	$	122,255	$	117,066

Common Shares Outstanding

The following table reconciles our outstanding common stock for the periods indicated:


						Common
						shares

Balance, December 31, 2017 and 2018						4,217,596
Issuance of shares in acquisition (see Note 7)						11,145
Vesting of restricted stock unit awards (see Note 14)						7,604
Shares withheld to cover taxes upon vesting of restricted stock unit awards						(883)
Other						71
Balance, December 31, 2019						4,235,533

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.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 14 for further discussion).

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


	Year Ended December 31,
	2019		2018		2017
Earnings (losses) per share – numerator:
Net (losses) earnings	$	8,207	$	2,945	$	(482)

Denominator:
Basic weighted average number of shares outstanding	4,228		4,218		4,218
Basic earnings (losses) per share	$	1.94	$	0.70	$	(0.11)

Diluted earnings (losses) per share:

Diluted weighted average number of shares outstanding:
Common shares	4,228		4,218		4,218
Restricted stock unit awards ⁽¹⁾	5		—		—
Performance share unit awards ⁽²⁾	—		—		—
Total	4,233		4,218		4,218

Diluted earnings (losses) per share	$	1.94	$	0.70	$	(0.11)

_______________

(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 are included in the calculation of diluted earnings per share when the performance share award performance conditions have been achieved. The performance conditions for the performance share unit awards granted in 2018 and 2019 were achieved as of December 31, 2018 and 2019, respectively. For the years ended December 31, 2019 and 2018, the effects of the performance share awards on earning per share were anti-dilutive.

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,
	2019		2018		2017

Contributory expenses	$	1,117	$	808	$	734

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.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

The characteristics of the fair value amounts classified within each level of the hierarchy are described as follows:

•Level 1 fair values are based on quoted prices, which are available in active markets for identical assets or liabilities as of the measurement date. Active markets are defined as those in which transactions for identical assets or liabilities occur with sufficient frequency so as to provide pricing information on an ongoing basis. For Level 1 valuation of marketable securities, we utilize market quotations provided by our primary financial institution. For the valuations of derivative financial instruments, we utilize the New York Mercantile Exchange (“NYMEX”) for certain commodity valuations.

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

•Level 3 fair values are based on unobservable market data inputs for assets or liabilities.

Fair value contracts consist of derivative financial instruments and are recorded as either an asset or liability measured at its fair value. Changes in fair value are recognized immediately in earnings unless the derivatives qualify for, and we elect, cash flow hedge accounting. We had no contracts designated for hedge accounting during any of the current reporting periods (see Note 12 for further information).

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

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Impairment Testing for Long-Lived Assets

Long-lived assets (primarily property and equipment and intangible assets) 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 12 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 13 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 impacts our income tax provision or benefit.

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 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, 2019 and 2017.

Letter of Credit Facility

We maintained a Credit and Security Agreement with Wells Fargo Bank, National Association, to provide for the issuance of up to $60.0 million in stand-by letters of credit primarily used to support crude oil purchases within our crude oil marketing segment and for other purposes. Stand-by letters of credit were issued as needed and were canceled as the underlying purchase obligations were satisfied by cash payment when due. The issuance of stand-by letters of credit enabled us to avoid posting cash collateral when procuring crude oil supply. We used the letter of credit facility for letters of credit related to our insurance program. At December 31, 2018, we had $4.6 million of letters of credit outstanding under this facility.

Our borrowing base was based on our net receivable balance, and due to customer prepayments, our borrowing base as outlined in the letter of credit facility did not fully support the outstanding letters of credit that have been issued. As a result, on July 1, 2019, we canceled the letter of credit facility, and secured the outstanding letters of credit with our restricted cash balance. No further performance obligations exist under the facility effective with its termination.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 two to thirty-nine years.

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 6 for additional information regarding our property and equipment and AROs.

Recent Accounting Pronouncements

Measurement of Credit Losses on Financial Instruments. In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-13, which replaces the current incurred loss impairment method with a method that reflects expected credit losses on financial instruments. In November 2018, the FASB issued ASU 2018-19, which clarifies the scope of the standard in the amendments in ASU 2016-13. In May 2019, the FASB issued ASU 2019-05, which provides entities with an option to irrevocably elect the fair value option for certain financial instruments. The new standard is effective as of January 1, 2020, and we adopted this standard effective January 1, 2020. We do not believe the adoption of this standard will have a material impact on our consolidated financial statements or on our disclosures.

Stock-Based Compensation

We measure all share-based payment awards, including the issuance of restricted stock unit awards and performance share unit awards 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 statements of operations based on the estimated fair value of those awards on the grant date and is 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 14 for additional information regarding our 2018 LTIP.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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 recognition of revenue as the entity satisfies the performance obligations.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 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.

