Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Mar. 01, 2019 | Jun. 29, 2018 | |
Document and Entity Information [Abstract] | |||
Entity Registrant Name | ADAMS RESOURCES & ENERGY, INC. | ||
Entity Central Index Key | 2,178 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Accelerated Filer | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2018 | ||
Document Fiscal Year Focus | 2,018 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Entity Common Stock, Shares Outstanding | 4,217,596 | ||
Entity Emerging Growth Company | false | ||
Entity Small Business | true | ||
Entity Shell Company | false | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 92,505,083 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Current assets: | ||
Cash and cash equivalents | $ 117,066 | $ 109,393 |
Accounts receivable, net of allowance for doubtful accounts of $153 and $303, respectively | 85,197 | 121,353 |
Accounts receivable – related party | 425 | 0 |
Inventory | 22,779 | 12,192 |
Derivative assets | 162 | 166 |
Income tax receivable | 2,404 | 1,317 |
Prepayments and other current assets | 1,557 | 1,264 |
Total current assets | 229,590 | 245,685 |
Property and equipment, net | 44,623 | 29,362 |
Investment in unconsolidated affiliate | 0 | 425 |
Cash deposits and other assets | 4,657 | 7,232 |
Total assets | 278,870 | 282,704 |
Current liabilities: | ||
Accounts payable | 116,068 | 124,706 |
Accounts payable – related party | 29 | 5 |
Derivative liabilities | 139 | 145 |
Current portion of capital lease obligations | 883 | 338 |
Other current liabilities | 6,148 | 4,404 |
Total current liabilities | 123,267 | 129,598 |
Other long-term liabilities: | ||
Asset retirement obligations | 1,525 | 1,273 |
Capital lease obligations | 3,209 | 1,351 |
Deferred taxes and other liabilities | 4,271 | 3,363 |
Total liabilities | 132,272 | 135,585 |
Commitments and contingencies (Note 15) | ||
Shareholders’ equity: | ||
Preferred stock – $1.00 par value, 960,000 shares authorized, none outstanding | 0 | 0 |
Common stock – $0.10 par value, 7,500,000 shares authorized, 4,217,596 shares outstanding | 422 | 422 |
Contributed capital | 11,948 | 11,693 |
Retained earnings | 134,228 | 135,004 |
Total shareholders’ equity | 146,598 | 147,119 |
Total liabilities and shareholders’ equity | $ 278,870 | $ 282,704 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Statement of Financial Position [Abstract] | ||
Allowance for doubtful accounts | $ 153 | $ 303 |
Preferred stock - par value (in dollars per share) | $ 1 | $ 1 |
Preferred stock - shares authorized (in shares) | 960,000 | 960,000 |
Preferred stock - outstanding (in shares) | 0 | 0 |
Common stock - par value (in dollars per share) | $ 0.10 | $ 0.10 |
Common stock - shares authorized (in shares) | 7,500,000 | 7,500,000 |
Common stock - shares outstanding (in shares) | 4,217,596 | 4,217,596 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Revenues: | |||
Total revenues | $ 1,750,213 | $ 1,322,060 | $ 1,099,540 |
Costs and expenses: | |||
Oil and natural gas property impairments | 0 | 3 | 313 |
General and administrative | 8,937 | 9,707 | 10,410 |
Depreciation, depletion and amortization | 10,654 | 13,599 | 18,792 |
Total costs and expenses | 1,748,805 | 1,320,558 | 1,093,486 |
Operating earnings (losses) | 1,408 | 1,502 | 6,054 |
Other income (expense): | |||
Loss on deconsolidation of subsidiary (Note 4) | 0 | (3,505) | 0 |
Impairment of investment in unconsolidated affiliate | 0 | (2,500) | 0 |
Interest income | 2,155 | 1,103 | 582 |
Interest expense | (109) | (27) | (2) |
Total other income (expense), net | 2,046 | (4,929) | 580 |
(Losses) earnings before income taxes and investment in unconsolidated affiliate | 3,454 | (3,427) | 6,634 |
Income tax (provision) benefit: | |||
Current | 427 | (895) | (2,778) |
Deferred | (936) | 3,840 | 87 |
Income tax benefit (provision) | (509) | 2,945 | (2,691) |
Earnings (losses) from continuing operations | 2,945 | (482) | 3,943 |
Losses from investments in unconsolidated affiliates, net of tax benefit of $—, $—, and $770, respectively | 0 | 0 | (1,430) |
Net (losses) earnings | $ 2,945 | $ (482) | $ 2,513 |
Basic earnings (losses) per common share: | |||
From continuing operations (in dollars per share) | $ 0.70 | $ (0.11) | $ 0.94 |
From investment in unconsolidated affiliate (in dollars per share) | 0 | 0 | (0.34) |
Basic net (losses) earnings per common share (in dollars per share) | 0.70 | (0.11) | 0.60 |
Diluted net (losses) earnings per common share (in dollars per share) | 0.70 | (0.11) | 0.60 |
Dividends per common share (in dollars per share) | $ 0.88 | $ 0.88 | $ 0.88 |
Marketing | |||
Revenues: | |||
Total revenues | $ 1,694,437 | $ 1,267,275 | $ 1,043,775 |
Costs and expenses: | |||
Cost and expenses | 1,681,045 | 1,247,763 | 1,016,733 |
Transportation | |||
Revenues: | |||
Total revenues | 55,776 | 53,358 | 52,355 |
Costs and expenses: | |||
Cost and expenses | 48,169 | 48,538 | 45,154 |
Oil and natural gas | |||
Revenues: | |||
Total revenues | 0 | 1,427 | 3,410 |
Costs and expenses: | |||
Cost and expenses | $ 0 | $ 948 | $ 2,084 |
CONSOLIDATED STATEMENTS OF OP_2
CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Statement [Abstract] | |||
Tax benefit from investments in unconsolidated affiliates | $ 0 | $ 0 | $ 770 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Operating activities: | |||
Net (losses) earnings | $ 2,945 | $ (482) | $ 2,513 |
Adjustments to reconcile net (losses) earnings to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 10,654 | 13,599 | 18,792 |
Gains on sale of property | (1,240) | (594) | (1,966) |
Impairment of oil and natural gas properties | 0 | 3 | 313 |
Provision for doubtful accounts | (150) | 78 | 19 |
Share-based compensation expense | 255 | 0 | 0 |
Deferred income taxes | 936 | (3,840) | (857) |
Net change in fair value contracts | (2) | 27 | (243) |
Losses from equity investment | 0 | 0 | 468 |
Impairment of investments in unconsolidated affiliates | 0 | 2,500 | 1,732 |
Loss on deconsolidation of subsidiary (Note 4) | 0 | 3,505 | 0 |
Changes in assets and liabilities: | |||
Accounts receivable | 36,350 | (34,935) | (15,368) |
Accounts receivable/payable, affiliates | 24 | 271 | 0 |
Inventories | (10,587) | 878 | (5,399) |
Income tax receivable | (1,087) | 1,418 | (148) |
Prepayments and other current assets | (293) | 831 | 492 |
Accounts payable | (10,252) | 44,790 | 6,984 |
Accrued liabilities | 1,744 | (991) | 52 |
Other | 1,717 | (962) | (440) |
Net cash provided by operating activities | 31,014 | 26,096 | 6,944 |
Investing activities: | |||
Property and equipment additions | (11,731) | (2,644) | (8,484) |
Asset acquisition | (10,272) | 0 | 0 |
Proceeds from property sales | 2,038 | 720 | 3,706 |
Proceeds from sales of AREC assets | 0 | 2,775 | 0 |
Investments in unconsolidated affiliates | 0 | 0 | (4,700) |
Insurance and state collateral (deposits) refunds | 830 | (1,067) | 1,710 |
Net cash used in investing activities | (19,135) | (216) | (7,768) |
Financing activities: | |||
Principal repayments of capital lease obligations | (495) | (118) | 0 |
Dividends paid on common stock | (3,711) | (3,711) | (3,711) |
Net cash used in financing activities | (4,206) | (3,829) | (3,711) |
Increase (decrease) in cash and cash equivalents | 7,673 | 22,051 | (4,535) |
Cash and cash equivalents at beginning of period | 109,393 | 87,342 | 91,877 |
Cash and cash equivalents at end of period | $ 117,066 | $ 109,393 | $ 87,342 |
CONSOLIDATED STATEMENTS OF SHAR
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - USD ($) $ in Thousands | Total | Common Stock | Contributed Capital | Retained Earnings |
Beginning balance at Dec. 31, 2015 | $ 152,510 | $ 422 | $ 11,693 | $ 140,395 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Net earnings (losses) | 2,513 | 2,513 | ||
Dividends declared: | ||||
Common stock, $0.88/share | (3,711) | (3,711) | ||
Ending balance at Dec. 31, 2016 | 151,312 | 422 | 11,693 | 139,197 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Net earnings (losses) | (482) | (482) | ||
Dividends declared: | ||||
Common stock, $0.88/share | (3,711) | (3,711) | ||
Ending balance at Dec. 31, 2017 | 147,119 | 422 | 11,693 | 135,004 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Net earnings (losses) | 2,945 | 2,945 | ||
Stock-based compensation expense | 255 | 255 | ||
Dividends declared: | ||||
Common stock, $0.88/share | (3,711) | (3,711) | ||
Awards under LTIP, $0.44/share | (10) | (10) | ||
Ending balance at Dec. 31, 2018 | $ 146,598 | $ 422 | $ 11,948 | $ 134,228 |
CONSOLIDATED STATEMENTS OF SH_2
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (Parenthetical) | 12 Months Ended |
Dec. 31, 2018$ / shares | |
Statement of Stockholders' Equity [Abstract] | |
Dividends per common share (in dollars per share) | $ 0.88 |
Awards under LTIP (in dollars per share) | $ 0.44 |
Organization and Basis of Prese
Organization and Basis of Presentation | 12 Months Ended |
Dec. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Basis of Presentation | Organization and Basis of Presentation Organization Adams Resources & Energy, Inc. (“AE”) is a publicly traded Delaware corporation organized in 1973, the common shares of which are listed on the NYSE 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, 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. Use of Estimates The preparation of our financial statements in conformity with GAAP requires management to use estimates and assumptions that affect the reported amount of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We base our estimates and judgments on historical experience and on various other assumptions and information we believe to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the operating environment changes. While we believe the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies We adhere to the following significant accounting policies in the preparation of our consolidated financial statements. Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable associated with crude oil marketing activities comprise approximately 90 percent of our total receivables, and industry practice requires payment for these sales to occur within 20 days of the end of the month following a transaction. Our customer makeup, credit policies and the relatively short duration of receivables mitigate the uncertainty typically associated with receivables management. An allowance for doubtful accounts is provided where appropriate. Our allowance for doubtful accounts is determined based on specific identification combined with a review of the general status of the aging of all accounts. We consider the following factors in our review of our allowance for doubtful accounts: (i) historical experience with customers, (ii) the perceived financial stability of customers based on our research, (iii) the levels of credit we grant to customers, and (iv) the duration of the receivable. We may increase the allowance for doubtful accounts in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties. On a routine basis, we review estimates associated with the allowance for doubtful accounts to ensure that we have recorded sufficient reserves to cover potential losses. See Note 16 for further information regarding credit risk. The following table presents our allowance for doubtful accounts activity for the periods indicated (in thousands): December 31, 2018 2017 2016 Balance at beginning of period $ 303 $ 225 $ 206 Charges to costs and expenses 43 137 100 Deductions (193) (59) (81) Balance at end of period $ 153 $ 303 $ 225 Cash and Cash Equivalents Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than three months from the date of purchase. Cash and cash equivalents are maintained with major financial institutions, and deposit amounts may exceed the amount of federally backed insurance provided. While we regularly monitor the financial stability of these institutions, cash and cash equivalents ultimately remain at risk subject to the financial viability of these institutions. Derivative Instruments In the normal course of our operations, our crude oil marketing segment purchases and sells crude oil. We seek to profit by procuring the commodity as it is produced and then delivering the product to the end users or the intermediate use marketplace. As typical for the industry, these transactions are made pursuant to the terms of forward month commodity purchase and/or sale contracts. Some of these contracts meet the definition of a derivative instrument, and therefore, we account for these contracts at fair value, unless the normal purchase and sale exception is applicable. These types of underlying contracts are standard for the industry and are the governing document for our crude oil marketing segment. None of our derivative instruments have been designated as hedging instruments. Earnings Per Share Basic earnings (losses) per share is computed by dividing our net earnings (losses) by the weighted average number of shares of common stock outstanding during the period. Diluted earnings (losses) per share is computed by giving effect to all potential shares of common stock outstanding, including our stock related to unvested restricted stock unit awards. Unvested restricted stock unit awards granted under the Adams Resources & Energy, Inc. 2018 Long-Term Incentive Plan (“2018 LTIP”) are not considered to be participating securities as the holders of these shares do not have non-forfeitable dividend rights in the event of our declaration of a dividend for common shares (see Note 13 for further discussion). A reconciliation of the calculation of basic and diluted earnings (losses) per share is as follows (in thousands, except per share data): Year Ended December 31, 2018 2017 2016 Earnings (losses) per share – numerator: Earnings (losses) from continuing operations $ 2,945 $ (482) $ 3,943 Losses from investment in unconsolidated affiliate, net of tax — — (1,430) Net (losses) earnings $ 2,945 $ (482) $ 2,513 Denominator: Basic weighted average number of shares outstanding 4,218 4,218 4,218 Basic earnings (losses) per share: From continuing operations $ 0.70 $ (0.11) $ 0.94 From investment in unconsolidated affiliate — — (0.34) Basic earnings (losses) per share $ 0.70 $ (0.11) $ 0.60 Diluted earnings (losses) per share: Diluted weighted average number of shares outstanding: Common shares 4,218 4,218 4,218 Restricted stock unit awards (1) — — — Performance share unit awards ( 2 ) — — — Total 4,218 4,218 4,218 Diluted earnings (losses) per share: From continuing operations $ 0.70 $ (0.11) $ 0.94 From investment in unconsolidated affiliate — — (0.34) Diluted earnings (losses) per share $ 0.70 $ (0.11) $ 0.60 ________________________ (1) The dilutive effect of restricted stock unit awards for the year ended December 31, 2018 is de minimis. (2) The dilutive effect of performance share awards will be included in the calculation of diluted earnings per share when the performance share award performance conditions have been achieved. Employee Benefits We maintain a 401(k) savings plan for the benefit of our employees. We do not maintain any other pension or retirement plans. Our 401(k) plan contributory expenses were as follows for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Contributory expenses $ 808 $ 734 $ 757 Fair Value Measurements The carrying amounts reported in the consolidated balance sheets for cash and cash equivalents, accounts receivable and accounts payable approximates fair value because of the immediate or short-term maturity of these financial instruments. Marketable securities are recorded at fair value based on market quotations from actively traded liquid markets. Our fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk, in the principal market of the asset or liability at a specified measurement date. Recognized valuation techniques employ inputs such as contractual prices, quoted market prices or rates, operating costs, discount factors and business growth rates. These inputs may be either readily observable, corroborated by market data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the highest extent possible. Accordingly, we utilize valuation techniques (such as the market approach) that maximize the use of observable inputs and minimize the use of unobservable inputs. A three-tier hierarchy has been established that classifies fair value amounts recognized in the financial statements based on the observability of inputs used to estimate such fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy. 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 11 for further information). Fair value estimates are based on assumptions that market participants would use when pricing an asset or liability, and we use a fair value hierarchy of three levels that prioritizes the information used to develop those assumptions. Currently, for all items presented herein, we utilize a market approach to valuing our contracts. On a contract by contract, forward month by forward month basis, we obtain observable market data for valuing our contracts. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data. Impairment Testing for Long-Lived Assets Long-lived assets (primarily property and equipment) are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written-down to their estimated fair values. The carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset’s carrying value exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge equal to the excess of the asset’s carrying value over its estimated fair value is recorded. Fair value is defined as the price that would be received to sell an asset or be paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. We measure fair value using market price indicators or, in the absence of such data, appropriate valuation techniques. See Note 11 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 12 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, 2017 and 2016. Letter of Credit Facility We maintain a Credit and Security Agreement with Wells Fargo Bank, National Association to provide for the issuance of up to $60 million in stand-by letters of credit primarily used to support crude oil purchases within our crude oil marketing segment and for other purposes. We are currently using the letter of credit facility for letters of credit related to our insurance program. This facility is collateralized by the eligible accounts receivable within the crude oil marketing segment and expires on August 30, 2019. The issued stand-by letters of credit are canceled as the underlying purchase obligations are satisfied by cash payment when due. The letter of credit facility places certain restrictions on GulfMark Energy, Inc., one of our wholly owned subsidiaries. These restrictions include the maintenance of positive net earnings excluding inventory valuation changes, as defined, among other restrictions. We are currently in compliance with all such financial covenants. However, per the terms of our letter of credit agreement, we were in default of certain nonfinancial covenants at December 31, 2018, and we obtained a waiver whereby the creditor will not exercise any of its rights or remedies. At December 31, 2018 and 2017, we had $4.6 million and $2.2 million, respectively, of letters of credit outstanding under this facility. 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. We capitalize interest costs, if any, incurred in connection with major capital expenditures while the asset is in its construction phase. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s estimated useful life as a component of depreciation expense. When capitalized interest is recorded, it reduces interest expense. Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related long-lived asset. ARO amounts are measured at their estimated fair value using expected present value techniques. Over time, the ARO liability is accreted to its present value (through accretion expense), and the capitalized amount is depreciated over the remaining useful life of the related long-lived asset. We will incur a gain or loss to the extent that our ARO liabilities are not settled at their recorded amounts. See Note 6 for additional information regarding our property and equipment and AROs. Recent Accounting Pronouncements Lease accounting standard . In February 2016, the Financial Accounting Standards Board issued Accounting Standards Codification (“ASC”) 842, Leases (“ASC 842”), which requires substantially all leases to be recorded on the balance sheet. We adopted the new standard on January 1, 2019 and expect to apply it to all existing lease contracts as of January 1, 2019. We also plan to apply it to all new leases entered into after January 1, 2019. ASC 842 supersedes existing lease accounting guidance under ASC 840, Leases (“ASC 840”). We expect to adopt the new standard using the modified retrospective approach and apply certain optional transitional practical expedients. We elected an optional transition method that allowed application of the new standard at the adoption date and the recognition of a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption with no adjustment to previously reported results. In accordance with this approach, our consolidated financial statements for periods prior to January 1, 2019 will not be revised to reflect the new lease accounting guidance. We also elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allowed the carry forward of historical lease classification. We did not elect the practical expedient related to hindsight. ASC 842 will result in changes to the way our operating leases are recorded, presented and disclosed in our consolidated financial statements. Upon adoption of ASC 842 on January 1, 2019, we expect to recognize a right-of-use (“ROU”) asset and a corresponding lease liability based on the present value of then existing operating lease obligations. In addition, there are several key accounting policy elections that we will make upon adoption of ASC 842 including: • We will not recognize ROU assets and lease liabilities for short-term leases and will instead record them in a manner similar to operating leases under ASC 840 lease accounting guidelines. A short term lease is one with a maximum lease term of 12 months or less and does not include a purchase option or renewal option the lessee is reasonably certain to exercise. • We will also elect the non-lease component for any asset class where lease and non-lease components are comingled and the non-lease component is determined to be insignificant when compared to the lease component. Upon adoption of this new guidance, we expect to recognize a ROU asset and lease liability for operating leases of approximately $11.4 million on our consolidated balance sheet based upon discounted amounts on January 1, 2019. Stock-Based Compensation |
