Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Mar. 01, 2016 | Jun. 30, 2015 | |
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 Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Accelerated Filer | ||
Entity Public Float | $ 89,541,323 | ||
Entity Common Stock, Shares Outstanding | 4,217,596 | ||
Document Fiscal Year Focus | 2,015 | ||
Document Fiscal Period Focus | FY | ||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2015 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
CURRENT ASSETS: | ||
Cash and cash equivalents | $ 91,877 | $ 80,184 |
Accounts receivable, net of allowance for doubtful accounts of $206 and $179, respectively | 71,813 | 144,434 |
Inventories | 7,671 | 13,481 |
Fair value contracts | 0 | 936 |
Income tax receivable | 2,587 | 970 |
Prepayments | 2,589 | 10,940 |
Total current assets | 176,537 | 250,945 |
PROPERTY AND EQUIPMENT: | ||
Marketing | 65,200 | 65,865 |
Transportation | 70,732 | 63,239 |
Oil and gas (successful efforts method) | 77,117 | 88,661 |
Other | 187 | 186 |
Property and equipment | 213,236 | 217,951 |
Less - Accumulated depreciation, depletion and amortization | (153,521) | (133,080) |
Net property and equipment | 59,715 | 84,871 |
OTHER ASSETS: | ||
Cash deposits and other | 6,963 | 4,998 |
Total Assets | 243,215 | 340,814 |
CURRENT LIABILITIES: | ||
Accounts payable | 74,117 | 160,743 |
Accounts payable - related party | 40 | 51 |
Fair value contracts | 195 | 943 |
Accrued and other liabilities | 5,845 | 6,208 |
Current deferred income taxes | 0 | 658 |
Total current liabilities | 80,197 | 168,603 |
LONG-TERM DEBT | 0 | 0 |
OTHER LIABILITIES: | ||
Asset retirement obligations | 2,469 | 2,464 |
Deferred taxes and other liabilities | 8,039 | 12,250 |
Total liabilities | $ 90,705 | $ 183,317 |
COMMITMENTS AND CONTINGENCIES (NOTE 6) | ||
SHAREHOLDERS' EQUITY: | ||
Preferred stock, $1.00 par value, 960,000 shares authorized, none outstanding | $ 0 | $ 0 |
Common stock, $.10 par value, 7,500,000 shares authorized, 4,217,596 issued and outstanding for all periods presented | 422 | 422 |
Contributed capital | 11,693 | 11,693 |
Retained earnings | 140,395 | 145,382 |
Total shareholders' equity | 152,510 | 157,497 |
Liabilities and shareholders' equity | $ 243,215 | $ 340,814 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
CURRENT ASSETS: | ||
Allowance for doubtful accounts | $ 206 | $ 179 |
SHAREHOLDERS' EQUITY: | ||
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 issued (in shares) | 4,217,596 | 4,217,596 |
Common stock - shares outstanding (in shares) | 4,217,596 | 4,217,596 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
REVENUES: | |||
Marketing | $ 1,875,885 | $ 4,050,497 | $ 3,863,057 |
Transportation | 63,331 | 68,968 | 68,783 |
Oil and natural gas | 5,063 | 13,361 | 14,129 |
Total revenues | 1,944,279 | 4,132,826 | 3,945,969 |
COSTS AND EXPENSES: | |||
Marketing | 1,841,893 | 4,020,017 | 3,815,006 |
Transportation | 52,076 | 56,802 | 56,504 |
Oil and natural gas operations | 19,013 | 15,826 | 8,748 |
Oil and natural gas property sale (gain) | 0 | (2,528) | 0 |
General and administrative | 9,939 | 8,613 | 9,060 |
Depreciation, depletion and amortization | 23,717 | 24,615 | 22,275 |
Total costs and expenses | 1,946,638 | 4,123,345 | 3,911,593 |
Operating (Loss) Earnings | (2,359) | 9,481 | 34,376 |
Other Income (Expense): | |||
Interest income | 327 | 301 | 198 |
Interest expense | (13) | (2) | (24) |
Earnings (loss) from continuing operations before income taxes | (2,045) | 9,780 | 34,550 |