Revenue Disaggregation

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


	Reporting Segments
	Marketing		Transportation		Total

Year Ended December 31, 2019
Revenues from contracts with customers	$	1,555,393	$	63,191	$	1,618,584
Other ⁽¹⁾	192,663		—		192,663
Total revenues	$	1,748,056	$	63,191	$	1,811,247

Timing of revenue recognition:
Goods transferred at a point in time	$	1,555,393	$	—	$	1,555,393
Services transferred over time	—		63,191		63,191
Total revenues from contracts with customers	$	1,555,393	$	63,191	$	1,618,584

Year Ended December 31, 2018
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.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Other Crude Oil 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 net revenue basis in the accompanying consolidated financial 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,
	2019		2018		2017

Revenue gross-up	$	859,091	$	448,846	$	203,095

Note 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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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

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 crude oil and natural gas assets for aggregate cash proceeds of approximately $5.2 million. The Bankruptcy Court approved the asset purchase and sales agreements, and we sold 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 represented the difference between the proceeds we 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 case was dismissed during October 2018. During 2019, we received a cash payment from AREC totaling approximately $1.0 million, related to the final settlement of its bankruptcy and dissolution. Of the amount received, approximately $0.4 million was offset against a receivable that had been set up as of December 31, 2018, and $0.6 million was recorded as a gain in our consolidated statements of operations.

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. 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.

Note 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,
	2019		2018

Insurance premiums	$	473	$	677
Rents, licenses and other	1,086		880
Total	$	1,559	$	1,557

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 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
	Useful Life	December 31,
	in Years	2019		2018

Tractors and trailers ⁽¹⁾	5 – 6	$	115,693	$	96,523
Field equipment ⁽²⁾	2 – 5	25,094		20,725
Buildings	5 – 39	16,055		15,746
Office equipment	2 – 5	1,951		1,863
Land		1,790		1,790
Construction in progress		3,661		2,794
Total		164,244		139,441
Less accumulated depreciation		(95,198)		(94,818)
Property and equipment, net		$	69,046	$	44,623

______________

(1)Amounts include tractors held under finance leases in our crude oil marketing segment. At December 31, 2019 and 2018, gross property and equipment associated with these assets held under finance leases were $5.5 million and $4.7 million, respectively. Accumulated amortization associated with these assets held under finance leases were $1.7 million and $0.7 million at December 31, 2019 and 2018, respectively (see Note 16 for further information).

(2)2019 amount includes a tank storage and throughput arrangement in our crude oil marketing segment held under a finance lease. Gross property and equipment associated with these assets held under a finance lease at December 31, 2019 was $3.3 million. Accumulated amortization associated with these assets held under a finance lease at December 31, 2019 was $0.7 million (see Note 16 for further information).

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


	Year Ended December 31,
	2019		2018		2017
Depreciation, depletion and amortization, excluding amounts
under finance leases	$	14,833	$	10,112	$	13,478
Amortization of property and equipment under finance leases	1,808		542		121
Total depreciation, depletion and amortization	$	16,641	$	10,654	$	13,599

Gains on Sales of Assets

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


	Year Ended December 31,
	2019		2018		2017

Gains on sales of used tractors, trailers and equipment	$	1,400	$	1,240	$	594

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 is 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. The following table reflects a summary of our AROs for the periods indicated (in thousands):


	Year Ended December 31,
	2019		2018		2017

ARO liability at beginning of year	$	1,525	$	1,273	$	2,329
Liabilities incurred	17		252		18
Accretion of discount	48		36		58
Liabilities settled	(17)		(36)		(261)
Deconsolidation of subsidiary ⁽¹⁾	—		—		(871)
ARO liability at end of year	$	1,573	$	1,525	$	1,273

_______________

(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 7. Asset Acquisitions

EH Transport

On April 10, 2019, we entered into a purchase and sale agreement with EH Transport, Inc. and affiliates (collectively, “EH Transport”), a Houston, Texas based bulk carrier trucking company, for the purchase of certain transportation assets. On May 6, 2019, we closed on the asset acquisition for approximately $6.4 million, which consisted of $5.6 million in cash after post-closing adjustments related to equipment qualifications, 11,145 of our common shares valued at $0.4 million and contingent consideration valued at approximately $0.4 million.

This acquisition added approximately 39 tractors and 51 trailers to our existing transportation fleet, and these assets were included in our transportation segment. This acquisition added new customers and new product lines to our transportation segment portfolio, which allows us to grow into new markets. As a result of the acquisition, in addition to general chemical products, we transport liquefied petroleum gas, asphalt and bleach for customers.

We incurred approximately $0.1 million of acquisition costs in connection with this acquisition, which has been included in the allocation of the purchase price to the assets acquired.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the consideration paid for the EH Transport assets and the estimated fair value of the assets acquired at the acquisition date (in thousands):


Consideration:
Cash	$	5,624
Value of AE common shares issued	392
Contingent consideration arrangement	431
Fair value of total consideration transferred	$	6,447

Recognized amounts of identifiable assets acquired:
Property and equipment — tractors and trailers	$	4,576
Shop, office and telecommunication equipment	20
Intangible assets — customer relationships	1,851
Total purchase price	$	6,447

The fair market value of the common shares issued in this transaction was determined based upon the closing share price of AE common stock on May 6, 2019 of $35.15.

We assumed no liabilities in this acquisition. The estimated fair value of the acquired property and equipment was determined using the estimated market value of each type of asset. The estimated fair value of the acquired customer relationship intangible assets was determined using an income approach, specifically a discounted cash flow analysis. The income approach estimates the future benefits of the customer relationships and deducts the expenses incurred in servicing the relationships and the contributions from the other business assets to derive the future net benefits of these assets. The future net benefits are discounted back to present value using the appropriate discount rate, which results in the value of the customer relationships.