Revenue Recognition
Revenue Recognition | 12 Months Ended |
Dec. 31, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Revenue Recognition | 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. 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. 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 period indicated (in thousands): Year Ended December 31, 2018 Reporting Segments Marketing Transportation Total Revenues from contracts with customers $ 1,580,997 $ 55,776 $ 1,636,773 Other (1) 113,440 — 113,440 Total revenues $ 1,694,437 $ 55,776 $ 1,750,213 Timing of revenue recognition: Goods transferred at a point in time $ 1,580,997 $ — $ 1,580,997 Services transferred over time — 55,776 55,776 Total revenues from contracts with customers $ 1,580,997 $ 55,776 $ 1,636,773 _______________ (1) Other crude oil marketing revenues are recognized under ASC 815, Derivatives and Hedging , and ASC 845, Nonmonetary Transactions – Purchases and Sales of Inventory with the Same Counterparty . Other Marketing Revenue Certain of the commodity purchase and sale contracts utilized by our crude oil marketing segment qualify as derivative instruments with certain specifically identified contracts also designated as trading activity. From the time of contract origination, these contracts are marked-to-market and recorded on a 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, 2018 2017 2016 Revenue gross-up $ 448,846 $ 203,095 $ 314,270 |
Subsidiary Bankruptcy, Deconsol
Subsidiary Bankruptcy, Deconsolidation and Sale | 12 Months Ended |
Dec. 31, 2018 | |
Reorganizations [Abstract] | |
Subsidiary Bankruptcy, Deconsolidation and Sale | Subsidiary Bankruptcy, Deconsolidation and Sale Bankruptcy Filing, Deconsolidation and Sale On April 21, 2017, AREC filed a voluntary petition in the Bankruptcy Court seeking relief under the Bankruptcy Code. AREC operated its business and managed its properties as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and order of the Bankruptcy Court. As a result of AREC’s bankruptcy filing, AE ceded its authority to the Bankruptcy Court, and AE management could not carry on AREC activities in the ordinary course of business without Bankruptcy Court approval. AE managed the day-to-day operations of AREC, but did not have discretion to make significant capital or operating budgetary changes or decisions or to purchase or sell significant assets, as AREC’s material decisions were subject to review and approval by the Bankruptcy Court. For these reasons, we concluded that AE lost control of AREC, and no longer had significant influence over AREC during the pendency of the bankruptcy. Therefore, we deconsolidated AREC effective with the filing of the Chapter 11 bankruptcy in April 2017. In order to deconsolidate AREC, the carrying values of the assets and liabilities of AREC were removed from our consolidated balance sheet as of April 30, 2017, and we recorded our investment in AREC at its estimated fair value of approximately $5.0 million. We determined the fair value of our investment based upon bids we received in an auction process (see Note 1 for further discussion). We also determined that the estimated fair value of our investment in AREC was expected to be lower than its net book value immediately prior to the deconsolidation. As a result, during the second quarter of 2017, we recorded a non-cash charge of approximately $1.6 million associated with the deconsolidation of AREC, which reflected the excess of the net assets of AREC over its estimated fair value based on the expected sales transaction price of approximately $5.0 million, net of estimated transaction costs. Subsequent to the deconsolidation of AREC, we accounted for our investment in AREC using the cost method of accounting because AE did not exercise significant influence over the operations of AREC due to the Chapter 11 filing. On August 1, 2017, a hearing was held before the Bankruptcy Court seeking approval of asset purchase and sales agreements under Section 363 of the Bankruptcy Code with three unaffiliated parties to purchase AREC’s crude oil and natural gas assets for aggregate cash proceeds of approximately $5.2 million. The Bankruptcy Court approved the asset purchase and sales agreements, and we closed on the sales of these assets during the third quarter of 2017. In October 2017, AREC submitted its liquidation plan to the Bankruptcy Court for approval. In connection with the sales of these assets and submission of the liquidation plan, we recognized an additional loss of $1.9 million during the third quarter of 2017, which represents the difference between the proceeds we 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, and we expect final settlement and liquidation to occur during 2019. At December 31, 2018, we have a receivable from AREC of approximately $0.4 million related to the final settlement of AREC. DIP Financing – Related Party Relationship |
Prepayments and Other Current A
Prepayments and Other Current Assets | 12 Months Ended |
Dec. 31, 2018 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |
Prepayments and Other Current Assets | Prepayments and Other Current Assets The components of prepayments and other current assets were as follows at the dates indicated (in thousands): December 31, 2018 2017 Insurance premiums $ 677 $ 425 Rents, licenses and other 880 839 Total $ 1,557 $ 1,264 |
Property and Equipment
Property and Equipment | 12 Months Ended |
Dec. 31, 2018 | |
Property, Plant and Equipment [Abstract] | |
Property and Equipment | Property and Equipment The historical costs of our property and equipment and related accumulated depreciation balances were as follows at the dates indicated (in thousands): Estimated Useful Life December 31, in Years 2018 2017 Tractors and trailers (1) 5 – 6 $ 96,523 $ 88,065 Field equipment 2 – 5 20,725 18,490 Buildings 5 – 39 15,746 15,727 Office equipment 2 – 5 1,863 1,929 Land 1,790 1,790 Construction in progress 2,794 275 Total 139,441 126,276 Less accumulated depreciation (94,818) (96,914) Property and equipment, net $ 44,623 $ 29,362 ______________ (1) Amounts include tractors held under capital leases in our crude oil marketing segment. At December 31, 2018 and 2017, gross property and equipment associated with assets held under capital leases were $4.7 million and $1.8 million, respectively. Accumulated amortization associated with assets held under capital leases were $0.7 million and $0.1 million at December 31, 2018 and 2017, respectively (see Note 15 for further information). Components of depreciation, depletion and amortization expense were as follows for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Depreciation, depletion and amortization, excluding amounts under capital leases $ 10,112 $ 13,478 $ 18,792 Amortization of property and equipment under capital leases 542 121 — Total depreciation, depletion and amortization $ 10,654 $ 13,599 $ 18,792 Asset Acquisition On October 1, 2018, we completed the purchase of a trucking company for $10.0 million that owned approximately 113 tractors and 126 trailers operating in the Red River area in North Texas and South Central Oklahoma. This acquisition is included in our crude oil marketing segment from the date of the acquisition. We incurred approximately $0.3 million of acquisition costs in connection with this acquisition, which was included in the allocation of the purchase price to the assets acquired. The purchase price of approximately $10.3 million was allocated on October 1, 2018 as follows (in thousands): Tractors $ 4,799 Trailers 4,901 Field equipment 381 Materials and supplies 191 Total $ 10,272 Gains on Sales of Assets We sold certain used trucks and equipment and recorded net pre-tax gains as follows for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Gains on sales of used trucks and equipment $ 1,240 $ 594 $ 1,966 Crude Oil and Natural Gas Exploration and Production Assets Our subsidiary that owned the upstream crude oil and natural gas exploration and production assets was deconsolidated effective with its bankruptcy filing in April 2017 and subsequently accounted for as a cost method investment (see Note 4). These upstream crude oil and natural gas exploration and production assets were sold during the third quarter of 2017. We have no further interest in these assets. Impairment provisions included in upstream crude oil and natural gas exploration and production segment operating losses were as follows for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Producing property impairments $ — $ — $ 30 Non-producing property impairments — 3 283 Total crude oil and natural gas impairments $ — $ 3 $ 313 Asset Retirement Obligations We record AROs for the estimated retirement costs associated with certain tangible long-lived assets. The estimated fair value of AROs are recorded in the period in which they are incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the asset. If the liability is settled for an amount other than the recorded amount, an increase or decrease to expense is recognized. A summary of our AROs is presented as follows for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 ARO liability beginning balance $ 1,273 $ 2,329 $ 2,469 Liabilities incurred 252 18 162 Accretion of discount 36 58 92 Liabilities settled (36) (261) (394) Deconsolidation of subsidiary (1) — (871) — ARO liability ending balance $ 1,525 $ 1,273 $ 2,329 _______________ |
Cash Deposits and Other Assets
Cash Deposits and Other Assets | 12 Months Ended |
Dec. 31, 2018 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |
Cash Deposits and Other Assets | Cash Deposits and Other Assets Components of cash deposits and other assets were as follows at the dates indicated (in thousands): December 31, 2018 2017 Amounts associated with liability insurance program: Insurance collateral deposits (1) $ 1,453 $ 3,767 Excess loss fund 1,916 2,284 Accumulated interest income 788 814 Other amounts: State collateral deposits 57 57 Materials and supplies 443 273 Other — 37 Total $ 4,657 $ 7,232 _______________ (1) During 2018, we issued a letter of credit of approximately $4.2 million to the insurance companies in connection with our liability insurance program, and as a result, our cash collateral deposit was refunded to us. |
Investments in Unconsolidated A
Investments in Unconsolidated Affiliates | 12 Months Ended |
Dec. 31, 2018 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Investments in Unconsolidated Affiliates | Investments in Unconsolidated Affiliates At December 31, 2018, we had no remaining balances in our medical-related investments. We currently do not have any plans to pursue additional medical-related investments. Bencap In December 2015, we formed a new wholly owned subsidiary, Adams Resources Medical Management, Inc. (“ARMM”), and in January 2016, ARMM acquired a 30 percent member interest in Bencap LLC (“Bencap”) for a $2.2 million cash payment. Bencap provides medical insurance brokerage and medical claims auditing services to employers utilizing ERISA governed employee benefit plans. We accounted for this investment under the equity method of accounting. Under the terms of the investment agreement, Bencap had the option to request borrowings from us of up to $1.5 million (on or after December 5, 2016 but before October 31, 2018) that we were required to provide or forfeit our 30 percent member interest. During 2016, 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, 2018, we had no further ownership interest in Bencap. VestaCare In April 2016, ARMM acquired an approximate 15 percent equity interest (less than 3 percent voting interest) in VestaCare, Inc., a California corporation (“VestaCare”), for a $2.5 million cash payment. VestaCare provides an array of software as a service (SaaS) electronic payment technologies to medical providers, payers and patients including VestaCare’s most recent product offering, VestaPay™. VestaPay™ allows medical care providers to structure fully automated and dynamically updating electronic payment plans for their patients. We account for this investment under the cost method of accounting. During 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, 2018, we continue to own an approximate 15 percent equity interest in VestaCare. AREC |
Segment Reporting
Segment Reporting | 12 Months Ended |
Dec. 31, 2018 | |
Segment Reporting [Abstract] | |
Segment Reporting | Segment Reporting Historically, our three reporting segments have been: (i) crude oil marketing, transportation and storage, (ii) tank truck transportation of liquid chemicals and dry bulk, and (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 is accounted for under the cost method of accounting. AREC remained a reportable segment until its deconsolidation, effective April 30, 2017. Information concerning our various business activities was follows for the periods indicated (in thousands): Reporting Segments Marketing Transportation Oil and Gas and Other Total Year Ended December 31, 2018 Revenues $ 1,694,437 $ 55,776 $ — $ 1,750,213 Segment operating (losses) earnings (1) 7,008 3,337 — 10,345 Depreciation, depletion and amortization 6,384 4,270 — 10,654 Property and equipment additions (3) (4) 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 (1) (2) 11,700 (544) 53 11,209 Depreciation, depletion and amortization 7,812 5,364 423 13,599 Property and equipment additions (3) 468 351 1,825 2,644 Year Ended December 31, 2016 Revenues $ 1,043,775 $ 52,355 $ 3,410 $ 1,099,540 Segment operating (losses) earnings (1) 17,045 (48) (533) 16,464 Depreciation, depletion and amortization 9,997 7,249 1,546 18,792 Property and equipment additions 1,321 6,868 295 8,484 _________________ (1) Our crude oil marketing segment’s operating earnings included inventory valuation losses of $5.4 million for the year ended December 31, 2018, and inventory liquidation gains of $3.3 million and $8.2 million for the years ended December 31, 2017 and 2016, respectively. (2) Segment operating (losses) earnings includes approximately $0.4 million of costs related to a voluntary early retirement program that was implemented in August 2017. (3) Our crude oil marketing segment’s property and equipment additions do not include approximately $2.9 million and $1.8 million of tractors acquired during the years ended December 31, 2018 and 2017, respectively, under capital leases. See Note 15 for further information. (4) During the year ended December 31, 2018, we had $13 thousand of property and equipment additions for leasehold improvements at our corporate headquarters, which is not attributed or allocated to any of our reporting segments. Segment operating earnings reflect revenues net of operating costs and depreciation, depletion and amortization expense and are reconciled to earnings (losses) before income taxes and investment in unconsolidated affiliate, as follows for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Segment operating earnings $ 10,345 $ 11,209 $ 16,464 General and administrative (1) (8,937) (9,707) (10,410) Operating earnings (losses) 1,408 1,502 6,054 Loss on deconsolidation of subsidiary — (3,505) — Impairment of investment in unconsolidated affiliate — (2,500) — Interest income 2,155 1,103 582 Interest expense (109) (27) (2) (Losses) earnings before income taxes and investment in unconsolidated affiliate $ 3,454 $ (3,427) $ 6,634 _______________ (1) General and administrative expenses for the year ended December 31, 2017 included approximately $1.0 million of costs related to a voluntary early retirement program we implemented in August 2017. Identifiable assets by industry segment were as follows at the dates indicated (in thousands): December 31, 2018 2017 2016 Reporting segment: Marketing $ 119,370 $ 134,745 $ 107,257 Transportation 34,112 29,069 32,120 Oil and Gas (1) — 425 7,279 Cash and other 125,388 118,465 100,216 Total assets $ 278,870 $ 282,704 $ 246,872 ____________________ (1) At December 31, 2017, amount represents our remaining cost method investment in this segment. See Note 4 for further information. There were no intersegment sales during the year ended December 31, 2018, and intersegment sales during the years ended December 31, 2017 and 2016 were insignificant. Other identifiable assets are primarily corporate cash, corporate accounts receivable, investments and properties not identified with any specific segment of our business. Accounting policies for transactions between reportable segments are consistent with applicable accounting policies as disclosed herein. |
Transactions with Affiliates
Transactions with Affiliates | 12 Months Ended |
Dec. 31, 2018 | |
Related Party Transactions [Abstract] | |
Transactions with Affiliates | Transactions with Affiliates We enter into certain transactions in the normal course of business with affiliated entities including direct cost reimbursement for shared phone and administrative services. In addition, we lease our corporate office space from an affiliated entity. We utilize our former affiliate, Bencap, to administer certain of our employee medical benefit programs including a detail audit of individual medical claims (see Note 15 for further information). Bencap earns a fee from us for providing such services at a discounted amount from its standard charge to non-affiliates. We had an equity method investment in Bencap, which was forfeited during the first quarter of 2017. As a result, we have no further ownership interest in Bencap (see Note 8). Activities with affiliates were as follows for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Overhead recoveries (1) $ — $ — $ 32 Affiliate billings to us 75 81 65 Billings to affiliates 6 4 5 Rentals paid to affiliate 487 583 628 Fee paid to Bencap (2) — 108 583 ___________________ (1) In connection with the operation of certain crude oil and natural gas properties, we charged related parties for administrative overhead. In late 2016, these charges ended as properties were either plugged and abandoned or operating responsibilities for these properties were transferred to another entity. (2) Amount represents fees paid to Bencap through the forfeiture of our investment during the first quarter of 2017. As a result of the investment forfeiture, Bencap is no longer an affiliate. DIP Financing |
Derivative Instruments and Fair
Derivative Instruments and Fair Value Measurements | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments and Fair Value Measurements | Derivative Instruments and Fair Value Measurements Derivative Instruments At December 31, 2018, we had in place ten commodity purchase and sale contracts with fair value associated with them as the contractual prices of crude oil were outside of the range of prices specified in the agreements. These commodity purchase and sale contracts encompassed approximately: • 322 barrels per day of crude oil during January 2019 through April 2019; • 258 barrels per day of crude oil during May 2019; • 322 barrels per day of crude oil during June 2019 through August 2019; and • 258 barrels per day of crude oil during September 2019 through December 2019. The estimated fair value of forward month commodity contracts (derivatives) reflected in the accompanying consolidated balance sheet were as follows at the date indicated (in thousands): December 31, 2018 Balance Sheet Location and Amount Current Other Current Other Assets Assets Liabilities Liabilities Asset derivatives: Fair value forward hydrocarbon commodity contracts at gross valuation $ 162 $ — $ — $ — Liability derivatives: Fair value forward hydrocarbon commodity contracts at gross valuation — — 139 — Less counterparty offsets — — — — As reported fair value contracts $ 162 $ — $ 139 $ — At December 31, 2017, we had in place twenty commodity purchase and sale contracts, of which four of these contracts had no fair value associated with them as the contractual prices of crude oil were within the range of prices specified in the agreements. These commodity purchase and sale contracts encompassed approximately: • 452 barrels per day of crude oil during January 2018; • 322 barrels per day of crude oil during February through May 2018; • 258 barrels per day of crude oil during June 2018; • 646 barrels per day of crude oil during July 2018; • 322 barrels per day of crude oil during August through September 2018; and • 258 barrels per day of crude oil during October through December 2018. The estimated fair value of forward month commodity contracts (derivatives) reflected in the accompanying consolidated balance sheet were as follows at the date indicated (in thousands): December 31, 2017 Balance Sheet Location and Amount Current Other Current Other Assets Assets Liabilities Liabilities Asset derivatives: Fair value forward hydrocarbon commodity contracts at gross valuation $ 166 $ — $ — $ — Liability derivatives: Fair value forward hydrocarbon commodity contracts at gross valuation — — 145 — Less counterparty offsets — — — — As reported fair value contracts $ 166 $ — $ 145 $ — We only enter into commodity contracts with creditworthy counterparties and evaluate our exposure to significant counterparties on an ongoing basis. At December 31, 2018 and 2017, we were not holding nor have we posted any collateral to support our forward month fair value derivative activity. We are not subject to any credit-risk related trigger events. We have no other financial investment arrangements that would serve to offset our derivative contracts. Forward month commodity contracts (derivatives) reflected in the accompanying consolidated statements of operations were as follows for the periods indicated (in thousands): Gains (Losses) Year Ended December 31, 2018 2017 2016 Revenues – marketing $ 2 $ (26) $ 243 Fair Value Measurements The following tables set forth, by level with the Level 1, 2 and 3 fair value hierarchy, the carrying values of our financial assets and liabilities at the dates indicated (in thousands): December 31, 2018 Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Assets Observable Unobservable and Liabilities Inputs Inputs Counterparty (Level 1) (Level 2) (Level 3) Offsets Total Derivatives: Current assets $ — $ 162 $ — $ — $ 162 Current liabilities — (139) — — (139) Net value $ — $ 23 $ — $ — $ 23 December 31, 2017 Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Assets Observable Unobservable and Liabilities Inputs Inputs Counterparty (Level 1) (Level 2) (Level 3) Offsets Total Derivatives: Current assets $ — $ 166 $ — $ — $ 166 Current liabilities — (145) — — (145) Net value $ — $ 21 $ — $ — $ 21 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, 2018 and 2017, credit valuation adjustments were not significant to the overall valuation of our fair value contracts. As a result, applicable fair value assets and liabilities are included in their entirety in the fair value hierarchy. Nonrecurring Fair Value Measurements Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of impairment. During the year ended December 31, 2018, we had no long-lived assets that were subject to non-recurring fair value measurements. The following table presents categories of long-lived assets that were subject to non-recurring fair value measurements during the year ended December 31, 2017 (in thousands): Fair Value Measurements at the End of the Reporting Period Using Quoted Prices in Active Significant Carrying Markets for Other Significant Total Value at Identical Assets Observable Unobservable Non-Cash December 31, and Liabilities Inputs Inputs Impairment 2017 (Level 1) (Level 2) (Level 3) Loss Oil and gas properties — Investment in AREC $ 425 $ — $ 425 $ — $ 3,505 Investment in VestaCare — — — — 2,500 $ 6,005 The following table presents categories of long-lived assets that were subject to non-recurring fair value measurements during the year ended December 31, 2016 (in thousands): Fair Value Measurements at the End of the Reporting Period Using Quoted Prices in Active Significant Carrying Markets for Other Significant Total Value at Identical Assets Observable Unobservable Non-Cash December 31, and Liabilities Inputs Inputs Impairment 2016 (Level 1) (Level 2) (Level 3) Loss Investment in Bencap $ — $ — $ — $ — $ 2,200 Oil and gas properties 62,784 — — 62,784 313 $ 2,513 |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes The components of our income tax (provision) benefit were as follows for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Current: Federal $ 388 $ (1,418) $ (2,103) State 39 523 (675) Total current 427 (895) (2,778) Deferred: Federal (752) 3,722 777 State (184) 118 80 Total deferred (936) 3,840 857 Total (provision for) benefit from income taxes (1) $ (509) $ 2,945 $ (1,921) ______________ (1) 2016 includes a tax benefit of $0.8 million related to losses from our investment in Bencap, and is included in the loss from investment in unconsolidated affiliate category on the consolidated statements of operations. 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, 2018 2017 2016 Pre-tax net book income (loss) (1) $ 3,454 $ (3,427) $ 4,434 Statutory federal income tax (provision) benefit $ (725) $ 1,165 $ (1,552) State income tax (provision) benefit (145) 736 (387) Federal statutory depletion — 153 62 Federal tax rate adjustment — 2,007 — Valuation allowance — (1,038) — Reverse valuation allowance 98 — — Return to provision adjustments 388 — — Other (125) (78) (44) Total (provision for) benefit from income taxes $ (509) $ 2,945 $ (1,921) Effective income tax rate (2) (3) 15% 86% 43% _______________ (1) 2016 includes the pre-tax loss from investment in unconsolidated affiliate of $2.2 million. (2) Excluding the adjustment related to the federal tax rate change, the effective income tax rate for 2017 is 58 percent. (3) Excluding the adjustment related to the return to provision, the effective income tax rate for 2018 is 26 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, 2018 2017 Long-term deferred tax asset (liability): (1) Prepaid and other insurance $ (170) $ (684) Property (5,259) (2,497) Investments in unconsolidated affiliates 525 623 Valuation allowance related to investments in unconsolidated affiliates (525) (623) Net operating loss 1,436 — Other (245) (121) Net long-term deferred tax liability (4,238) (3,302) Net deferred tax liability $ (4,238) $ (3,302) ______________ (1) Amounts as of December 31, 2017 have been revalued at 21 percent as a result of the enactment of the Tax Cuts and Jobs Act on December 22, 2017. Financial statement recognition and measurement of positions taken, or expected to be taken, by an entity in its income tax returns must consider the uncertainty and judgment involved in the determination and filing of income taxes. Tax positions taken in an income tax return that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the tax position will be examined by taxing authorities with full knowledge of all relevant information. We have no significant unrecognized tax benefits. Interest and penalties associated with income tax liabilities are classified as income tax expense. The earliest tax years remaining open for audit for federal and major states of operations are as follows: Earliest Open Tax Year Federal 2014 Texas 2014 Louisiana 2015 Michigan 2014 Other Matters |
Share-Based Compensation Plan
Share-Based Compensation Plan | 12 Months Ended |
Dec. 31, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Share-Based Compensation Plan | Share-Based Compensation Plan In May 2018, our shareholders approved the 2018 LTIP, a long-term incentive plan under which any employee or non-employee director who provides services to us is eligible to participate in the plan. The 2018 LTIP, which is overseen by the Compensation Committee of our Board of Directors, provides for the grant of various types of equity awards, of which restricted stock unit awards and performance-based compensation awards were granted during the second quarter of 2018. The maximum number of shares authorized for issuance under the 2018 LTIP is 150,000 shares, and the 2018 LTIP is effective until May 8, 2028. We began awarding share-based compensation to eligible employees and directors in June 2018. After giving effect to awards granted under the 2018 LTIP and assuming the potential achievement of the maximum amounts of the performance factors through December 31, 2018, a total of 120,403 shares were available for issuance. During the year ended December 31, 2018, we recognized $0.3 million of compensation expense in connection with equity-based awards. If dividends are paid with respect to our common shares during the vesting period, an equivalent amount will accrue and be held by us without interest until the restricted stock unit awards and performance share unit awards vest, at which time the amount will be paid to the recipient. If the award is forfeited prior to vesting, the accrued dividends will also be forfeited. At December 31, 2018, we had $10.0 thousand of accrued dividend amounts for awards granted under the 2018 LTIP. Restricted Stock Unit Awards A restricted stock unit award is a grant of a right to receive our common shares in the future at no cost to the recipient apart from fulfilling service and other conditions once a defined vesting period expires, subject to customary forfeiture provisions. A restricted stock unit award will either be settled by the delivery of common shares or by the payment of cash based upon the fair market value of a specified number of shares, at the discretion of the Compensation Committee, subject to the terms of the applicable award agreement. The Compensation Committee intends for these awards to vest with the settlement of common shares. Restricted stock unit awards generally vest at a rate of approximately 33 percent per year beginning one year after the grant date and are non-vested until the required service periods expire. The fair value of a restricted stock unit award is based on the market price per share of our common shares on the date of grant. Compensation expense is recognized based on the grant date fair value over the requisite service or vesting period. The following table presents restricted stock unit award activity for the periods indicated: Weighted- Average Grant Number of Date Fair Value Shares per Share (1) Restricted stock unit awards at January 1, 2018 — $ — Granted (2) 13,733 $ 43.00 Vested — $ — Forfeited — $ — Restricted stock unit awards at December 31, 2018 13,733 $ — ____________________ (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. (2) The aggregate grant date fair value of restricted stock unit awards issued during 2018 was $0.6 million based on a grant date market price of our common shares of $43.00 per share. Unrecognized compensation cost associated with restricted stock unit awards was approximately $0.4 million at December 31, 2018. Due to the graded vesting provisions of these awards, we expect to recognize the remaining compensation cost for these awards over a weighted-average period of 1.5 years. Performance Share Unit Awards An award granted as performance-based compensation is awarded to a participant contingent upon attainment of our future performance goals during a performance cycle. The performance goals were pre-established by the Compensation Committee. Following the end of the performance period, the holder of a performance-based compensation award is entitled to receive payment of an amount not exceeding the number of shares of common stock subject to, or the maximum value of, the performance-based compensation award, based on the achievement of the performance measures for the performance period. The performance share unit awards generally vest in full approximately three The fair value of a performance share unit award is based on the market price per share of our common shares on the date of grant. Compensation expense is recognized based on the grant date fair value over the requisite service or vesting period. Compensation expense will be adjusted for the performance goals on a quarterly basis. The following table presents performance share unit award activity for the periods indicated: Weighted- Average Grant Number of Date Fair Value Shares per Share (1) Performance share unit awards at January 1, 2018 — $ — Granted (2) 7,932 $ 43.00 Performance factor decrease (3) (3,966) $ 43.00 Vested — $ — Forfeited — $ — Performance share unit awards at December 31, 2018 3,966 $ — ____________________ (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. (2) The aggregate grant date fair value of performance share unit awards issued during 2018 was $0.2 million based on a grant date market price of our common share of $43.00 per share and assuming a performance factor of 100 percent. (3) The performance factor was lowered to 50 percent at the end of 2018 based upon a comparison of actual results to performance goals. Unrecognized compensation cost associated with performance share unit awards was approximately $0.1 million at December 31, 2018. We expect to recognize the remaining compensation cost for these awards over a weighted-average period of 2.4 years. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplemental Cash Flow Information | Supplemental Cash Flow Information Supplemental cash flows and non-cash transactions were as follows for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Cash paid for interest $ 109 $ 22 $ 2 Cash paid for federal and state income taxes 787 459 2,589 Non-cash transactions: Change in accounts payable related to property and equipment additions 1,685 70 679 Property and equipment acquired under capital leases 2,898 1,808 — |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitment and Contingencies Capital Lease Obligations During 2017 and 2018, we entered into capital leases for certain of our tractors in our crude oil marketing segment. The following table summarizes our principal contractual commitments outstanding under our capital leases at December 31, 2018 for the next five years, and in total thereafter (in thousands): 2019 $ 1,052 2020 1,052 2021 1,052 2022 909 2023 451 Thereafter — Total minimum lease payments 4,516 Less: Amount representing interest (424) Present value of capital lease obligations 4,092 Less current portion of capital lease obligations (883) Total long-term capital lease obligations $ 3,209 Operating Lease Obligations We lease certain property and equipment under noncancelable and cancelable operating leases. Our significant lease agreements consist of (i) arrangements with independent truck owner-operators for use of their equipment and driver services; (ii) leased office space; and (iii) certain lease and terminal access contracts in order to provide tank storage and dock access for our crude oil marketing business. Currently, our significant lease agreements have terms that range from one to seven Lease expense is charged to operating costs and expenses on a straight-line basis over the period of expected economic benefit. Contingent rental payments are expensed as incurred. We are generally required to perform routine maintenance on the underlying leased assets. Maintenance and repairs of leased assets resulting from our operations are charged to expense as incurred. Rental expense was as follows for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Rental expense $ 11,078 $ 12,073 $ 11,314 At December 31, 2018, rental obligations under non-cancelable operating leases and terminal arrangements with terms in excess of one year for the next five years and thereafter are payable as follows (in thousands): 2019 $ 4,242 2020 2,258 2021 2,107 2022 1,782 2023 1,495 Thereafter 1,488 Total operating lease payments $ 13,372 Insurance Policies Under our automobile and workers’ compensation insurance policies that were in place through September 30, 2017, we pre-funded our estimated losses, and therefore, we could either receive a return of premium paid or be assessed for additional premiums up to pre-established limits. Additionally, in certain instances, the risk of insured losses was shared with a group of similarly situated entities through an insurance captive. We have appropriately recognized estimated expenses and liabilities related to these policies for losses incurred but not reported to us or our insurance carrier. The amount of pre-funded insurance premiums left to cover potential future losses are presented in the table below. If the potential insurance claims do not further develop, the pre-funded premiums will be returned to us as a premium refund. Effective October 1, 2017, we changed the structure of our automobile and workers’ compensation insurance policies. We have exited the group captive and now establish a liability for expected claims incurred but not reported on a monthly basis as we move forward. As claims are paid, the liability is relieved. The amount of pre-funded insurance premiums left to cover potential future losses and our accruals for automobile and workers’ compensation claims were as follows at the dates indicated (in thousands): December 31, 2018 2017 Pre-funded premiums for losses incurred but not reported $ 427 $ 988 Accrued automobile and workers’ compensation claims 2,246 450 We maintain a self-insurance program for managing employee medical claims. A liability for expected claims incurred but not reported is established on a monthly basis. As claims are paid, the liability is relieved. We also maintain third party insurance stop-loss coverage for annual aggregate medical claims exceeding $6.0 million. Medical accrual amounts were as follows at the dates indicated (in thousands): December 31, 2018 2017 Accrued medical claims $ 1,181 $ 1,329 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 or results of operations. Guarantees AE issues parent guarantees of commitments associated with the activities of its subsidiary companies. The guarantees generally result from subsidiary commodity purchase obligations, subsidiary operating lease commitments and subsidiary banking transactions. The nature of these arrangements is to guarantee the performance of the subsidiary in meeting their respective underlying obligations. The parent would only be called upon to perform under the guarantee in the event of a payment default by the applicable subsidiary company. In satisfying these obligations, the parent would first look to the assets of the defaulting subsidiary company. At December 31, 2018, parental guaranteed obligations were approximately $22.3 million. Currently, neither AE nor any of its subsidiaries has any other types of guarantees outstanding that require liability recognition. |