A customer relationship intangible asset is the relationship between EH Transport and various customers to whom we did not have a previous relationship. The customer relationships we acquired in this transaction provide us with access to those customers to whom we did not have a previous relationship and allows us to enter product markets in which we had not previously participated. Because of the highly competitive and fragmented transportation market, we believe access to these customers and product lines will provide us with an entry into new markets.

The discounted cash flow analysis used to estimate the fair value of the EH Transport customer relationships relied on Level 3 fair value inputs. Level 3 fair values are based on unobservable inputs. Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset at the measurement date. With respect to the EH Transport customer relationships, the Level 3 inputs include the rate of retention of the current customers of EH Transport as of the valuation date, our transportation segment’s historical customer retention rate and projected future revenues associated with the customers. The EH Transport customers expected to remain with us after the transaction were included in the valuation of the customer relationships. We are amortizing the customer relationship intangible assets over a period of seven years, using a modified straight-line approach.

During the year ended December 31, 2019, we recorded $0.2 million of amortization expense related to these intangible assets. The following table presents our forecast of amortization expense associated with these intangible assets for the years indicated (in thousands):


	2020		2021		2022		2023		2024

Amortization expense	$	302	$	283	$	263	$	244	$	227

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The purchase and sale agreement includes a contingent consideration arrangement that requires us to pay the former owner of the assets up to a quarterly maximum amount of $146,875 (undiscounted) plus interest for the first four quarters following the closing date of the acquisition. The amount to be paid is based upon the number of qualified truck drivers that are employed by us at the end of each quarter. The potential undiscounted amount of all future payments that could be required to be paid under the contingent consideration arrangement is between $0 and $587,500. The fair value of the contingent consideration arrangement of $0.4 million was estimated by applying an income valuation approach, which is based on Level 3 inputs, including the number of qualified truck drivers we expect will be employed at each payment date. At December 31, 2019, we had a remaining accrual of $0.2 million related to this contingent consideration arrangement, which was included in other current liabilities.

Red River

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 was 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 purchase price	$	10,272

Note 8. Cash Deposits and Other Assets

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


	December 31,
	2019		2018

Amounts associated with liability insurance program:
Insurance collateral deposits	$	1,233	$	1,453
Excess loss fund	943		1,916
Accumulated interest income	609		788
Other amounts:
State collateral deposits	37		57
Materials and supplies	477		443

Total	$	3,299	$	4,657

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.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9. Investments in Unconsolidated Affiliates

At December 31, 2019, 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, 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 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, 2019, 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 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 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, 2019, we continue to own an approximate 15 percent equity interest in VestaCare.

AREC

As a result of AREC’s voluntary bankruptcy filing in April 2017 and our loss of control of this subsidiary, we deconsolidated AREC in April 2017, and we recorded our investment in this subsidiary under the cost method of accounting. 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. During the third quarter of 2017, as a result of the sale of substantially all of AREC’s assets, we recognized an additional loss of $1.9 million, which represented the difference between the net proceeds we 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 case was dismissed during October 2018. During 2019, we received a cash payment from AREC totaling approximately $1.0 million, related to the final settlement of its bankruptcy and dissolution. Of the amount received, approximately $0.4 million was offset against a receivable that had been set up as of December 31, 2018, and $0.6 million was recorded as a gain in our consolidated statements of operations.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 10. 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 (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 4 for further information), and as a result of our loss of control of the wholly owned subsidiary, AREC was deconsolidated and was accounted for under the cost method of accounting. AREC remained a reportable segment until its deconsolidation, effective April 30, 2017.

Financial information by reporting segment was as follows for the periods indicated (in thousands):


	Reporting Segments
	Marketing		Transportation		Oil and Gas and Other ⁽¹⁾		Total

Year Ended December 31, 2019
Revenues	$	1,748,056	$	63,191	$	—	$	1,811,247
Segment operating (losses) earnings ⁽²⁾	16,099		1,899		—		17,998
Depreciation, depletion and amortization	8,741		7,900		—		16,641
Property and equipment additions ⁽⁴⁾	7,249		28,472		22		35,743

Year Ended December 31, 2018
Revenues	$	1,694,437	$	55,776	$	—	$	1,750,213
Segment operating (losses) earnings ⁽²⁾	7,008		3,337		—		10,345
Depreciation, depletion and amortization	6,384		4,270		—		10,654
Property and equipment additions ^{(4) (5)}	1,540		10,178		13		11,731

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

_________________

(1)Amounts presented for the year ended December 31, 2017 are related to our upstream crude oil and natural gas exploration and production segment prior to its deconsolidation.

(2)Our crude oil marketing segment’s operating earnings included inventory liquidation gains of $3.7 million and $3.3 million, respectively, for the years ended December 31, 2019 and 2017, and inventory valuation losses of $5.4 million for the year ended December 31, 2018.

(3)Segment operating (losses) earnings for the year ended December 31, 2017 includes approximately $0.4 million of costs related to a voluntary early retirement program that was implemented in August 2017.

(4)Our crude oil marketing segment’s property and equipment additions do not include approximately $4.1 million, $2.9 million and $1.8 million of assets acquired under finance leases during the years ended December 31, 2019, 2018 and 2017, respectively. See Note 16 for further information.

(5)During the years ended December 31, 2019 and 2018, we had $22 thousand and $13 thousand, respectively, 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, as follows for the periods indicated (in thousands):


	Year Ended December 31,
	2019		2018		2017

Segment operating earnings	$	17,998	$	10,345	$	11,209
General and administrative ⁽¹⁾	(10,198)		(8,937)		(9,707)
Operating earnings	7,800		1,408		1,502
Loss on deconsolidation of subsidiary	—		—		(3,505)
Impairment of investment in unconsolidated affiliate	—		—		(2,500)
Gain on dissolution of investment	573		—		—
Interest income	2,766		2,155		1,103
Interest expense	(636)		(109)		(27)
(Losses) earnings before income taxes	$	10,503	$	3,454	$	(3,427)

_______________

(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,
	2019		2018		2017

Reporting segment:
Marketing	$	141,402	$	119,370	$	134,745
Transportation	58,483		34,112		29,069
Oil and Gas ⁽¹⁾	—		—		425
Cash and other	130,957		125,388		118,465
Total assets	$	330,842	$	278,870	$	282,704

____________________

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

There were no intersegment sales during the years ended December 31, 2019 and 2018, and intersegment sales during the year ended December 31, 2017 were insignificant. Other identifiable assets are primarily corporate cash, corporate accounts receivable 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 11. 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 in a building operated by 17 South Briar Hollow Lane, LLC, an affiliate of KSA Industries, Inc., which is an affiliated entity.

We utilized our former affiliate, Bencap, to administer certain of our employee medical benefit programs including a detail audit of individual medical claims (see Note 9 for further information). Bencap earned a fee from us for providing these 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 a result, we have no further ownership interest in Bencap (see Note 9).

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


	Year Ended December 31,
	2019		2018		2017

Affiliate billings to us	$	83	$	75	$	81
Billings to affiliates	5		6		4
Rentals paid to affiliate	487		487		583
Fee paid to Bencap ⁽¹⁾	—		—		108

___________________

(1)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 4 for further information).

Note 12. Derivative Instruments and Fair Value Measurements

Derivative Instruments

At December 31, 2019, we had in place six commodity purchase and sale contracts with 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:

•258 barrels per day of crude oil during January 2020 through February 2020;

•322 barrels per day of crude oil during March 2020 through April 2020; and

•258 barrels per day of crude oil during May 2020 through December 2020.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

The estimated fair value of forward month commodity contracts (derivatives) reflected in the accompanying consolidated balance sheets were as follows at the dates indicated (in thousands):


	Balance Sheet Location and Amount
	Current		Other		Current		Other
December 31, 2019	Assets		Assets		Liabilities		Liabilities
Asset derivatives:
Fair value forward hydrocarbon commodity
contracts at gross valuation	$	—	$	—	$	—	$	—
Liability derivatives:
Fair value forward hydrocarbon commodity
contracts at gross valuation	—		—		—		—
Less counterparty offsets	—		—		—		—
As reported fair value contracts	$	—	$	—	$	—	$	—

December 31, 2018
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	$	—

We only enter into commodity contracts with creditworthy counterparties and evaluate our exposure to significant counterparties on an ongoing basis. At December 31, 2019 and 2018, 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,
	2019		2018		2017

Revenues – marketing	$	(24)	$	2	$	(26)

Fair Value Measurements

The following table reflects, 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):


	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

December 31, 2019
Derivatives:
Current assets	$	—	$	—	$	—	$	—	$	—
Current liabilities	—		—		—		—		—
Net value	$	—	$	—	$	—	$	—	$	—

December 31, 2018
Derivatives:
Current assets	$	—	$	162	$	—	$	—	$	162
Current liabilities	—		(139)		—		—		(139)
Net value	$	—	$	23	$	—	$	—	$	23

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, 2019 and 2018, credit valuation adjustments were not significant to the overall valuation of our fair value contracts. As a result, applicable fair value assets and liabilities are included in their entirety in the fair value hierarchy.

Nonrecurring Fair Value Measurements

Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of impairment. During the years ended December 31, 2019 and 2018, we had no long-lived assets that were subject to non-recurring fair value measurements.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Note 13. Income Taxes

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


	Year Ended December 31,
	2019		2018		2017
Current:
Federal	$	164	$	388	$	(1,418)
State	(375)		39		523
Total current	(211)		427		(895)
Deferred:
Federal	(2,063)		(752)		3,722
State	(22)		(184)		118
Total deferred	(2,085)		(936)		3,840
Total (provision for) benefit from income taxes	$	(2,296)	$	(509)	$	2,945

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A reconciliation of the (provision for) benefit from income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes was as follows for the periods indicated (in thousands):


	Year Ended December 31,
	2019			2018			2017

Pre-tax net book income (loss)	$	10,503		$	3,454		$	(3,427)

Statutory federal income tax (provision) benefit	$	(2,206)		$	(725)		$	1,165
State income tax (provision) benefit	(397)			(145)			736
Federal statutory depletion	—			—			153
Federal tax rate adjustment	—			—			2,007
Valuation allowance	—			—			(1,038)
Reverse valuation allowance	—			98			—
Return to provision adjustments	285			388			—
Other	22			(125)			(78)
Total (provision for) benefit from income taxes	$	(2,296)		$	(509)		$	2,945
Effective income tax rate ^{(1) (2)}	22		%	15		%	86		%

_______________

(1)Excluding the adjustment related to the federal tax rate change, the effective income tax rate for 2018 is 26 percent.