Concentration of Credit Risk
Concentration of Credit Risk | 12 Months Ended |
Dec. 31, 2018 | |
Risks and Uncertainties [Abstract] | |
Concentration of Credit Risk | Concentration of Credit Risk We may incur credit risk to the extent our customers do not fulfill their obligations to us pursuant to contractual terms. Risks of nonpayment and nonperformance by our customers are a major consideration in our business, and our credit procedures and policies may not be adequate to sufficiently eliminate customer credit risk. Managing credit risk involves a number of considerations, such as the financial profile of the customer, the value of collateral held, if any, specific terms and duration of the contractual agreement, and the customer’s sensitivity to economic developments. We have established various procedures to manage credit exposure, including initial credit approval, credit limits and rights of offset. We also utilize letters of credit and guarantees to limit exposure. Our largest customers consist of large multinational integrated crude oil companies and independent domestic refiners of crude oil. In addition, we transact business with independent crude oil producers, major chemical companies, crude oil trading companies and a variety of commercial energy users. Within this group of customers, we derive approximately 50 percent of our revenues from three to five large crude oil refining customers. While we have ongoing established relationships with certain domestic refiners of crude oil, alternative markets are readily available since we supply less than one percent of U.S. domestic refiner demand. As a fungible commodity delivered to major Gulf Coast supply points, our crude oil sales can be readily delivered to alternative end markets. We believe that a loss of any of those customers where we currently derive more than 10 percent of our revenues would not have a material adverse effect on our operations as shown in the table below: Individual customer sales Individual customer receivables in excess in excess of 10% of revenues of 10% of total receivables Year Ended December 31, December 31, 2018 2017 2016 2018 2017 2016 27.3 % 22.8 % 18.2 % 18.4 % 19.1 % 20.9 % 14.1 % 17.1 % 16.5 % 11.9 % 15.0 % 14.0 % 10.8 % 15.9 % 11.1 % 10.1 % 10.7 % 10.6 % 10.4 % |
Quarterly Financial Information
Quarterly Financial Information (Unaudited) | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly Financial Information (Unaudited) | Quarterly Financial Information (Unaudited) The following table presents selected quarterly financial data for the periods indicated (in thousands, except per share data): First Second Third Fourth Quarter Quarter Quarter Quarter Year Ended December 31, 2018 Revenues $ 387,256 $ 452,417 $ 467,891 $ 442,649 Operating (losses) earnings (1) 1,077 4,298 2,239 (6,206) Net (losses) earnings 1,138 3,620 2,035 (3,848) Earnings (losses) per share: Basic net (losses) earnings per share $ 0.27 $ 0.86 $ 0.48 $ (0.91) Diluted net (losses) earnings per share $ 0.27 $ 0.86 $ 0.48 $ (0.91) Year Ended December 31, 2017 Revenues $ 303,087 $ 315,202 $ 295,311 $ 408,460 Operating (losses) earnings (1,584) 619 (1,290) 3,757 Net (losses) earnings (860) (282) (3,033) 3,693 Earnings (losses) per share: Basic and diluted net (losses) earnings per share $ (0.20) $ (0.07) $ (0.72) $ 0.88 ____________________ (1) The fourth quarter of 2018 includes inventory valuation losses of approximately $7.9 million in our crude oil marketing segment. |
Oil and Gas Producing Activitie
Oil and Gas Producing Activities (Unaudited) | 12 Months Ended |
Dec. 31, 2018 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Oil and Gas Producing Activities (Unaudited) | Oil and Gas Producing Activities (Unaudited) Our wholly owned subsidiary, AREC, participated in the exploration and development of domestic crude oil and natural gas properties primarily in the Permian Basin of West Texas and the Haynesville Shale. AREC’s offices were maintained in Houston. 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 closed on the sale of substantially all of its assets. As a result of the sales of these assets, we no longer have an ownership interest in any crude oil and natural gas producing activities. In the disclosures and tables below, amounts for 2017 are for the period from January 1, 2017 through April 30, 2017, as a result of the deconsolidation of AREC due to its bankruptcy filing. There is no further exploration and development activity after April 30, 2017. Crude Oil and Natural Gas Producing Activities Total costs incurred in crude oil and natural gas exploration and development activities, all within the U.S., were as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 Property acquisition costs: Unproved $ 4 $ 32 Exploration costs: Expensed 5 291 Development costs 1,815 — Total costs incurred $ 1,824 $ 323 Estimated Crude Oil and Natural Gas Reserves The following information regarding estimates of our proved crude oil and natural gas reserves, substantially all located onshore in Texas and Louisiana, was based on reports prepared on our behalf by our independent petroleum engineers. Because crude oil and natural gas reserve estimates are inherently imprecise and require extensive judgments of reservoir engineering data, they are generally less precise than estimates made in conjunction with financial disclosures. The revisions of previous estimates as reflected in the table below result from changes in commodity pricing assumptions and from more precise engineering calculations based upon additional production histories and price changes. As discussed previously, AREC was deconsolidated effective with its bankruptcy filing in April 2017, and we recorded our investment in AREC under the cost method of accounting in April 2017. During the third quarter of 2017, AREC closed on the sale of substantially all of its assets. As a result of the sales of these assets, we no longer have an ownership interested in any crude oil and natural gas producing activities. In the tables below, amounts for 2017 are for the period from January 1, 2017 through April 30, 2017, as a result of the deconsolidation of AREC due to its bankruptcy filing. Proved developed and undeveloped reserves were as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 Natural Crude Natural Crude Gas Oil Gas Oil (Mcf) (Bbls) (Mcf) (Bbls) Total proved reserves: Beginning of year 4,214 187 4,835 226 Revisions of previous estimates — — 65 24 Crude oil and natural gas reserves sold (4,067) (170) (175) (4) Extensions, discoveries and other reserve additions 42 6 151 18 Production (189) (23) (662) (77) End of year — — 4,214 187 The components of our previously owned proved crude oil and natural gas reserves, all within the U.S., were as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 Natural Crude Natural Crude Gas Oil Gas Oil (Mcf) (Bbls) (Mcf) (Bbls) Proved developed reserves — — 4,214 187 Proved undeveloped reserves — — — — Total proved reserves — — 4,214 187 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 is 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 for each of the years presented, all without escalation. The process of estimating crude oil and natural gas reserves is complex and requires significant judgment. Uncertainties are inherent in estimating quantities of proved reserves, including many factors beyond the estimator’s control. Reserve engineering is a subjective process of estimating subsurface accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and the interpretation thereof. As a result, assessments by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates. Accordingly, crude oil and natural gas quantities ultimately recovered will vary from reserve estimates. Standardized Measure of Discounted Future Net Cash Flows from Crude Oil and Natural Gas Operations and Changes Therein The standardized measure of discounted future net cash flows was determined based on the economic conditions in effect at the end of the years presented, except in those instances where fixed and determinable gas price escalations were included in contracts. The disclosures below do not purport to present the fair market value of our previously owned crude oil and natural gas reserves. An estimate of the fair market value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, a discount factor more representative of the time value of money and risks inherent in reserve estimates. The standardized measure of discounted future net cash flows was as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 Future gross revenues $ — $ 17,938 Future costs: Lease operating expenses — (12,421) Development costs — (38) Future net cash flows before income taxes — 5,479 Discount at 10% per annum — (2,002) Discounted future net cash flows before income taxes — 3,477 Future income taxes, net of discount at 10% per annum — (1,217) Standardized measure of discounted future net cash flows $ — $ 2,260 The estimated value of crude oil and natural gas reserves and future net revenues derived therefrom are highly dependent upon crude oil and natural gas commodity price assumptions. For these estimates, our independent petroleum engineers assumed market prices as follows for the periods indicated: Year Ended December 31, 2017 2016 Market price: Crude oil per barrel $ — $ 38.34 Natural gas per thousand cubic feet (Mcf) $ — $ 2.56 These prices were based on the unweighted arithmetic average of the prices in effect on the first day of the month for each month of the respective twelve month periods as required by SEC regulations. The prices reported in the reserve disclosures for natural gas included the value of associated natural gas liquids. Crude oil and natural gas reserve values and future net cash flow estimates are very sensitive to pricing assumptions and will vary accordingly. The effect of income taxes and discounting on the standardized measure of discounted future net cash flows was as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 Future net cash flows before income taxes $ — $ 5,479 Future income taxes — (1,918) Future net cash flows — 3,561 Discount at 10% per annum — (1,301) Standardized measure of discounted future net cash flows $ — $ 2,260 The principal sources of changes in the standardized measure of discounted future net cash flows were as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 Beginning of year $ 2,260 $ 3,527 Sale of crude oil and natural gas reserves (2,732) (350) Net change in prices and production costs — (1,391) New field discoveries and extensions, net of future production costs 94 275 Sales of crude oil and natural gas produced, net of production costs (476) 87 Net change due to revisions in quantity estimates — 181 Accretion of discount 130 194 Production rate changes and other (493) (945) Net change in income taxes 1,217 682 End of year $ — $ 2,260 Results of Operations for Crude Oil and Natural Gas Producing Activities The results of crude oil and natural gas producing activities, excluding corporate overhead and interest costs, were as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 Revenues $ 1,427 $ 3,410 Costs and expenses: Production (951) (3,337) Producing property impairment — (30) Depreciation, depletion and amortization (423) (1,546) Operating earnings (losses) before income taxes 53 (1,503) Income tax benefit (expense) (19) 526 Operating earnings (losses) $ 34 $ (977) |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Consolidation | Adams Resources & Energy, Inc. (“AE”) is a publicly traded Delaware corporation organized in 1973, the common shares of which are listed on the NYSE 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, 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. |
Use of Estimates | Use of Estimates The preparation of our financial statements in conformity with GAAP requires management to use estimates and assumptions that affect the reported amount of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We base our estimates and judgments on historical experience and on various other assumptions and information we believe to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the operating environment changes. While we believe the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates. |
Accounts Receivable and Allowance for Doubtful Accounts | Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable associated with crude oil marketing activities comprise approximately 90 percent of our total receivables, and industry practice requires payment for these sales to occur within 20 days of the end of the month following a transaction. Our customer makeup, credit policies and the relatively short duration of receivables mitigate the uncertainty typically associated with receivables management. An allowance for doubtful accounts is provided where appropriate. Our allowance for doubtful accounts is determined based on specific identification combined with a review of the general status of the aging of all accounts. We consider the following factors in our review of our allowance for doubtful accounts: (i) historical experience with customers, (ii) the perceived financial stability of customers based on our research, (iii) the levels of credit we grant to customers, and (iv) the duration of the receivable. We may increase the allowance for doubtful accounts in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties. On a routine basis, we review estimates associated with the allowance for doubtful accounts to ensure that we have recorded sufficient reserves to cover potential losses. See Note 16 for further information regarding credit risk. |
Cash and Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than three months from the date of purchase. Cash and cash equivalents are maintained with major financial institutions, and deposit amounts may exceed the amount of federally backed insurance provided. While we regularly monitor the financial stability of these institutions, cash and cash equivalents ultimately remain at risk subject to the financial viability of these institutions. |
Derivative Instruments | Derivative Instruments In the normal course of our operations, our crude oil marketing segment purchases and sells crude oil. We seek to profit by procuring the commodity as it is produced and then delivering the product to the end users or the intermediate use marketplace. As typical for the industry, these transactions are made pursuant to the terms of forward month commodity purchase and/or sale contracts. Some of these contracts meet the definition of a derivative instrument, and therefore, we account for these contracts at fair value, unless the normal purchase and sale exception is applicable. These types of underlying contracts are standard for the industry and are the governing document for our crude oil marketing segment. None of our derivative instruments have been designated as hedging instruments. |
Earnings Per Share | Earnings Per Share Basic earnings (losses) per share is computed by dividing our net earnings (losses) by the weighted average number of shares of common stock outstanding during the period. Diluted earnings (losses) per share is computed by giving effect to all potential shares of common stock outstanding, including our stock related to unvested restricted stock unit awards. Unvested restricted stock unit awards granted under the Adams Resources & Energy, Inc. 2018 Long-Term Incentive Plan (“2018 LTIP”) are not considered to be participating securities as the holders of these shares do not have non-forfeitable dividend rights in the event of our declaration of a dividend for common shares (see Note 13 for further discussion). |
Fair Value Measurements | Fair Value Measurements The carrying amounts reported in the consolidated balance sheets for cash and cash equivalents, accounts receivable and accounts payable approximates fair value because of the immediate or short-term maturity of these financial instruments. Marketable securities are recorded at fair value based on market quotations from actively traded liquid markets. Our fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk, in the principal market of the asset or liability at a specified measurement date. Recognized valuation techniques employ inputs such as contractual prices, quoted market prices or rates, operating costs, discount factors and business growth rates. These inputs may be either readily observable, corroborated by market data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the highest extent possible. Accordingly, we utilize valuation techniques (such as the market approach) that maximize the use of observable inputs and minimize the use of unobservable inputs. A three-tier hierarchy has been established that classifies fair value amounts recognized in the financial statements based on the observability of inputs used to estimate such fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy. 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 11 for further information). |
Impairment Testing for Long-Lived Assets | Impairment Testing for Long-Lived Assets Long-lived assets (primarily property and equipment) are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written-down to their estimated fair values. The carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset’s carrying value exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge equal to the excess of the asset’s carrying value over its estimated fair value is recorded. Fair value is defined as the price that would be received to sell an asset or be paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. We measure fair value using market price indicators or, in the absence of such data, appropriate valuation techniques. See Note 11 for information regarding impairment charges related to long-lived assets. |
Income Taxes | Income Taxes Income taxes are accounted for using the asset and liability method. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of such items and their respective tax basis (see Note 12 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 | InventoryInventory 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, 2017 and 2016. |
Letter of Credit Facility | Letter of Credit Facility We maintain a Credit and Security Agreement with Wells Fargo Bank, National Association to provide for the issuance of up to $60 million in stand-by letters of credit primarily used to support crude oil purchases within our crude oil marketing segment and for other purposes. We are currently using the letter of credit facility for letters of credit related to our insurance program. This facility is collateralized by the eligible accounts receivable within the crude oil marketing segment and expires on August 30, 2019. |