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

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


	December 31,
	2019		2018

Long-term deferred tax asset (liability):
Prepaid and other insurance	$	248	$	(170)
Property	(9,953)		(5,259)
Investments in unconsolidated affiliates	525		525
Valuation allowance related to investments in unconsolidated affiliates	(525)		(525)


Net operating loss	3,567		1,436
Other	(184)		(245)
Net long-term deferred tax liability	(6,322)		(4,238)
Net deferred tax liability	$	(6,322)	$	(4,238)

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.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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


			Earliest Open
			Tax Year

Federal			2015
Texas			2015
Louisiana			2016
Michigan			2015

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 related entirely to the remeasurement of deferred tax liabilities to the 21 percent tax rate.

Note 14. Stock-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 have been granted. 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 stock-based compensation to eligible employees and directors in June 2018. After giving effect to awards granted under the 2018 LTIP, forfeitures under the 2018 LTIP and achievement of performance factors through December 31, 2019, a total of 120,827 shares were available for issuance.

Compensation expense recognized in connection with equity-based awards was as follows for the periods indicated (in thousands):


	Year Ended December 31,
	2019		2018		2017

Compensation expense	$	478	$	255	$	—

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, 2019 and 2018, we had $23,600 and $9,500, respectively, of accrued dividend amounts for awards granted under the 2018 LTIP.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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
Granted ⁽³⁾	14,376	$	34.00
Vested	(7,188)	$	41.90
Forfeited	(2,139)	$	38.42
Restricted stock unit awards at December 31, 2019	18,782

____________________

(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.

(3)The aggregate grant date fair value of restricted stock unit awards issued during 2019 was $0.5 million based on a grant date market price of our common shares of $34.00 per share.

Unrecognized compensation cost associated with restricted stock unit awards was approximately $0.3 million at December 31, 2019. 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 1.4 years.

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. Performance goals are 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 is generally 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
Granted ⁽⁴⁾	8,094	$	34.00
Performance factor decrease ⁽³⁾	(7,312)	$	34.23
Vested	(416)	$	43.00
Forfeited	(1,545)	$	37.37
Performance share unit awards at December 31, 2019	2,787

____________________

(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 shares of $43.00 per share and assuming a performance factor of 100 percent.

(3)The performance factor for awards granted in 2018 was lowered to 47.5 percent based on a comparison of actual results for 2018 to performance goals. The performance factor for awards granted in 2019 was lowered to 0 percent based upon a comparison of actual results for 2019 to performance goals.

(4)The aggregate grant date fair value of performance share unit awards issued during 2019 was $0.3 million based on a grant date market price of our common shares of $34.00 per share and assuming a performance factor of 100 percent.

Unrecognized compensation cost associated with performance share unit awards was approximately $0.1 million at December 31, 2019. We expect to recognize the remaining compensation cost for these awards over a weighted-average period of 1.4 years.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 15. Supplemental Cash Flow Information

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


	Year Ended December 31,
	2019		2018		2017

Cash paid for interest	$	636	$	109	$	22
Cash paid for federal and state income taxes	234		787		459

Non-cash transactions:
Change in accounts payable related to property and equipment additions	(448)		1,685		70
Property and equipment acquired under finance leases	4,148		2,898		1,808
Issuance of common shares in asset acquisition (see Note 7)	392		—		—
Receivable for sale of property and equipment	952		—		—

See Note 16 for information related to non-cash transactions related to the adoption of the new lease accounting standard.

Note 16. Leases

Adoption of ASC 842

In February 2016, the Financial Accounting Standards Board issued Accounting Standards Codification 842, Leases (“ASC 842”), which requires lessees to recognize a right-of-use (“ROU”) asset and a corresponding lease liability for leases with terms longer than twelve months. We adopted the new standard effective January 1, 2019, using a modified retrospective transition method and applied 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 were not 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.

ASC 842 changes 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 recognized a ROU asset and a corresponding lease liability based on the present value of then existing operating lease obligations of approximately $11.4 million on our consolidated balance sheet. In addition, there are several key accounting policy elections that we made upon adoption of ASC 842 including:

•We did not recognize ROU assets and lease liabilities for short-term leases and instead record them in a manner similar to operating leases under ASC 840, Leases, 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 have also elected the non-lease component practical expedient 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.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Lease Recognition

We determine if an arrangement is a lease at inception. Operating leases are included in operating lease ROU assets, current liabilities and long-term operating lease liabilities in the consolidated balance sheets. Finance leases are included in property and equipment, current liabilities and long-term finance lease liabilities in the consolidated balance sheets.

ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. ROU assets and liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term. For determining the present value of lease payments, we use the discount rate implicit in the lease when readily determinable. As most of our leases do not provide an implicit rate, we use an incremental borrowing rate in determining the present value of lease payments that approximates the rate of interest we would have to pay to borrow on a collateralized basis over a similar term. At adoption, the ROU asset also includes any lease payment made and excludes lease incentives and initial direct costs. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that we will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term.

Our lease agreements do not contain any leases with variable lease payments (i.e., payments that depend on a percentage of sales of a lessee or payments that increase based upon an index such as CPI), residual value guarantees probable of being paid or material restrictive covenants. Lease agreements with lease and non-lease components are generally accounted for separately when practical. For leases where the lease and non-lease component are comingled and the non-lease component is determined to be insignificant when compared to the lease component, the lease and the non-lease components are treated as a single lease component for all asset classes.

We are a lessee in noncancellable (1) operating leases for office space, equipment and lease and terminal access contracts for tank storage and dock access for our crude oil marketing business, and (2) finance leases for tractors and tank storage and throughput for our crude oil marketing business. Leases with an initial term of twelve months or less are not recorded on the balance sheet. Our lease agreements have remaining lease terms ranging from one year to approximately eight years.

Some leases include one or more options to renew, with renewal terms that can extend the lease term for generally one year with exercise of lease renewal options being at our sole discretion as lessee.

The following table provides the components of lease expense the period indicated (in thousands):


	Year Ended
	December 31,
	2019
Finance lease cost:
Amortization of ROU assets	$	1,807
Interest on lease liabilities	295
Operating lease cost	2,933
Short-term lease cost	9,627
Total lease expense	$	14,662

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table provides supplemental cash flow and other information related to leases for the period indicated (in thousands):


	Year Ended
	December 31,
	2019
Cash paid for amounts included in measurement of lease liabilities:
Operating cash flows from operating leases ⁽¹⁾	$	2,934
Operating cash flows from finance leases	295
Financing cash flows from finance leases	1,697

ROU assets obtained in exchange for new lease liabilities:
Finance leases	4,148
Operating leases	12,006

______________

(1)Amount is included in Other operating activities on the consolidated cash flow statement.

The following table provides the lease terms and discount rates for the period indicated:


	Year Ended
	December 31,
	2019
Weighted-average remaining lease term (years):
Finance leases	3.03
Operating leases	4.78

Weighted-average discount rate:
Finance leases	4.9	%
Operating leases	5.0	%

The following table provides supplemental balance sheet information related to leases at the date indicated (in thousands):


	December 31,
	2019
Assets
Finance lease ROU assets ⁽¹⁾	$	6,384
Operating lease ROU assets	9,576

Liabilities
Current
Finance lease liabilities	2,167
Operating lease liabilities	2,252
Noncurrent
Finance lease liabilities	4,376
Operating lease liabilities	7,323

______________

(1)Amount is included in Property and equipment, net on the consolidated balance sheet.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table provides maturities of undiscounted lease liabilities at December 31, 2019 (in thousands):


	Finance		Operating
	Lease		Lease

2020	$	2,426	$	2,660
2021	2,426		2,256
2022	1,492		1,914
2023	642		1,776
2024	37		1,668
Thereafter	—		443
Total lease payments	7,023		10,717
Less: Interest	(480)		(1,142)
Present value of lease liabilities	6,543		9,575
Less: Current portion of lease obligation	(2,167)		(2,252)
Total long-term lease obligation	$	4,376	$	7,323

The following table provides maturities of undiscounted lease liabilities at December 31, 2018 (in thousands):


	Finance		Operating
	Lease		Lease

2019	$	1,052	$	4,242
2020	1,052		2,258
2021	1,052		2,107
2022	909		1,782
2023	451		1,495
Thereafter	—		1,488
Total lease payments	4,516		$	13,372
Less: Interest	(424)
Present value of lease liabilities	4,092
Less: Current portion of lease obligation	(883)
Total long-term lease obligation	$	3,209

Note 17. Commitments and Contingencies

Insurance Policies

We establish a liability under our automobile and workers’ compensation insurance policies for expected claims incurred but not reported on a monthly basis. As claims are paid, the liability is relieved. Our accruals for automobile and workers’ compensation claims are presented in the following table.

For periods prior to October 1, 2017, we pre-funded our estimated claims, 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 are presented in the following table. If the potential insurance claims do not further develop, the pre-funded premiums will be returned to us as a premium refund.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The amount of pre-funded insurance premiums left to cover potential future losses related to periods prior to October 1, 2017, and our accruals for automobile and workers’ compensation claims were as follows at the dates indicated (in thousands):


	December 31,
	2019		2018

Pre-funded premiums for losses incurred but not reported	$	168	$	427
Accrued automobile and workers’ compensation claims	2,956		2,246

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 individual medical claims exceeding a certain minimum threshold. In addition, we maintain $1.0 million of umbrella insurance coverage for annual aggregate medical claims exceeding approximately $9.6 million. Medical accrual amounts were as follows at the dates indicated (in thousands):