Property and Equipment | Property and Equipment Property and equipment is recorded at cost. Expenditures for additions, improvements and other enhancements to property and equipment are capitalized, and minor replacements, maintenance and repairs that do not extend asset life or add value are charged to expense as incurred. When property and equipment assets are retired or otherwise disposed of, the related cost and accumulated depreciation is removed from the accounts and any resulting gain or loss is included in results of operations in operating costs and expenses for the respective period. Property and equipment, except for land, is depreciated using the straight-line method over the estimated average useful lives of two to thirty-nine years. We capitalize interest costs, if any, incurred in connection with major capital expenditures while the asset is in its construction phase. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s estimated useful life as a component of depreciation expense. When capitalized interest is recorded, it reduces interest expense. Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related long-lived asset. ARO amounts are measured at their estimated fair value using expected present value techniques. Over time, the ARO liability is accreted to its present value (through accretion expense), and the capitalized amount is depreciated over the remaining useful life of the related long-lived asset. We will incur a gain or loss to the extent that our ARO liabilities are not settled at their recorded amounts. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements Lease accounting standard . In February 2016, the Financial Accounting Standards Board issued Accounting Standards Codification (“ASC”) 842, Leases (“ASC 842”), which requires substantially all leases to be recorded on the balance sheet. We adopted the new standard on January 1, 2019 and expect to apply it to all existing lease contracts as of January 1, 2019. We also plan to apply it to all new leases entered into after January 1, 2019. ASC 842 supersedes existing lease accounting guidance under ASC 840, Leases (“ASC 840”). We expect to adopt the new standard using the modified retrospective approach and apply certain optional transitional practical expedients. We elected an optional transition method that allowed application of the new standard at the adoption date and the recognition of a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption with no adjustment to previously reported results. In accordance with this approach, our consolidated financial statements for periods prior to January 1, 2019 will not be revised to reflect the new lease accounting guidance. We also elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allowed the carry forward of historical lease classification. We did not elect the practical expedient related to hindsight. ASC 842 will result in changes to the way our operating leases are recorded, presented and disclosed in our consolidated financial statements. Upon adoption of ASC 842 on January 1, 2019, we expect to recognize a right-of-use (“ROU”) asset and a corresponding lease liability based on the present value of then existing operating lease obligations. In addition, there are several key accounting policy elections that we will make upon adoption of ASC 842 including: • We will not recognize ROU assets and lease liabilities for short-term leases and will instead record them in a manner similar to operating leases under ASC 840 lease accounting guidelines. A short term lease is one with a maximum lease term of 12 months or less and does not include a purchase option or renewal option the lessee is reasonably certain to exercise. • We will also elect the non-lease component for any asset class where lease and non-lease components are comingled and the non-lease component is determined to be insignificant when compared to the lease component. |
Share-based Compensation | Stock-Based CompensationWe measure all share-based payment, including the issuance of restricted stock units and performance share units to employees and board members, using a fair-value based method. The cost of services received from employees and non-employee board members in exchange for awards of equity instruments is recognized in the consolidated statement of operations based on the estimated fair value of those awards on the grant date and amortized on a straight-line basis over the requisite service period. The fair value of restricted stock unit awards and performance share unit awards is based on the closing price of our common stock on the grant date. We account for forfeitures as they occur. |
Revenue Recognition | 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. 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. 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 period indicated (in thousands): Year Ended December 31, 2018 Reporting Segments Marketing Transportation Total Revenues from contracts with customers $ 1,580,997 $ 55,776 $ 1,636,773 Other (1) 113,440 — 113,440 Total revenues $ 1,694,437 $ 55,776 $ 1,750,213 Timing of revenue recognition: Goods transferred at a point in time $ 1,580,997 $ — $ 1,580,997 Services transferred over time — 55,776 55,776 Total revenues from contracts with customers $ 1,580,997 $ 55,776 $ 1,636,773 _______________ (1) Other crude oil marketing revenues are recognized under ASC 815, Derivatives and Hedging , and ASC 845, Nonmonetary Transactions – Purchases and Sales of Inventory with the Same Counterparty . Other Marketing Revenue Certain of the commodity purchase and sale contracts utilized by our crude oil marketing segment qualify as derivative instruments with certain specifically identified contracts also designated as trading activity. From the time of contract origination, these contracts are marked-to-market and recorded on a net revenue basis in the accompanying 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 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. |
Cash Deposits and Other Assets | We have established certain deposits to support participation in our liability insurance program and remittance of state crude oil severance taxes and other state collateral deposits. Insurance collateral deposits are held by the insurance company to cover past or potential open claims based upon a percentage of the maximum assessment under our insurance policies. 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. |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Changes in the allowance for doubtful accounts | The following table presents our allowance for doubtful accounts activity for the periods indicated (in thousands): December 31, 2018 2017 2016 Balance at beginning of period $ 303 $ 225 $ 206 Charges to costs and expenses 43 137 100 Deductions (193) (59) (81) Balance at end of period $ 153 $ 303 $ 225 |
Schedule of earnings per share, basic and diluted | A reconciliation of the calculation of basic and diluted earnings (losses) per share is as follows (in thousands, except per share data): Year Ended December 31, 2018 2017 2016 Earnings (losses) per share – numerator: Earnings (losses) from continuing operations $ 2,945 $ (482) $ 3,943 Losses from investment in unconsolidated affiliate, net of tax — — (1,430) Net (losses) earnings $ 2,945 $ (482) $ 2,513 Denominator: Basic weighted average number of shares outstanding 4,218 4,218 4,218 Basic earnings (losses) per share: From continuing operations $ 0.70 $ (0.11) $ 0.94 From investment in unconsolidated affiliate — — (0.34) Basic earnings (losses) per share $ 0.70 $ (0.11) $ 0.60 Diluted earnings (losses) per share: Diluted weighted average number of shares outstanding: Common shares 4,218 4,218 4,218 Restricted stock unit awards (1) — — — Performance share unit awards ( 2 ) — — — Total 4,218 4,218 4,218 Diluted earnings (losses) per share: From continuing operations $ 0.70 $ (0.11) $ 0.94 From investment in unconsolidated affiliate — — (0.34) Diluted earnings (losses) per share $ 0.70 $ (0.11) $ 0.60 ________________________ (1) The dilutive effect of restricted stock unit awards for the year ended December 31, 2018 is de minimis. (2) The dilutive effect of performance share awards will be included in the calculation of diluted earnings per share when the performance share award performance conditions have been achieved. |
Schedule of cost of retirement plans | Our 401(k) plan contributory expenses were as follows for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Contributory expenses $ 808 $ 734 $ 757 |
Revenue Recognition (Tables)
Revenue Recognition (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | The following table disaggregates our revenue by segment and by major source for the period indicated (in thousands): Year Ended December 31, 2018 Reporting Segments Marketing Transportation Total Revenues from contracts with customers $ 1,580,997 $ 55,776 $ 1,636,773 Other (1) 113,440 — 113,440 Total revenues $ 1,694,437 $ 55,776 $ 1,750,213 Timing of revenue recognition: Goods transferred at a point in time $ 1,580,997 $ — $ 1,580,997 Services transferred over time — 55,776 55,776 Total revenues from contracts with customers $ 1,580,997 $ 55,776 $ 1,636,773 _______________ (1) Other crude oil marketing revenues are recognized under ASC 815, Derivatives and Hedging , and ASC 845, Nonmonetary Transactions – Purchases and Sales of Inventory with the Same Counterparty |
Schedule of New Accounting Pronouncements and Changes in Accounting Principles | Reporting these crude oil contracts on a gross revenue basis would increase our reported revenues as follows for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Revenue gross-up $ 448,846 $ 203,095 $ 314,270 |
Prepayments and Other Current_2
Prepayments and Other Current Assets (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |
Components of prepayments and other current assets | The components of prepayments and other current assets were as follows at the dates indicated (in thousands): December 31, 2018 2017 Insurance premiums $ 677 $ 425 Rents, licenses and other 880 839 Total $ 1,557 $ 1,264 |
Property and Equipment (Tables)
Property and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Property, Plant and Equipment [Abstract] | |
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 2018 2017 Tractors and trailers (1) 5 – 6 $ 96,523 $ 88,065 Field equipment 2 – 5 20,725 18,490 Buildings 5 – 39 15,746 15,727 Office equipment 2 – 5 1,863 1,929 Land 1,790 1,790 Construction in progress 2,794 275 Total 139,441 126,276 Less accumulated depreciation (94,818) (96,914) Property and equipment, net $ 44,623 $ 29,362 ______________ (1) Amounts include tractors held under capital leases in our crude oil marketing segment. At December 31, 2018 and 2017, gross property and equipment associated with assets held under capital leases were $4.7 million and $1.8 million, respectively. Accumulated amortization associated with assets held under capital leases were $0.7 million and $0.1 million at December 31, 2018 and 2017, respectively (see Note 15 for further information). Components of depreciation, depletion and amortization expense were as follows for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Depreciation, depletion and amortization, excluding amounts under capital leases $ 10,112 $ 13,478 $ 18,792 Amortization of property and equipment under capital leases 542 121 — Total depreciation, depletion and amortization $ 10,654 $ 13,599 $ 18,792 |
Purchase price allocation | The purchase price of approximately $10.3 million was allocated on October 1, 2018 as follows (in thousands): Tractors $ 4,799 Trailers 4,901 Field equipment 381 Materials and supplies 191 Total $ 10,272 |
Pre-tax gain on the sale of equipment | We sold certain used trucks and equipment and recorded net pre-tax gains as follows for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Gains on sales of used trucks and equipment $ 1,240 $ 594 $ 1,966 |
Schedule of Impairment of Oil and Gas Properties | Impairment provisions included in upstream crude oil and natural gas exploration and production segment operating losses were as follows for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Producing property impairments $ — $ — $ 30 Non-producing property impairments — 3 283 Total crude oil and natural gas impairments $ — $ 3 $ 313 |
Company's asset retirement obligations | A summary of our AROs is presented as follows for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 ARO liability beginning balance $ 1,273 $ 2,329 $ 2,469 Liabilities incurred 252 18 162 Accretion of discount 36 58 92 Liabilities settled (36) (261) (394) Deconsolidation of subsidiary (1) — (871) — ARO liability ending balance $ 1,525 $ 1,273 $ 2,329 _______________ |
Cash Deposits and Other Assets
Cash Deposits and Other Assets (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |
Components of cash deposits and other assets | Components of cash deposits and other assets were as follows at the dates indicated (in thousands): December 31, 2018 2017 Amounts associated with liability insurance program: Insurance collateral deposits (1) $ 1,453 $ 3,767 Excess loss fund 1,916 2,284 Accumulated interest income 788 814 Other amounts: State collateral deposits 57 57 Materials and supplies 443 273 Other — 37 Total $ 4,657 $ 7,232 _______________ |
Segment Reporting (Tables)
Segment Reporting (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Segment Reporting [Abstract] | |
Information concerning business activities | Information concerning our various business activities was follows for the periods indicated (in thousands): Reporting Segments Marketing Transportation Oil and Gas and Other Total Year Ended December 31, 2018 Revenues $ 1,694,437 $ 55,776 $ — $ 1,750,213 Segment operating (losses) earnings (1) 7,008 3,337 — 10,345 Depreciation, depletion and amortization 6,384 4,270 — 10,654 Property and equipment additions (3) (4) 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 (1) (2) 11,700 (544) 53 11,209 Depreciation, depletion and amortization 7,812 5,364 423 13,599 Property and equipment additions (3) 468 351 1,825 2,644 Year Ended December 31, 2016 Revenues $ 1,043,775 $ 52,355 $ 3,410 $ 1,099,540 Segment operating (losses) earnings (1) 17,045 (48) (533) 16,464 Depreciation, depletion and amortization 9,997 7,249 1,546 18,792 Property and equipment additions 1,321 6,868 295 8,484 _________________ (1) Our crude oil marketing segment’s operating earnings included inventory valuation losses of $5.4 million for the year ended December 31, 2018, and inventory liquidation gains of $3.3 million and $8.2 million for the years ended December 31, 2017 and 2016, respectively. (2) Segment operating (losses) earnings includes approximately $0.4 million of costs related to a voluntary early retirement program that was implemented in August 2017. (3) Our crude oil marketing segment’s property and equipment additions do not include approximately $2.9 million and $1.8 million of tractors acquired during the years ended December 31, 2018 and 2017, respectively, under capital leases. See Note 15 for further information. |
Reconciliation of segment earnings to earnings before income taxes | Segment operating earnings reflect revenues net of operating costs and depreciation, depletion and amortization expense and are reconciled to earnings (losses) before income taxes and investment in unconsolidated affiliate, as follows for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Segment operating earnings $ 10,345 $ 11,209 $ 16,464 General and administrative (1) (8,937) (9,707) (10,410) Operating earnings (losses) 1,408 1,502 6,054 Loss on deconsolidation of subsidiary — (3,505) — Impairment of investment in unconsolidated affiliate — (2,500) — Interest income 2,155 1,103 582 Interest expense (109) (27) (2) (Losses) earnings before income taxes and investment in unconsolidated affiliate $ 3,454 $ (3,427) $ 6,634 _______________ |
Identifiable assets by industry segment | Identifiable assets by industry segment were as follows at the dates indicated (in thousands): December 31, 2018 2017 2016 Reporting segment: Marketing $ 119,370 $ 134,745 $ 107,257 Transportation 34,112 29,069 32,120 Oil and Gas (1) — 425 7,279 Cash and other 125,388 118,465 100,216 Total assets $ 278,870 $ 282,704 $ 246,872 ____________________ (1) At December 31, 2017, amount represents our remaining cost method investment in this segment. See Note 4 for further information. |
Transactions with Affiliates (T
Transactions with Affiliates (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Related Party Transactions [Abstract] | |
Schedule of activities with affiliates | Activities with affiliates were as follows for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Overhead recoveries (1) $ — $ — $ 32 Affiliate billings to us 75 81 65 Billings to affiliates 6 4 5 Rentals paid to affiliate 487 583 628 Fee paid to Bencap (2) — 108 583 ___________________ (1) In connection with the operation of certain crude oil and natural gas properties, we charged related parties for administrative overhead. In late 2016, these charges ended as properties were either plugged and abandoned or operating responsibilities for these properties were transferred to another entity. (2) Amount represents fees paid to Bencap through the forfeiture of our investment during the first quarter of 2017. As a result of the investment forfeiture, Bencap is no longer an affiliate. |
Derivative Instruments and Fa_2
Derivative Instruments and Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivatives reflected in the consolidated balance sheet | The estimated fair value of forward month commodity contracts (derivatives) reflected in the accompanying consolidated balance sheet were as follows at the date indicated (in thousands): December 31, 2018 Balance Sheet Location and Amount Current Other Current Other Assets Assets Liabilities Liabilities Asset derivatives: Fair value forward hydrocarbon commodity contracts at gross valuation $ 162 $ — $ — $ — Liability derivatives: Fair value forward hydrocarbon commodity contracts at gross valuation — — 139 — Less counterparty offsets — — — — As reported fair value contracts $ 162 $ — $ 139 $ — At December 31, 2017, we had in place twenty commodity purchase and sale contracts, of which four of these contracts had no fair value associated with them as the contractual prices of crude oil were within the range of prices specified in the agreements. These commodity purchase and sale contracts encompassed approximately: • 452 barrels per day of crude oil during January 2018; • 322 barrels per day of crude oil during February through May 2018; • 258 barrels per day of crude oil during June 2018; • 646 barrels per day of crude oil during July 2018; • 322 barrels per day of crude oil during August through September 2018; and • 258 barrels per day of crude oil during October through December 2018. The estimated fair value of forward month commodity contracts (derivatives) reflected in the accompanying consolidated balance sheet were as follows at the date indicated (in thousands): December 31, 2017 Balance Sheet Location and Amount Current Other Current Other Assets Assets Liabilities Liabilities Asset derivatives: Fair value forward hydrocarbon commodity contracts at gross valuation $ 166 $ — $ — $ — Liability derivatives: Fair value forward hydrocarbon commodity contracts at gross valuation — — 145 — Less counterparty offsets — — — — As reported fair value contracts $ 166 $ — $ 145 $ — |
Derivatives reflected in the consolidated statement of operations | Forward month commodity contracts (derivatives) reflected in the accompanying consolidated statements of operations were as follows for the periods indicated (in thousands): Gains (Losses) Year Ended December 31, 2018 2017 2016 Revenues – marketing $ 2 $ (26) $ 243 |
Fair value assets and liabilities | The following tables set forth, by level with the Level 1, 2 and 3 fair value hierarchy, the carrying values of our financial assets and liabilities at the dates indicated (in thousands): December 31, 2018 Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Assets Observable Unobservable and Liabilities Inputs Inputs Counterparty (Level 1) (Level 2) (Level 3) Offsets Total Derivatives: Current assets $ — $ 162 $ — $ — $ 162 Current liabilities — (139) — — (139) Net value $ — $ 23 $ — $ — $ 23 December 31, 2017 Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Assets Observable Unobservable and Liabilities Inputs Inputs Counterparty (Level 1) (Level 2) (Level 3) Offsets Total Derivatives: Current assets $ — $ 166 $ — $ — $ 166 Current liabilities — (145) — — (145) Net value $ — $ 21 $ — $ — $ 21 |
Fair value, nonrecurring | Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of impairment. During the year ended December 31, 2018, we had no long-lived assets that were subject to non-recurring fair value measurements. The following table presents categories of long-lived assets that were subject to non-recurring fair value measurements during the year ended December 31, 2017 (in thousands): Fair Value Measurements at the End of the Reporting Period Using Quoted Prices in Active Significant Carrying Markets for Other Significant Total Value at Identical Assets Observable Unobservable Non-Cash December 31, and Liabilities Inputs Inputs Impairment 2017 (Level 1) (Level 2) (Level 3) Loss Oil and gas properties — Investment in AREC $ 425 $ — $ 425 $ — $ 3,505 Investment in VestaCare — — — — 2,500 $ 6,005 The following table presents categories of long-lived assets that were subject to non-recurring fair value measurements during the year ended December 31, 2016 (in thousands): Fair Value Measurements at the End of the Reporting Period Using Quoted Prices in Active Significant Carrying Markets for Other Significant Total Value at Identical Assets Observable Unobservable Non-Cash December 31, and Liabilities Inputs Inputs Impairment 2016 (Level 1) (Level 2) (Level 3) Loss Investment in Bencap $ — $ — $ — $ — $ 2,200 Oil and gas properties 62,784 — — 62,784 313 $ 2,513 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Components of the company's income tax (provision) benefit | The components of our income tax (provision) benefit were as follows for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Current: Federal $ 388 $ (1,418) $ (2,103) State 39 523 (675) Total current 427 (895) (2,778) Deferred: Federal (752) 3,722 777 State (184) 118 80 Total deferred (936) 3,840 857 Total (provision for) benefit from income taxes (1) $ (509) $ 2,945 $ (1,921) ______________ (1) 2016 includes a tax benefit of $0.8 million related to losses from our investment in Bencap, and is included in the loss from investment in unconsolidated affiliate category on the consolidated statements of operations. |
Reconciliation of taxes computed at the corporate federal income tax rate to the reported income tax (provision) | A reconciliation of the (provision for) benefit from income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes was as follows for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Pre-tax net book income (loss) (1) $ 3,454 $ (3,427) $ 4,434 Statutory federal income tax (provision) benefit $ (725) $ 1,165 $ (1,552) State income tax (provision) benefit (145) 736 (387) Federal statutory depletion — 153 62 Federal tax rate adjustment — 2,007 — Valuation allowance — (1,038) — Reverse valuation allowance 98 — — Return to provision adjustments 388 — — Other (125) (78) (44) Total (provision for) benefit from income taxes $ (509) $ 2,945 $ (1,921) Effective income tax rate (2) (3) 15% 86% 43% _______________ (1) 2016 includes the pre-tax loss from investment in unconsolidated affiliate of $2.2 million. (2) Excluding the adjustment related to the federal tax rate change, the effective income tax rate for 2017 is 58 percent. |
Components of the federal deferred tax asset (liability) | Deferred income taxes reflect the net difference between the financial statement carrying amounts and the underlying income tax basis in these items. The components of the federal deferred tax asset (liability) were as follows at the dates indicated (in thousands): December 31, 2018 2017 Long-term deferred tax asset (liability): (1) Prepaid and other insurance $ (170) $ (684) Property (5,259) (2,497) Investments in unconsolidated affiliates 525 623 Valuation allowance related to investments in unconsolidated affiliates (525) (623) Net operating loss 1,436 — Other (245) (121) Net long-term deferred tax liability (4,238) (3,302) Net deferred tax liability $ (4,238) $ (3,302) ______________ (1) Amounts as of December 31, 2017 have been revalued at 21 percent as a result of the enactment of the Tax Cuts and Jobs Act on December 22, 2017. |
Earliest tax years remaining for federal and major states of operations | The earliest tax years remaining open for audit for federal and major states of operations are as follows: Earliest Open Tax Year Federal 2014 Texas 2014 Louisiana 2015 Michigan 2014 |
Share-Based Compensation Plan (
Share-Based Compensation Plan (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Share-based Compensation, Activity | The following table presents restricted stock unit award activity for the periods indicated: Weighted- Average Grant Number of Date Fair Value Shares per Share (1) Restricted stock unit awards at January 1, 2018 — $ — Granted (2) 13,733 $ 43.00 Vested — $ — Forfeited — $ — Restricted stock unit awards at December 31, 2018 13,733 $ — ____________________ (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. (2) The aggregate grant date fair value of restricted stock unit awards issued during 2018 was $0.6 million based on a grant date market price of our common shares of $43.00 per share. Unrecognized compensation cost associated with restricted stock unit awards was approximately $0.4 million at December 31, 2018. Due to the graded vesting provisions of these awards, we expect to recognize the remaining compensation cost for these awards over a weighted-average period of 1.5 years. Performance Share Unit Awards An award granted as performance-based compensation is awarded to a participant contingent upon attainment of our future performance goals during a performance cycle. The performance goals were pre-established by the Compensation Committee. Following the end of the performance period, the holder of a performance-based compensation award is entitled to receive payment of an amount not exceeding the number of shares of common stock subject to, or the maximum value of, the performance-based compensation award, based on the achievement of the performance measures for the performance period. The performance share unit awards generally vest in full approximately three The fair value of a performance share unit award is based on the market price per share of our common shares on the date of grant. Compensation expense is recognized based on the grant date fair value over the requisite service or vesting period. Compensation expense will be adjusted for the performance goals on a quarterly basis. The following table presents performance share unit award activity for the periods indicated: Weighted- Average Grant Number of Date Fair Value Shares per Share (1) Performance share unit awards at January 1, 2018 — $ — Granted (2) 7,932 $ 43.00 Performance factor decrease (3) (3,966) $ 43.00 Vested — $ — Forfeited — $ — Performance share unit awards at December 31, 2018 3,966 $ — ____________________ (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. (2) The aggregate grant date fair value of performance share unit awards issued during 2018 was $0.2 million based on a grant date market price of our common share of $43.00 per share and assuming a performance factor of 100 percent. |
Supplemental Cash Flow Inform_2
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Cash Flow Elements [Abstract] | |
Schedule of supplemental cash flow information | Supplemental cash flows and non-cash transactions were as follows for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Cash paid for interest $ 109 $ 22 $ 2 Cash paid for federal and state income taxes 787 459 2,589 Non-cash transactions: Change in accounts payable related to property and equipment additions 1,685 70 679 Property and equipment acquired under capital leases 2,898 1,808 — |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of principal contractual commitments outstanding under our capital leases | The following table summarizes our principal contractual commitments outstanding under our capital leases at December 31, 2018 for the next five years, and in total thereafter (in thousands): 2019 $ 1,052 2020 1,052 2021 1,052 2022 909 2023 451 Thereafter — Total minimum lease payments 4,516 Less: Amount representing interest (424) Present value of capital lease obligations 4,092 Less current portion of capital lease obligations (883) Total long-term capital lease obligations $ 3,209 |
Rental expense | Rental expense was as follows for the periods indicated (in thousands): Year Ended December 31, 2018 2017 2016 Rental expense $ 11,078 $ 12,073 $ 11,314 |
Long-term non-cancelable operating leases and terminal arrangements for the next five years | At December 31, 2018, rental obligations under non-cancelable operating leases and terminal arrangements with terms in excess of one year for the next five years and thereafter are payable as follows (in thousands): 2019 $ 4,242 2020 2,258 2021 2,107 2022 1,782 2023 1,495 Thereafter 1,488 Total operating lease payments $ 13,372 |
Schedule of expenses and losses incurred but not reported | The amount of pre-funded insurance premiums left to cover potential future losses and our accruals for automobile and workers’ compensation claims were as follows at the dates indicated (in thousands): December 31, 2018 2017 Pre-funded premiums for losses incurred but not reported $ 427 $ 988 Accrued automobile and workers’ compensation claims 2,246 450 |
Schedule of accrued medical claims | Medical accrual amounts were as follows at the dates indicated (in thousands): December 31, 2018 2017 Accrued medical claims $ 1,181 $ 1,329 |
Concentration of Credit Risk (T
Concentration of Credit Risk (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Risks and Uncertainties [Abstract] | |
Schedule of concentration of risk | We believe that a loss of any of those customers where we currently derive more than 10 percent of our revenues would not have a material adverse effect on our operations as shown in the table below: Individual customer sales Individual customer receivables in excess in excess of 10% of revenues of 10% of total receivables Year Ended December 31, December 31, 2018 2017 2016 2018 2017 2016 27.3 % 22.8 % 18.2 % 18.4 % 19.1 % 20.9 % 14.1 % 17.1 % 16.5 % 11.9 % 15.0 % 14.0 % 10.8 % 15.9 % 11.1 % 10.1 % 10.7 % 10.6 % 10.4 % |
Quarterly Financial Informati_2
Quarterly Financial Information (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |
Selected quarterly financial data and earnings per share | The following table presents selected quarterly financial data for the periods indicated (in thousands, except per share data): First Second Third Fourth Quarter Quarter Quarter Quarter Year Ended December 31, 2018 Revenues $ 387,256 $ 452,417 $ 467,891 $ 442,649 Operating (losses) earnings (1) 1,077 4,298 2,239 (6,206) Net (losses) earnings 1,138 3,620 2,035 (3,848) Earnings (losses) per share: Basic net (losses) earnings per share $ 0.27 $ 0.86 $ 0.48 $ (0.91) Diluted net (losses) earnings per share $ 0.27 $ 0.86 $ 0.48 $ (0.91) Year Ended December 31, 2017 Revenues $ 303,087 $ 315,202 $ 295,311 $ 408,460 Operating (losses) earnings (1,584) 619 (1,290) 3,757 Net (losses) earnings (860) (282) (3,033) 3,693 Earnings (losses) per share: Basic and diluted net (losses) earnings per share $ (0.20) $ (0.07) $ (0.72) $ 0.88 ____________________ (1) The fourth quarter of 2018 includes inventory valuation losses of approximately $7.9 million in our crude oil marketing segment. |
Oil and Gas Producing Activit_2
Oil and Gas Producing Activities (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Cost incurred in oil and gas exploration and development activities | Total costs incurred in crude oil and natural gas exploration and development activities, all within the U.S., were as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 Property acquisition costs: Unproved $ 4 $ 32 Exploration costs: Expensed 5 291 Development costs 1,815 — Total costs incurred $ 1,824 $ 323 |
Proved developed and undeveloped oil and gas reserves | Proved developed and undeveloped reserves were as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 Natural Crude Natural Crude Gas Oil Gas Oil (Mcf) (Bbls) (Mcf) (Bbls) Total proved reserves: Beginning of year 4,214 187 4,835 226 Revisions of previous estimates — — 65 24 Crude oil and natural gas reserves sold (4,067) (170) (175) (4) Extensions, discoveries and other reserve additions 42 6 151 18 Production (189) (23) (662) (77) End of year — — 4,214 187 |
Components of proved oil and gas reserves | The components of our previously owned proved crude oil and natural gas reserves, all within the U.S., were as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 Natural Crude Natural Crude Gas Oil Gas Oil (Mcf) (Bbls) (Mcf) (Bbls) Proved developed reserves — — 4,214 187 Proved undeveloped reserves — — — — Total proved reserves — — 4,214 187 |
Standardized measure of discounted future net cash flows | The disclosures below do not purport to present the fair market value of our previously owned crude oil and natural gas reserves. An estimate of the fair market value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, a discount factor more representative of the time value of money and risks inherent in reserve estimates. The standardized measure of discounted future net cash flows was as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 Future gross revenues $ — $ 17,938 Future costs: Lease operating expenses — (12,421) Development costs — (38) Future net cash flows before income taxes — 5,479 Discount at 10% per annum — (2,002) Discounted future net cash flows before income taxes — 3,477 Future income taxes, net of discount at 10% per annum — (1,217) Standardized measure of discounted future net cash flows $ — $ 2,260 |
Assumed market prices of oil and natural gas reserves and future net revenues | The estimated value of crude oil and natural gas reserves and future net revenues derived therefrom are highly dependent upon crude oil and natural gas commodity price assumptions. For these estimates, our independent petroleum engineers assumed market prices as follows for the periods indicated: Year Ended December 31, 2017 2016 Market price: Crude oil per barrel $ — $ 38.34 Natural gas per thousand cubic feet (Mcf) $ — $ 2.56 |
Effect of income taxes and discounting on the standardized measure of discounted future net cash flows | The effect of income taxes and discounting on the standardized measure of discounted future net cash flows was as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 Future net cash flows before income taxes $ — $ 5,479 Future income taxes — (1,918) Future net cash flows — 3,561 Discount at 10% per annum — (1,301) Standardized measure of discounted future net cash flows $ — $ 2,260 |
Principal sources of changes in the standardized measure of discounted future net flows | The principal sources of changes in the standardized measure of discounted future net cash flows were as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 Beginning of year $ 2,260 $ 3,527 Sale of crude oil and natural gas reserves (2,732) (350) Net change in prices and production costs — (1,391) New field discoveries and extensions, net of future production costs 94 275 Sales of crude oil and natural gas produced, net of production costs (476) 87 Net change due to revisions in quantity estimates — 181 Accretion of discount 130 194 Production rate changes and other (493) (945) Net change in income taxes 1,217 682 End of year $ — $ 2,260 |
Results of operations for oil and gas producing activities | The results of crude oil and natural gas producing activities, excluding corporate overhead and interest costs, were as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 Revenues $ 1,427 $ 3,410 Costs and expenses: Production (951) (3,337) Producing property impairment — (30) Depreciation, depletion and amortization (423) (1,546) Operating earnings (losses) before income taxes 53 (1,503) Income tax benefit (expense) (19) 526 Operating earnings (losses) $ 34 $ (977) |
Organization and Basis of Pre_2
Organization and Basis of Presentation (Details) | 3 Months Ended | 12 Months Ended | |
Sep. 30, 2017agreement | Dec. 31, 2017segment | Dec. 31, 2018state | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||
Number of states in which entity operates | state | 48 | ||
Number of asset purchase and sales agreements with three unaffiliated parties | agreement | 3 | ||
Number of operating segments | 3 | ||
Number of reportable segments | 3 |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies - Accounts Receivable and Allowance for Doubtful Accounts (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Accounting Policies [Abstract] | |||
Industry practice payment of receivables | 20 days | ||
Changes in the allowance for doubtful accounts [Roll Forward] | |||
Balance at beginning of period | $ 303 | $ 225 | $ 206 |
Charges to costs and expenses | 43 | 137 | 100 |
Deductions | (193) | (59) | (81) |
Balance at end of period | $ 153 | $ 303 | $ 225 |
Product Concentration Risk | Accounts Receivable | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 90.00% |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies - Earnings per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||||
Earnings (losses) from continuing operations | $ 2,945 | $ (482) | $ 3,943 | ||||||||
Losses from investment in unconsolidated affiliate, net of tax | 0 | 0 | (1,430) | ||||||||
Net (losses) earnings | $ (3,848) | $ 2,035 | $ 3,620 | $ 1,138 | $ 3,693 | $ (3,033) | $ (282) | $ (860) | $ 2,945 | $ (482) | $ 2,513 |
Basic weighted average number of shares outstanding (in shares) | 4,218 | 4,218 | 4,218 | ||||||||
Basic earnings (losses) per share: | |||||||||||
From continuing operations (in dollars per share) | $ 0.70 | $ (0.11) | $ 0.94 | ||||||||
From investment in unconsolidated affiliate (in dollars per share) | 0 | 0 | (0.34) | ||||||||
Basic net (losses) earnings per common share (in dollars per share) | $ (0.91) | $ 0.48 | $ 0.86 | $ 0.27 | $ 0.70 | $ (0.11) | $ 0.60 | ||||
Diluted earnings (losses) per share: | |||||||||||
Diluted weighted average number of shares outstanding (in shares) | 4,218 | 4,218 | 4,218 | ||||||||
From continuing operations (in dollars per share) | $ 0.70 | $ (0.11) | $ 0.94 | ||||||||
From investment in unconsolidated affiliate (in dollars per share) | 0 | 0 | (0.34) | ||||||||
Diluted earnings (losses) per share (in dollars per share) | $ (0.91) | $ 0.48 | $ 0.86 | $ 0.27 | $ 0.70 | $ (0.11) | $ 0.60 | ||||
Restricted stock units awards | |||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||||
Units award | 0 | 0 | 0 | ||||||||
Performance share unit awards | |||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||||
Units award | 0 | 0 | 0 |
Summary of Significant Accoun_6
Summary of Significant Accounting Policies - Employee Benefits (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Accounting Policies [Abstract] | |||
Contributory expenses | $ 808 | $ 734 | $ 757 |
Summary of Significant Accoun_7
Summary of Significant Accounting Policies - Inventory (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Accounting Policies [Abstract] | ||
Inventory write-down | $ 5,400 | $ 0 |
Summary of Significant Accoun_8
Summary of Significant Accounting Policies - Letter of Credit Facility (Details) - USD ($) | Dec. 31, 2018 | Dec. 31, 2017 |
Line of Credit Facility [Line Items] | ||
Letters of credit outstanding | $ 4,200,000 | |
Wells Fargo Bank | ||
Line of Credit Facility [Line Items] | ||
Line of credit facility, maximum borrowing capacity | 60,000,000 | |
Wells Fargo Bank | Standby Letters of Credit | ||
Line of Credit Facility [Line Items] | ||
Letters of credit outstanding | $ 4,600,000 | $ 2,200,000 |
Summary of Significant Accoun_9
Summary of Significant Accounting Policies - Property and Equipment (Details) | 12 Months Ended |
Dec. 31, 2018 | |
Minimum | |
Property, Plant and Equipment [Line Items] | |
Property and equipment, useful life | 2 years |
Maximum | |
Property, Plant and Equipment [Line Items] | |
Property and equipment, useful life | 39 years |
Summary of Significant Accou_10