	December 31,
	2019		2018

Accrued medical claims	$	1,016	$	1,181

Legal Proceedings

On August 15, 2019, we received a notice from the Internal Revenue Service (the “IRS”) regarding a proposed penalty of approximately $1.2 million for our 2017 tax year information returns. The notice alleges that certain taxpayer identification numbers supplied to the IRS for our returns in 2017 were either missing or incorrect and that certain filings were late. We believe that the IRS’ claims are without merit and plan to pursue all available administrative and judicial remedies necessary to resolve this matter. Accordingly, we responded to the IRS on September 25, 2019 disputing the proposed penalty and requesting that the amount be waived, abated or a hearing held. We have not received a response at this time and are unable to predict when this matter might be resolved. We regularly assess the likelihood of adverse outcomes resulting from examinations such as this to determine the adequacy of our tax reserves. Since we are unable to predict whether the IRS will waive or abate the proposed penalty as requested, no liabilities have been accrued to date. We intend to vigorously defend our position in this matter. We believe that the final adjudication of this matter will not have a material impact on our consolidated financial position, results of operations or cash flows.

Litigation

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, results of operations or cash flows.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

At December 31, 2019, parental guaranteed obligations were approximately $44.3 million. Currently, neither AE nor any of its subsidiaries has any other types of guarantees outstanding that require liability recognition.

Note 18. Concentration of Credit Risk

We may incur credit risk to the extent our customers do not fulfill their obligations to us pursuant to contractual terms. Risks of nonpayment and nonperformance by our customers are a major consideration in our business, and our credit procedures and policies may not be adequate to sufficiently eliminate customer credit risk. Managing credit risk involves a number of considerations, such as the financial profile of the customer, the value of collateral held, if any, specific terms and duration of the contractual agreement, and the customer’s sensitivity to economic developments. We have established various procedures to manage credit exposure, including initial credit approval, credit limits and rights of offset. We also utilize letters of credit and guarantees to limit exposure.

Our largest customers consist of large multinational integrated crude oil companies and independent domestic refiners of crude oil. In addition, we transact business with independent crude oil producers, major chemical 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.

The following tables reflect the percentages of individual customer sales in excess of 10 percent of our consolidated revenues and individual customer receivables in excess of 10 percent of our total consolidated receivables for the periods indicated. We believe that a loss of any of the customers where we currently derive more than 10 percent of our revenues would not have a material adverse effect on our operations.


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,
2019		2018		2017		2019		2018		2017

37.3	%	27.3	%	22.8	%	16.6	%	18.4	%	19.1	%
11.4	%	14.1	%	17.1	%	12.6	%	11.9	%	15.0	%
				10.8	%					11.1	%
				10.7	%					10.4	%

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 19. 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, 2019
Revenues	$	445,168	$	484,433	$	450,307	$	431,339
Operating (losses) earnings	5,253		(643)		303		2,887
Net (losses) earnings	4,908		6		640		2,653

Earnings (losses) per share:
Basic net (losses) earnings per share	$	1.16	$	—	$	0.15	$	0.63
Diluted net (losses) earnings per share	$	1.16	$	—	$	0.15	$	0.63

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)

____________________

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

Note 20. 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. As discussed further in Note 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 sold 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, the period in which AREC was consolidated with us. We had no further exploration and development activity after April 30, 2017.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 period from January 1, 2017 through April 30, 2017 (in thousands):


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

Estimated Crude Oil and Natural Gas Reserves

The following information regarding estimates of our proved crude oil and natural gas reserves, substantially all of which were 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.

Proved developed and undeveloped reserves were as follows for the period from January 1, 2017 through April 30, 2017 (in thousands):


	Natural	Crude
	Gas	Oil
	(Mcf)	(Bbls)
Total proved reserves:
Beginning of period	4,214	187
Crude oil and natural gas reserves sold	(4,067)	(170)
Extensions, discoveries and other reserve additions	42	6
Production	(189)	(23)
End of period	—	—

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

We employed a third party petroleum consultant, Ryder Scott Company, to prepare our crude oil and natural gas reserve data estimates as of December 31, 2016. The firm of Ryder Scott has been well recognized within the industry for more than 50 years. As prescribed by the SEC, 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, all without escalation.

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 2016, 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 zero for the period from January 1, 2017 through April 30, 2017.

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 prices. 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 principal sources of changes in the standardized measure of discounted future net cash flows were as follows for the period from January 1, 2017 through April 30, 2017 (in thousands):



Beginning of period	$	2,260
Sale of crude oil and natural gas reserves	(2,732)
New field discoveries and extensions, net of future production costs	94
Sales of crude oil and natural gas produced, net of production costs	(476)
Accretion of discount	130
Production rate changes and other	(493)
Net change in income taxes	1,217
End of period	$	—

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ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 period from January 1, 2017 through April 30, 2017 (in thousands):



Revenues	$	1,427
Costs and expenses:
Production	(951)
Depreciation, depletion and amortization	(423)
Operating earnings before income taxes	53
Income tax expense	(19)
Operating earnings	$	34

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

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 Chief Executive Officer 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 Chief Executive Officer 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

(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 2019, 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, 2019

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 Chief Executive Officer 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 Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2019. In making this assessment, management used the criteria described in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on this assessment, management, including the Company’s Chief Executive Officer and Chief Financial Officer, concluded that internal control over financial reporting was effective as of December 31, 2019.