Summary of Significant Accounting Policies - New Accounting Pronouncements (Details) - Accounting Standards Update 2016-02 - Forecast $ in Thousands | Jan. 01, 2019USD ($) |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
Operating lease, right-of-use asset | $ 11,400 |
Operating lease, liability | $ 11,400 |
Revenue Recognition - Revenue D
Revenue Recognition - Revenue Disaggregation (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Revenue from Contract with Customer [Abstract] | |||||||||||
Revenue, performance obligation, description of timing | Payment is typically due in full within 30 days of the invoice date. | ||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Total revenues from contracts with customers | $ 1,636,773 | ||||||||||
Total revenues | $ 442,649 | $ 467,891 | $ 452,417 | $ 387,256 | $ 408,460 | $ 295,311 | $ 315,202 | $ 303,087 | 1,750,213 | $ 1,322,060 | $ 1,099,540 |
Goods transferred at a point in time | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Total revenues from contracts with customers | 1,580,997 | ||||||||||
Services transferred over time | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Total revenues from contracts with customers | 55,776 | ||||||||||
Revenues from contracts with customers | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Total revenues from contracts with customers | 1,636,773 | ||||||||||
Other | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Total revenues from contracts with customers | 113,440 | ||||||||||
Marketing | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Total revenues from contracts with customers | 1,580,997 | ||||||||||
Total revenues | 1,694,437 | 1,267,275 | 1,043,775 | ||||||||
Marketing | Goods transferred at a point in time | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Total revenues from contracts with customers | 1,580,997 | ||||||||||
Marketing | Services transferred over time | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Total revenues from contracts with customers | 0 | ||||||||||
Marketing | Revenues from contracts with customers | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Total revenues from contracts with customers | 1,580,997 | ||||||||||
Marketing | Other | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Total revenues from contracts with customers | 113,440 | ||||||||||
Transportation | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Total revenues from contracts with customers | 55,776 | ||||||||||
Total revenues | 55,776 | $ 53,358 | $ 52,355 | ||||||||
Transportation | Goods transferred at a point in time | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Total revenues from contracts with customers | 0 | ||||||||||
Transportation | Services transferred over time | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Total revenues from contracts with customers | 55,776 | ||||||||||
Transportation | Revenues from contracts with customers | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Total revenues from contracts with customers | 55,776 | ||||||||||
Transportation | Other | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Total revenues from contracts with customers | $ 0 |
Revenue Recognition - Other Rev
Revenue Recognition - Other Revenue (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||
Total revenues from contracts with customers | $ 1,636,773 | ||
Accounting Standards Update 2014-09 | Revenue gross-up | |||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | |||
Total revenues from contracts with customers | $ 448,846 | $ 203,095 | $ 314,270 |
Subsidiary Bankruptcy, Decons_2
Subsidiary Bankruptcy, Deconsolidation and Sale (Details) - USD ($) $ in Thousands | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 01, 2017 | Apr. 30, 2017 | Apr. 25, 2017 | |
Subsidiary Bankruptcy and Deconsolidation [Line Items] | |||||||||
Loss on deconsolidation of subsidiary | $ 0 | $ 3,505 | $ 0 | ||||||
Proceeds from sales of AREC assets | $ 2,800 | 0 | 2,775 | $ 0 | |||||
Accounts receivable – related party | 0 | $ 425 | 0 | ||||||
AREC | |||||||||
Subsidiary Bankruptcy and Deconsolidation [Line Items] | |||||||||
Loss on deconsolidation of subsidiary | $ 1,600 | ||||||||
DIP financing amount arranged | $ 1,250 | ||||||||
DIP amount outstanding | $ 400 | $ 400 | $ 400 | ||||||
AREC | LIBOR | |||||||||
Subsidiary Bankruptcy and Deconsolidation [Line Items] | |||||||||
DIP financing, interest rate | 2.00% | ||||||||
AREC | Disposal Group, Held-for-sale, Not Discontinued Operations | |||||||||
Subsidiary Bankruptcy and Deconsolidation [Line Items] | |||||||||
Expected transaction price | $ 5,000 | $ 5,200 | $ 5,000 | ||||||
Loss on disposal | $ 1,900 |
Prepayments and Other Current_3
Prepayments and Other Current Assets (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | ||
Insurance premiums | $ 677 | $ 425 |
Rents, licenses and other | 880 | 839 |
Total | $ 1,557 | $ 1,264 |
Property and Equipment - Cost o
Property and Equipment - Cost of Property and Equipment and Related Accumulated Depreciaiton, Depletion, and Amortization (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Property, Plant and Equipment [Line Items] | |||
Property and equipment, gross | $ 139,441 | $ 126,276 | |
Less accumulated depreciation, depletion and amortization | (94,818) | (96,914) | |
Property and equipment, net | 44,623 | 29,362 | |
Depreciation, depletion and amortization | $ 10,654 | 13,599 | $ 18,792 |
Minimum | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment, useful life | 2 years | ||
Maximum | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment, useful life | 39 years | ||
Tractors and trailers | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment, gross | $ 96,523 | 88,065 | |
Tractors and trailers | Minimum | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment, useful life | 5 years | ||
Tractors and trailers | Maximum | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment, useful life | 6 years | ||
Field equipment | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment, gross | $ 20,725 | 18,490 | |
Field equipment | Minimum | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment, useful life | 2 years | ||
Field equipment | Maximum | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment, useful life | 5 years | ||
Buildings | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment, gross | $ 15,746 | 15,727 | |
Buildings | Minimum | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment, useful life | 5 years | ||
Buildings | Maximum | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment, useful life | 39 years | ||
Office equipment | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment, gross | $ 1,863 | 1,929 | |
Office equipment | Minimum | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment, useful life | 2 years | ||
Office equipment | Maximum | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment, useful life | 5 years | ||
Land | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment, gross | $ 1,790 | 1,790 | |
Construction in progress | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment, gross | 2,794 | 275 | |
Assets held under capital leases | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment, gross | 4,700 | 1,800 | |
Less accumulated depreciation, depletion and amortization | (700) | (100) | |
Depreciation, depletion and amortization | 542 | 121 | 0 |
Assets not held under capital leases | |||
Property, Plant and Equipment [Line Items] | |||
Depreciation, depletion and amortization | $ 10,112 | $ 13,478 | $ 18,792 |
Property and Equipment - Asset
Property and Equipment - Asset Acquisition (Details) $ in Thousands | Oct. 01, 2018USD ($)trucktrailer |
Property, Plant and Equipment [Abstract] | |
Cash payment for acquisition | $ 10,000 |
Number of tractor trailer trucks | truck | 113 |
Number of trailers | trailer | 126 |
Acquisition related costs | $ 300 |
Purchase price | $ 10,300 |
Property and Equipment - Purcha
Property and Equipment - Purchase Price Allocation (Details) $ in Thousands | Oct. 01, 2018USD ($) |
Property, Plant and Equipment [Abstract] | |
Tractors | $ 4,799 |
Trailers | 4,901 |
Field equipment | 381 |
Materials and supplies | 191 |
Total | $ 10,272 |
Property and Equipment - Sales
Property and Equipment - Sales of Equipment (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Property, Plant and Equipment [Line Items] | |||
Gains on sales of used trucks and equipment | $ 1,240 | $ 594 | $ 1,966 |
Trucks | |||
Property, Plant and Equipment [Line Items] | |||
Gains on sales of used trucks and equipment | $ 1,240 | $ 594 | $ 1,966 |
Property and Equipment - Impair
Property and Equipment - Impairment of Oil and Gas Properties (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Property, Plant and Equipment [Abstract] | |||
Producing property impairments | $ 0 | $ 0 | $ 30 |
Non-producing property impairments | 0 | 3 | 283 |
Total crude oil and natural gas impairments | $ 0 | $ 3 | $ 313 |
Property and Equipment - Asse_2
Property and Equipment - Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
ARO liability beginning balance | $ 1,273 | $ 2,329 | $ 2,469 |
Liabilities incurred | 252 | 18 | 162 |
Accretion of discount | 36 | 58 | 92 |
Liabilities settled | (36) | (261) | (394) |
Deconsolidation of subsidiary | 0 | (871) | 0 |
ARO liability ending balance | $ 1,525 | $ 1,273 | $ 2,329 |
Cash Deposits and Other Asset_2
Cash Deposits and Other Assets (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | ||
Insurance collateral deposits | $ 1,453 | $ 3,767 |
Excess loss fund | 1,916 | 2,284 |
Accumulated interest income | 788 | 814 |
State collateral deposits | 57 | 57 |
Materials and supplies | 443 | 273 |
Other | 0 | 37 |
Total | 4,657 | $ 7,232 |
Letters of credit outstanding | $ 4,200 |
Investments in Unconsolidated_2
Investments in Unconsolidated Affiliates (Details) - USD ($) | Oct. 01, 2018 | Dec. 31, 2017 | Feb. 28, 2017 | Apr. 30, 2016 | Jan. 31, 2016 | Sep. 30, 2017 | Jun. 30, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Schedule of Equity Method Investments [Line Items] | ||||||||||
Cash payment for acquisition | $ 10,000,000 | |||||||||
Recognized net loss from investment | $ 0 | $ 0 | $ 1,430,000 | |||||||
Impairment of investments in unconsolidated affiliates | 0 | 2,500,000 | 0 | |||||||
Losses from equity investment | 0 | 0 | 468,000 | |||||||
Loss on deconsolidation of subsidiary | 0 | 3,505,000 | 0 | |||||||
Proceeds from sales of AREC assets | $ 2,800,000 | 0 | 2,775,000 | 0 | ||||||
Receivable | 121,353,000 | $ 85,197,000 | 121,353,000 | |||||||
AREC | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Loss on deconsolidation of subsidiary | $ 1,600,000 | |||||||||
DIP amount outstanding | $ 400,000 | $ 400,000 | $ 400,000 | |||||||
AREC | Disposal Group, Held-for-sale, Not Discontinued Operations | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Loss on disposal | 1,900,000 | |||||||||
Bencap LLC | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Maximum borrowing amount | $ 1,500,000 | |||||||||
Income tax benefit | 800,000 | |||||||||
Percentage of equity method investment | 0.00% | |||||||||
VestaCare, Inc. | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Voting interest | 3.00% | |||||||||
Impairment of investments in unconsolidated affiliates | $ 2,500,000 | |||||||||
Percentage of equity method investment | 15.00% | 15.00% | ||||||||
AREC | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Receivable | $ 400,000 | |||||||||
Bencap LLC | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Voting interest | 30.00% | |||||||||
Cash payment for acquisition | $ 2,200,000 | |||||||||
Recognized net loss from investment | 1,400,000 | |||||||||
Impairment of investments in unconsolidated affiliates | 1,700,000 | |||||||||
Losses from equity investment | $ 500,000 | |||||||||
Additional funding request | $ 500,000 | |||||||||
VestaCare, Inc. | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Cash payment for acquisition | $ 2,500,000 |
Segment Reporting - Information
Segment Reporting - Information concerning business activities (Details) $ in Thousands | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||||||||
Aug. 31, 2017USD ($) | Dec. 31, 2018USD ($) | Sep. 30, 2018USD ($) | Jun. 30, 2018USD ($) | Mar. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($)segment | Dec. 31, 2016USD ($) | |
Segment Reporting Information [Line Items] | ||||||||||||
Number of reportable segments | segment | 3 | |||||||||||
Revenues | $ 442,649 | $ 467,891 | $ 452,417 | $ 387,256 | $ 408,460 | $ 295,311 | $ 315,202 | $ 303,087 | $ 1,750,213 | $ 1,322,060 | $ 1,099,540 | |
Operating earnings (losses) | 1,408 | 1,502 | 6,054 | |||||||||
Depreciation, depletion and amortization | 10,654 | 13,599 | 18,792 | |||||||||
Property and equipment additions | 11,731 | 2,644 | 8,484 | |||||||||
Inventory liquidation gains and valuation (losses) | (7,900) | (7,900) | ||||||||||
Voluntary early retirement program expense | $ 400 | 1,000 | ||||||||||
Property and equipment acquired under capital leases | 2,898 | 1,808 | 0 | |||||||||
Leasehold Improvements | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Property and equipment additions | 13 | |||||||||||
Marketing | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Revenues | 1,694,437 | 1,267,275 | 1,043,775 | |||||||||
Depreciation, depletion and amortization | 6,384 | 7,812 | 9,997 | |||||||||
Property and equipment additions | 1,540 | 468 | 1,321 | |||||||||
Inventory liquidation gains and valuation (losses) | $ (5,400) | $ 3,300 | (5,400) | 3,300 | 8,200 | |||||||
Transportation | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Revenues | 55,776 | 53,358 | 52,355 | |||||||||
Depreciation, depletion and amortization | 4,270 | 5,364 | 7,249 | |||||||||
Property and equipment additions | 10,178 | 351 | 6,868 | |||||||||
Oil and Gas and Other | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Revenues | 0 | 1,427 | 3,410 | |||||||||
Depreciation, depletion and amortization | 0 | 423 | 1,546 | |||||||||
Property and equipment additions | 13 | 1,825 | 295 | |||||||||
Operating Segments | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating earnings (losses) | 10,345 | 11,209 | 16,464 | |||||||||
Operating Segments | Marketing | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating earnings (losses) | 7,008 | 11,700 | 17,045 | |||||||||
Operating Segments | Transportation | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating earnings (losses) | 3,337 | (544) | (48) | |||||||||
Operating Segments | Oil and Gas and Other | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating earnings (losses) | $ 0 | $ 53 | $ (533) |
Segment Reporting - Reconciliat
Segment Reporting - Reconciliation of segment earnings to earnings before income taxes (Details) - USD ($) $ in Thousands | 1 Months Ended | 12 Months Ended | ||
Aug. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items] | ||||
Operating earnings (losses) | $ 1,408 | $ 1,502 | $ 6,054 | |
Loss on deconsolidation of subsidiary | 0 | (3,505) | 0 | |
Impairment of investment in unconsolidated affiliate | 0 | (2,500) | 0 | |
Interest income | 2,155 | 1,103 | 582 | |
Interest expense | (109) | (27) | (2) | |
(Losses) earnings before income taxes and investment in unconsolidated affiliate | 3,454 | (3,427) | 6,634 | |
Voluntary early retirement program expense | $ 400 | 1,000 | ||
Operating Segments | ||||
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items] | ||||
Operating earnings (losses) | 10,345 | 11,209 | 16,464 | |
Corporate, Non-Segment | ||||
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items] | ||||
Operating earnings (losses) | (8,937) | (9,707) | (10,410) | |
Segment Reconciling Items | ||||
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items] | ||||
Loss on deconsolidation of subsidiary | 0 | (3,505) | 0 | |
Impairment of investment in unconsolidated affiliate | 0 | (2,500) | 0 | |
Interest income | 2,155 | 1,103 | 582 | |
Interest expense | $ (109) | $ (27) | $ (2) |
Segment Reporting - Identifiabl
Segment Reporting - Identifiable assets by industry segment (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Segment Reporting Information [Line Items] | |||
Assets | $ 278,870 | $ 282,704 | |
Operating Segments | |||
Segment Reporting Information [Line Items] | |||
Assets | 278,870 | 282,704 | $ 246,872 |
Operating Segments | Marketing | |||
Segment Reporting Information [Line Items] | |||
Assets | 119,370 | 134,745 | 107,257 |
Operating Segments | Transportation | |||
Segment Reporting Information [Line Items] | |||
Assets | 34,112 | 29,069 | 32,120 |
Operating Segments | Oil and natural gas | |||
Segment Reporting Information [Line Items] | |||
Assets | 0 | 425 | 7,279 |
Corporate, Non-Segment | |||
Segment Reporting Information [Line Items] | |||
Assets | $ 125,388 | $ 118,465 | $ 100,216 |
Transactions with Affiliates (D
Transactions with Affiliates (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Related Party Transaction [Line Items] | |||
Interest income on DIP financing | $ 100 | ||
Affiliated Entities | |||
Related Party Transaction [Line Items] | |||
Overhead recoveries | $ 0 | 0 | $ 32 |
Affiliate billings to us | 75 | 81 | 65 |
Billings to affiliates | 6 | 4 | 5 |
Rentals paid to affiliate | 487 | 583 | 628 |
Fees paid to Bencap | $ 0 | $ 108 | $ 583 |
Derivative Instruments and Fa_3
Derivative Instruments and Fair Value Measurements - Narrative (Details) - Commodity Contract | 12 Months Ended | |
Dec. 31, 2018barrel_of_oil_per_daycontract | Dec. 31, 2017barrel_of_oil_per_daycontract | |
Derivative [Line Items] | ||
Number of contracts held | contract | 10 | 20 |
Reported Value Measurement | ||
Derivative [Line Items] | ||
Number of contracts held | contract | 4 | |
January through April 2019 | ||
Derivative [Line Items] | ||
Production per day | 322 | |
May 2,019 | ||
Derivative [Line Items] | ||
Production per day | 258 | |
June 2019 through August 2019 | ||
Derivative [Line Items] | ||
Production per day | 322 | |
September 2019 through December 2019 | ||
Derivative [Line Items] | ||
Production per day | 258 | |
January 2,018 | ||
Derivative [Line Items] | ||
Production per day | 452 | |
February through May 2018 | ||
Derivative [Line Items] | ||
Production per day | 322 | |
June 2,018 | ||
Derivative [Line Items] | ||
Production per day | 258 | |
July 2,018 | ||
Derivative [Line Items] | ||
Production per day | 646 | |
August through September 2018 | ||
Derivative [Line Items] | ||
Production per day | 322 | |
October through December 2018 | ||
Derivative [Line Items] | ||
Production per day | 258 |
Derivative Instruments and Fa_4
Derivative Instruments and Fair Value Measurements - Use of derivative instruments (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Derivative, Fair Value, Net [Abstract] | ||
As reported fair value contracts | $ 162 | $ 166 |
As reported fair value contracts | 139 | 145 |
Commodity Contract | Not Designated as Hedging Instrument | Current Assets | ||
Derivative, Fair Value, Net [Abstract] | ||
Asset derivatives: | 162 | 166 |
Liability derivatives: | 0 | 0 |
Less counterparty offsets | 0 | 0 |
As reported fair value contracts | 162 | 166 |
Commodity Contract | Not Designated as Hedging Instrument | Other Assets | ||
Derivative, Fair Value, Net [Abstract] | ||
Asset derivatives: | 0 | 0 |
Liability derivatives: | 0 | 0 |
Less counterparty offsets | 0 | 0 |
As reported fair value contracts | 0 | 0 |
Commodity Contract | Not Designated as Hedging Instrument | Current Liabilities | ||
Derivative, Fair Value, Net [Abstract] | ||
Asset derivatives: | 0 | 0 |
Liability derivatives: | 139 | 145 |
Less counterparty offsets | 0 | 0 |
As reported fair value contracts | 139 | 145 |
Commodity Contract | Not Designated as Hedging Instrument | Other Liabilities | ||
Derivative, Fair Value, Net [Abstract] | ||
Asset derivatives: | 0 | 0 |
Liability derivatives: | 0 | 0 |
Less counterparty offsets | 0 | 0 |
As reported fair value contracts | $ 0 | $ 0 |
Derivative Instruments and Fa_5
Derivative Instruments and Fair Value Measurements - Forward month commodity contracts (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Commodity Contract | Revenues - Marketing | Not Designated as Hedging Instrument | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Revenues – Marketing | $ 2 | $ (26) | $ 243 |
Derivative Instruments and Fa_6
Derivative Instruments and Fair Value Measurements - Derivatives by hedging relationship and fair value measurements (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Derivatives: | ||
Current assets | $ 162 | $ 166 |
Current assets, counterparty offsets | 0 | 0 |
Current liabilities | (139) | (145) |
Current liabilities, counterparty offsets | 0 | 0 |
Net value | 23 | 21 |
Net value, counterparty offsets | 0 | 0 |
Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) | ||
Derivatives: | ||
Current assets | 0 | 0 |
Current liabilities | 0 | 0 |
Net value | 0 | 0 |
Significant Unobservable Inputs (Level 3) | ||
Derivatives: | ||
Current assets | 162 | 166 |
Current liabilities | (139) | (145) |
Net value | 23 | 21 |
Significant Unobservable Inputs (Level 3) | ||
Derivatives: | ||
Current assets | 0 | 0 |
Current liabilities | 0 | 0 |
Net value | $ 0 | $ 0 |
Derivative Instruments and Fa_7
Derivative Instruments and Fair Value Measurements - Nonrecurring fair value measurements (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Non-cash impairment loss | $ 0 | $ 3,505 | $ 0 |
Fair Value, Measurements, Nonrecurring | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Non-cash impairment loss | 6,005 | 2,513 | |
Fair Value, Measurements, Nonrecurring | AREC | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Investments | 425 | ||
Non-cash impairment loss | 3,505 | ||
Fair Value, Measurements, Nonrecurring | VestaCare, Inc. | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Investments | 0 | ||
Non-cash impairment loss | 2,500 | ||
Fair Value, Measurements, Nonrecurring | Bencap LLC | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Investments | 0 | ||
Non-cash impairment loss | 2,200 | ||
Fair Value, Measurements, Nonrecurring | Oil and gas properties | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Investments | 62,784 | ||
Non-cash impairment loss | 313 | ||
Fair Value, Measurements, Nonrecurring | Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) | AREC | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Investments | 0 | ||
Fair Value, Measurements, Nonrecurring | Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) | VestaCare, Inc. | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Investments | 0 | ||
Fair Value, Measurements, Nonrecurring | Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) | Bencap LLC | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Investments | 0 | ||
Fair Value, Measurements, Nonrecurring | Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) | Oil and gas properties | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Investments | 0 | ||
Fair Value, Measurements, Nonrecurring | Significant Unobservable Inputs (Level 3) | AREC | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Investments | 425 | ||
Fair Value, Measurements, Nonrecurring | Significant Unobservable Inputs (Level 3) | VestaCare, Inc. | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Investments | 0 | ||
Fair Value, Measurements, Nonrecurring | Significant Unobservable Inputs (Level 3) | Bencap LLC | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Investments | 0 | ||
Fair Value, Measurements, Nonrecurring | Significant Unobservable Inputs (Level 3) | Oil and gas properties | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Investments | 0 | ||
Fair Value, Measurements, Nonrecurring | Significant Unobservable Inputs (Level 3) | AREC | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Investments | 0 | ||
Fair Value, Measurements, Nonrecurring | Significant Unobservable Inputs (Level 3) | VestaCare, Inc. | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Investments | $ 0 | ||
Fair Value, Measurements, Nonrecurring | Significant Unobservable Inputs (Level 3) | Bencap LLC | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Investments | 0 | ||
Fair Value, Measurements, Nonrecurring | Significant Unobservable Inputs (Level 3) | Oil and gas properties | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Investments | $ 62,784 |
Income Taxes - Components of th
Income Taxes - Components of the company's income tax (provision) benefit (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Current: | |||
Federal | $ 388 | $ (1,418) | $ (2,103) |
State | 39 | 523 | (675) |
Total current | 427 | (895) | (2,778) |
Deferred: | |||
Federal | (752) | 3,722 | 777 |
State | (184) | 118 | 80 |
Total deferred | (936) | 3,840 | 857 |
Total (provision for) benefit from income taxes | (509) | 2,945 | (1,921) |
Effective Income Tax Rate Reconciliation, Noncontrolling Interest Income (Loss), Amount | $ 0 | $ 0 | $ 770 |
Income Taxes - Reconciliation o
Income Taxes - Reconciliation of taxes computed at the corporate federal income tax rate to the reported income tax (provision) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |||
Pre-tax net book income (loss) | $ 3,454 | $ (3,427) | $ 4,434 |
Statutory federal income tax (provision) benefit | (725) | 1,165 | (1,552) |
State income tax (provision) benefit | (145) | 736 | (387) |
Federal statutory depletion | 0 | 153 | 62 |
Federal tax rate adjustment | 0 | 2,007 | 0 |
Valuation allowance | 98 | (1,038) | 0 |
Return to provision adjustments | 388 | 0 | 0 |
Other | (125) | (78) | (44) |
Total (provision for) benefit from income taxes | $ (509) | $ 2,945 | $ (1,921) |
Effective income tax rate | 15.00% | 86.00% | 43.00% |
Pre-tax losses from investments in unconsolidated affiliates | $ 2,200 | ||
Effective income tax rate excluding adjustment | 58.00% | ||
Return to provision adjustments | 26.00% |
Income Taxes - Components of _2
Income Taxes - Components of the federal deferred tax asset (liability) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Long-term deferred tax asset (liability) [Abstract] | ||
Prepaid and other insurance | $ (170) | $ (684) |
Property | (5,259) | (2,497) |
Investments in unconsolidated affiliates | 525 | 623 |
Valuation allowance related to investments in unconsolidated affiliates | (525) | (623) |
Net operating loss | (1,436) | 0 |
Other | (245) | (121) |
Net long-term deferred tax liability | (4,238) | (3,302) |
Net deferred tax liability | $ (4,238) | $ (3,302) |
Income Taxes - Earliest tax yea
Income Taxes - Earliest tax years remaining for federal and major states of operations (Details) | 12 Months Ended |
Dec. 31, 2018 | |
Federal | |
Income Tax Examination [Line Items] | |
Earliest Open Tax Year | 2,014 |
Texas | |
Income Tax Examination [Line Items] | |
Earliest Open Tax Year | 2,014 |
Louisiana | |
Income Tax Examination [Line Items] | |
Earliest Open Tax Year | 2,015 |
Michigan | |
Income Tax Examination [Line Items] | |
Earliest Open Tax Year | 2,014 |
Income Taxes - Other matters (D
Income Taxes - Other matters (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Income Tax Disclosure [Abstract] | |
Tax benefit from remeasurement of deferred tax liabilities | $ 2 |
Share-Based Compensation Plan_2
Share-Based Compensation Plan (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2018 | May 31, 2018 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Compensation expense in connection with equity-based awards | $ 300,000 | ||
The 2018 LTIP | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of shares authorized (in shares) | 120,403 | 120,403 | 150,000 |
Accrued dividends | $ 10,000 | $ 10,000 | |
The 2018 LTIP | Restricted stock units awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Award vesting rights, percentage | 33.00% | ||
Number of Shares | |||
Restricted stock unit awards at January 1, 2018 (in shares) | 0 | ||
Granted (in shares) | 13,733 | ||
Vested (in shares) | 0 | ||
Forfeited (in shares) | 0 | ||
Restricted stock unit awards at June 30, 2018 (in shares) | 13,733 | 13,733 | |
Weighted Average Grant Date Fair Value per Share | |||
Restricted stock unit awards at January 1, 2018 (in dollars per share) | $ 0 | ||
Granted (in dollars per share) | 43 | ||
Vested (in dollars per share) | 0 | ||
Forfeited (in dollars per share) | 0 | ||
Restricted stock unit awards at June 30, 2018 (in dollars per share) | $ 0 | $ 0 | |
Aggregate grant date fair value awards issues | $ 600,000 | ||
Unrecognized compensation cost | $ 400,000 | $ 400,000 | |
Period for recognition for remaining compensation cost | 1 year 6 months | ||
The 2018 LTIP | Performance share unit awards | |||
Number of Shares | |||
Restricted stock unit awards at January 1, 2018 (in shares) | 0 | ||
Granted (in shares) | 7,932 | ||
Performance factor decrease (in shares) | (3,966) | ||
Vested (in shares) | 0 | ||
Forfeited (in shares) | 0 | ||
Restricted stock unit awards at June 30, 2018 (in shares) | 3,966 | 3,966 | |
Weighted Average Grant Date Fair Value per Share | |||
Restricted stock unit awards at January 1, 2018 (in dollars per share) | $ 0 | ||
Granted (in dollars per share) | 43 | ||
Performance factor decrease (in dollars per share) | 43 | ||
Vested (in dollars per share) | 0 | ||
Forfeited (in dollars per share) | 0 | ||
Restricted stock unit awards at June 30, 2018 (in dollars per share) | $ 0 | $ 0 | |
Aggregate grant date fair value awards issues | $ 200,000 | ||
Performance factor | 50.00% | 100.00% | |
Unrecognized compensation cost | $ 100,000 | $ 100,000 | |
Period for recognition for remaining compensation cost | 2 years 4 months 24 days | ||
Award vesting period | 3 years |
Supplemental Cash Flow Inform_3
Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Supplemental Cash Flow Elements [Abstract] | |||
Cash paid for interest | $ 109 | $ 22 | $ 2 |
Cash paid for federal and state income taxes | 787 | 459 | 2,589 |
Non-cash transactions: | |||
Change in accounts payable related to property and equipment additions | 1,685 | 70 | 679 |
Property and equipment acquired under capital leases | $ 2,898 | $ 1,808 | $ 0 |
Commitments and Contingencies -
Commitments and Contingencies - Schedule of principal contractual commitments outstanding under our capital leases (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Commitments and Contingencies Disclosure [Abstract] | ||
2,019 | $ 1,052 | |
2,020 | 1,052 | |
2,021 | 1,052 | |
2,022 | 909 | |
2,023 | 451 | |
Thereafter | 0 | |
Total minimum lease payments | 4,516 | |
Less: Amount representing interest | (424) | |
Present value of capital lease obligations | 4,092 | |
Less current portion of capital lease obligations | (883) | $ (338) |
Total long-term capital lease obligations | $ 3,209 | $ 1,351 |
Commitments and Contingencies_2
Commitments and Contingencies - Narrative (Details) $ in Millions | Dec. 31, 2018USD ($) |
Loss Contingencies [Line Items] | |
Parental guaranteed obligations | $ 22.3 |
Minimum | |
Loss Contingencies [Line Items] | |
Operating lease term | 1 year |
Aggregate medical claims for umbrella insurance coverage per calendar year | $ 6 |
Maximum | |
Loss Contingencies [Line Items] | |
Operating lease term | 7 years |
Commitments and Contingencies_3
Commitments and Contingencies - Rental expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |||
Rental expense | $ 11,078 | $ 12,073 | $ 11,314 |
Commitments and Contingencies_4
Commitments and Contingencies - Long-term non-cancelable operating leases and terminal arrangements for the next five years (Details) $ in Thousands | Dec. 31, 2018USD ($) |
Commitments and Contingencies Disclosure [Abstract] | |
2,019 | $ 4,242 |
2,020 | 2,258 |
2,021 | 2,107 |
2,022 | 1,782 |
2,023 | 1,495 |
Thereafter | 1,488 |
Total | $ 13,372 |
Commitments and Contingencies_5
Commitments and Contingencies - Schedule of expenses and losses incurred but not reported (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Commitments and Contingencies Disclosure [Abstract] | ||
Pre-funded premiums for losses incurred but not reported | $ 427 | $ 988 |
Accrued automobile and workers’ compensation claims | $ 2,246 | $ 450 |
Commitments and Contingencies_6
Commitments and Contingencies - Schedule of accrued medical claims (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Commitments and Contingencies Disclosure [Abstract] | ||
Accrued medical claims | $ 1,181 | $ 1,329 |
Concentration of Credit Risk (D
Concentration of Credit Risk (Details) - customer | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Concentration Risk [Line Items] | |||
Percentage of U.S. demand supplied by company | 1.00% | ||
Customer Concentration Risk | Minimum | |||
Concentration Risk [Line Items] | |||
Number of customers | 3 | ||
Customer Concentration Risk | Maximum | |||
Concentration Risk [Line Items] | |||
Number of customers | 5 | ||
Customer Concentration Risk | Sales Revenue, Goods, Net | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 50.00% | ||
Customer Concentration Risk | Sales Revenue, Goods, Net | Customer One | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 27.30% | 22.80% | 18.20% |
Customer Concentration Risk | Sales Revenue, Goods, Net | Customer Two | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 14.10% | 17.10% | 16.50% |
Customer Concentration Risk | Sales Revenue, Goods, Net | Customer Three | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 10.80% | 15.90% | |
Customer Concentration Risk | Sales Revenue, Goods, Net | Customer Four | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 10.70% | 10.60% | |
Customer Concentration Risk | Accounts Receivable | Customer One | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 18.40% | 19.10% | 20.90% |
Customer Concentration Risk | Accounts Receivable | Customer Two | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 11.90% | 15.00% | 14.00% |
Customer Concentration Risk | Accounts Receivable | Customer Three | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 11.10% | 10.10% | |
Customer Concentration Risk | Accounts Receivable | Customer Four | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 10.40% |
Quarterly Financial Informati_3
Quarterly Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Selected quarterly financial data and earnings per share [Abstract] | |||||||||||
Revenues | $ 442,649 | $ 467,891 | $ 452,417 | $ 387,256 | $ 408,460 | $ 295,311 | $ 315,202 | $ 303,087 | $ 1,750,213 | $ 1,322,060 | $ 1,099,540 |
Operating (losses) earnings | (6,206) | 2,239 | 4,298 | 1,077 | 3,757 | (1,290) | 619 | (1,584) | |||
Net (losses) earnings | $ (3,848) | $ 2,035 | $ 3,620 | $ 1,138 | $ 3,693 | $ (3,033) | $ (282) | $ (860) | $ 2,945 | $ (482) | $ 2,513 |
Earnings (losses) per share: | |||||||||||
Basic net (losses) earnings per share (in dollars per share) | $ (0.91) | $ 0.48 | $ 0.86 | $ 0.27 | $ 0.70 | $ (0.11) | $ 0.60 | ||||
Diluted net (losses) earnings per share (in dollars per share) | $ (0.91) | $ 0.48 | $ 0.86 | $ 0.27 | $ 0.70 | $ (0.11) | $ 0.60 | ||||
Basic and diluted net (losses) earnings per share (in dollars per share) | $ 0.88 | $ (0.72) | $ (0.07) | $ (0.20) | |||||||
Inventory adjustments | $ 7,900 | $ 7,900 |
Oil and Gas Producing Activit_3
Oil and Gas Producing Activities (Unaudited) - Cost incurred in oil and gas exploration and development activities (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Property acquisition costs: | ||
Unproved | $ 4 | $ 32 |
Development costs | 1,815 | 0 |
Total costs incurred | 1,824 | 323 |
Expensed | ||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||
Expensed | $ 5 | $ 291 |
Oil and Gas Producing Activit_4
Oil and Gas Producing Activities (Unaudited) - Proved developed and undeveloped oil and gas reserves (Details) bbl in Thousands, MMcf in Thousands | 12 Months Ended | |
Dec. 31, 2017MMcfbbl | Dec. 31, 2016bblMMcf | |
Natural Gas | ||
Total proved reserves: | ||
Beginning of year | MMcf | 4,214 | 4,835 |
Revisions of previous estimates | MMcf | 0 | 65 |
Crude oil and natural gas reserves sold | MMcf | (4,067) | (175) |
Extensions, discoveries and other reserve additions | MMcf | 42 | 151 |
Production | MMcf | (189) | (662) |
End of year | MMcf | 0 | 4,214 |
Crude Oil | ||
Total proved reserves: | ||
Beginning of year | bbl | 187 | 226 |
Revisions of previous estimates | bbl | 0 | 24 |
Crude oil and natural gas reserves sold | bbl | (170) | (4) |
Extensions, discoveries and other reserve additions | bbl | 6 | 18 |
Production | bbl | (23) | (77) |
End of year | bbl | 0 | 187 |
Oil and Gas Producing Activit_5
Oil and Gas Producing Activities (Unaudited) - Components of proved oil and gas reserves (Details) bbl in Thousands, MMcf in Thousands | Dec. 31, 2017MMcfbbl | Dec. 31, 2016bblMMcf | Dec. 31, 2015MMcfbbl |
Natural Gas | |||
Reserve Quantities [Line Items] | |||
Proved developed reserves | MMcf | 0 | 4,214 | |
Proved undeveloped reserves | MMcf | 0 | 0 | |
Total proved reserves | MMcf | 0 | 4,214 | 4,835 |
Crude Oil | |||
Reserve Quantities [Line Items] | |||
Proved developed reserves | bbl | 0 | 187 | |
Proved undeveloped reserves | bbl | 0 | 0 | |
Total proved reserves | bbl | 0 | 187 | 226 |
Oil and Gas Producing Activit_6
Oil and Gas Producing Activities (Unaudited) - Narrative (Details) | 12 Months Ended |
Dec. 31, 2017 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Period of average estimated price of proved reserves | 12 months |
Oil and Gas Producing Activit_7
Oil and Gas Producing Activities (Unaudited) - Standardized measure of discounted future net cash flows (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||
Future gross revenues | $ 0 | $ 17,938 | |
Future costs: | |||
Lease operating expenses | 0 | (12,421) | |
Development costs | 0 | (38) | |
Future net cash flows before income taxes | 0 | 5,479 | |
Discount at 10% per annum | 0 | (2,002) | |
Discounted future net cash flows before income taxes | 0 | 3,477 | |
Future income taxes, net of discount at 10% per annum | 0 | (1,217) | |
Standardized measure of discounted future net cash flows | $ 0 | $ 2,260 | $ 3,527 |
Oil and Gas Producing Activit_8
Oil and Gas Producing Activities (Unaudited) - Assumed market prices of oil and natural gas reserves and future net revenues (Details) | 12 Months Ended | |
Dec. 31, 2017$ / MMcf$ / bbl | Dec. 31, 2016$ / bbl$ / MMcf | |
Crude Oil | ||
Market price: | ||
Average sales price | $ / bbl | 0 | 38.34 |
Natural gas | ||
Market price: | ||
Average sales price | $ / MMcf | 0 | 2.56 |
Oil and Gas Producing Activit_9
Oil and Gas Producing Activities (Unaudited) - Effect of income taxes and discounting on the standardized measure of discounted future net cash flows (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||
Future net cash flows before income taxes | $ 0 | $ 5,479 | |
Future income taxes | 0 | (1,918) | |
Future net cash flows | 0 | 3,561 | |
Discount at 10% per annum | 0 | (1,301) | |
Standardized measure of discounted future net cash flows | $ 0 | $ 2,260 | $ 3,527 |
Oil and Gas Producing Activi_10
Oil and Gas Producing Activities (Unaudited) - Principal sources of changes in the standardized measure of discounted future net flows (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward] | ||
Beginning of year | $ 2,260 | $ 3,527 |
Sale of crude oil and natural gas reserves | (2,732) | (350) |
Net change in prices and production costs | 0 | (1,391) |
New field discoveries and extensions, net of future production costs | 94 | 275 |
Sales of crude oil and natural gas produced, net of production costs | (476) | 87 |
Net change due to revisions in quantity estimates | 0 | 181 |
Accretion of discount | 130 | 194 |
Production rate changes and other | (493) | (945) |
Net change in income taxes | 1,217 | 682 |
End of year | $ 0 | $ 2,260 |
Oil and Gas Producing Activi_11
Oil and Gas Producing Activities (Unaudited) - Results of operations for oil and gas producing activities (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||
Revenues | $ 1,427 | $ 3,410 | |
Costs and expenses: | |||
Production | (951) | (3,337) | |
Producing property impairments | $ 0 | 0 | (30) |
Depreciation, depletion and amortization | (423) | (1,546) | |
Operating earnings (losses) before income taxes | 53 | (1,503) | |
Income tax benefit (expense) | (19) | 526 | |
Operating earnings (losses) | $ 34 | $ (977) |