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”).

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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 6, 2020.


/s/ Kevin J. Roycraft						/s/ Tracy E. Ohmart
Kevin J. Roycraft						Tracy E. Ohmart
Chief Executive Officer						Chief Financial Officer

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. and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2019, 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, 2019, 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 sheets of the Company as of December 31, 2019 and 2018, the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2019, and the related notes (collectively, the consolidated financial statements), and our report dated March 6, 2020 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, 2019. 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.

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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 6, 2020

Item 9B. Other Information.

None.

PART III

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 2020 Annual Meeting of Shareholders (the “2020 Proxy Statement”), which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2019, under the headings “Election of Directors” and “Executive Officers” and is incorporated herein by reference.

Item 11. Executive Compensation.

The information required by this item will be set forth in our 2020 Proxy Statement, which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2019, 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.

The information required by this item will be set forth in our 2020 Proxy Statement, which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2019, under the heading “Voting Securities and Principal Holders Thereof” and is incorporated herein by reference.

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

The information required by this item will be set forth in our 2020 Proxy Statement, which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2019, under the headings “Transactions with Related Parties” and “Director Independence” and is incorporated herein by reference.

Item 14. Principal Accounting Fees and Services.

The information required by this item will be set forth in our 2020 Proxy Statement, which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2019, under the heading “Principal Accounting Fees and Services” and is incorporated herein by reference.

PART IV

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 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 .
3.2			Bylaws of Adams Resources & Energy, Inc., as amended (incorporated by reference to Exhibit 3(b) of the Annual Report on Form 10-K for the year ended December 31, 2012).
4.1*			Specimen common stock certificat e.
4.2			Credit and Security Agreement between GulfMark Energy, Inc., Adams Resources Marketing, Ltd., and Wells Fargo Bank, National Association dated August 27, 2009 (incorporated by reference to Exhibit 4(b) of the Quarterly Report on Form 10-Q for the period ended September 30, 2009).
4.3*			Descript ion of Securities Registered Under S ection 12 of the Ex ch ange Act.
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			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 (incorporated by reference to Exhibit 10.4 of the Annual Report on Form 10-K for the year ended December 31, 2017).
10.3+			Adams Resources & Energy, Inc. 2018 Long-Term Incentive Plan, effective as of May 8, 2018 (incorporated by reference to Exhibit 10.1 of the Quarterly Report on Form 10-Q for the period ended March 31, 2018).
10.4+			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 of the Quarterly Report on Form 10-Q for the period ended June 30, 2018).

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Exhibit Number			Exhibit


10.5+			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 of the Quarterly Report on Form 10-Q for the period ended June 30, 2018).
10.6+			Form of Employee Performance Share Unit Award Agreement for 2018 Awards under the Adams Resources & Energy, Inc. 2018 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 of the Quarterly Report on Form 10-Q for the period ended June 30, 2018).
10.7+*			Form of Employee Performance Share Unit Award Agreement for 201 9 Awards under the Adams Resources & Energy, Inc. 2018 Long-Term Incentive Plan .
10.8			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 of the Quarterly Report on Form 10-Q for the period ended September 30, 2018).
10.9			Asset Purchase Agreement, dated as of April 10, 2019, between EH Transport, Inc. and EH Trucking, Inc. and Edis J. Hobson, as sellers, and Service Transport Company, as purchaser (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed on May 6, 2019).
14.1			Adams Resources & Energy, Inc. and Subsidiaries’ Code of Ethics (incorporated by reference to Exhibit 3(d) of the Annual Report on Form 10-K for the year ended December 31, 2002).
21*			Subsidiaries of the registrant.
23.1*			Consent of KPMG LLP.
23.2*			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 .
99.1			Ryder Scott Company Report as of December 31, 2016 (incorporated by reference to Exhibit 99.1 of the Annual Report on Form 10-K for the year ended December 31, 2016).
101.CAL*			Inline XBRL Calculation Linkbase Document
101.DEF*			Inline XBRL Definition Linkbase Document
101.INS*			Inline 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*			Inline XBRL Labels Linkbase Document
101.PRE*			Inline XBRL Presentation Linkbase Document
101.SCH*			Inline XBRL Schema Document
104*			Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)

_______________________

* Filed or 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.

Not applicable.

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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 6, 2020.


						ADAMS RESOURCES & ENERGY, INC.
						(Registrant)


			By:			/s/ Kevin J. Roycraft
						Kevin J. Roycraft
						Chief Executive Officer
						(Principal Executive Officer)

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

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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 6, 2020.


Signature						Title

/s/ Townes G. Pressler						Director and Chairman of the Board
Townes G. Pressler

/s/ Murray E. Brasseux						Director
Murray E. Brasseux

/s/ Dennis E. Dominic						Director
Dennis E. Dominic

/s/ Michelle A. Earley						Director
Michelle A. Earley

/s/ Richard C. Jenner						Director
Richard C. Jenner

/s/ John O. Niemann Jr.						Director
John O. Niemann Jr.

/s/ W.R. Scofield						Director
W.R. Scofield