Income Tax (Provision) Benefit: | |||
Current | (4,073) | (9,712) | (9,269) |
Deferred | 4,843 | 6,151 | (3,160) |
Income tax (provision) benefit | 770 | (3,561) | (12,429) |
Earnings (loss) from continuing operations | (1,275) | 6,219 | 22,121 |
Earnings (loss) from discontinued operations net of tax (provision) benefit of zero, $(163) and $275 respectively | 0 | 304 | (511) |
Net Earnings (Loss) | $ (1,275) | $ 6,523 | $ 21,610 |
EARNINGS (LOSS) PER SHARE: | |||
From continuing operations (in dollars per share) | $ (0.30) | $ 1.48 | $ 5.24 |
From discontinued operations (in dollars per share) | 0 | 0.07 | (0.12) |
Basic and diluted net earnings per share (in dollars per share) | (0.30) | 1.55 | 5.12 |
Dividends declared per common share (in dollars per share) | $ 0.88 | $ 0.88 | $ 0.66 |
CONSOLIDATED STATEMENTS OF OPE5
CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
CONSOLIDATED STATEMENTS OF OPERATIONS [Abstract] | |||
Earnings (loss) from discontinued operations, tax | $ 0 | $ (163) | $ 275 |
CONSOLIDATED STATEMENTS OF SHAR
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - USD ($) $ in Thousands | Common Stock [Member] | Contributed Capital [Member] | Retained Earnings [Member] | Total |
BALANCE at Dec. 31, 2012 | $ 422 | $ 11,693 | $ 123,743 | $ 135,858 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Net earnings (loss) | 0 | 0 | 21,610 | 21,610 |
Dividends paid on common stock | 0 | 0 | (2,783) | (2,783) |
BALANCE at Dec. 31, 2013 | 422 | 11,693 | 142,570 | 154,685 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Net earnings (loss) | 0 | 0 | 6,523 | 6,523 |
Dividends paid on common stock | 0 | 0 | (3,711) | (3,711) |
BALANCE at Dec. 31, 2014 | 422 | 11,693 | 145,382 | 157,497 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Net earnings (loss) | 0 | 0 | (1,275) | (1,275) |
Dividends paid on common stock | 0 | 0 | (3,712) | (3,712) |
BALANCE at Dec. 31, 2015 | $ 422 | $ 11,693 | $ 140,395 | $ 152,510 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
CASH PROVIDED BY OPERATIONS: | |||
Net earnings (loss) | $ (1,275) | $ 6,523 | $ 21,610 |
Adjustments to reconcile net earnings to net cash from operating activities - | |||
Depreciation, depletion and amortization | 23,717 | 24,615 | 22,275 |
Property sales (gains) oil and gas | 0 | (2,528) | 0 |
Property sale (gains) other | (535) | (1,028) | (683) |
Dry hole costs incurred | 817 | 1,034 | 233 |
Impairment of oil and natural gas properties | 12,082 | 8,009 | 2,630 |
Provision for doubtful accounts | 27 | (73) | 46 |
Deferred income taxes | (4,843) | (6,151) | 3,161 |
Net change in fair value contracts | 188 | 402 | (389) |
Decrease (increase) in accounts receivable | 72,594 | 99,749 | (4,770) |
Decrease (increase) in inventories | 5,810 | 14,135 | 606 |
Decrease (increase) in income tax receivable | (1,617) | 1,127 | (898) |
Decrease (increase) in prepayments | 8,351 | 5,839 | (8,687) |
Increase (decrease) in accounts payable | (87,404) | (104,887) | 7,809 |
Increase (decrease) in accrued and other liabilities | (166) | 448 | (516) |
Other changes, net | (2,269) | (81) | 1,549 |
Net cash provided by operating activities | 25,477 | 47,133 | 43,976 |
INVESTING ACTIVITIES: | |||
Property and equipment additions | (11,074) | (30,523) | (27,602) |
Insurance and state collateral (deposits) refunds | 283 | (493) | (1,179) |
Proceeds from property sales | 719 | 7,045 | 1,082 |
Net cash (used in) investing activities | (10,072) | (23,971) | (27,699) |
FINANCING ACTIVITIES: | |||
Dividend payments | (3,712) | (3,711) | (2,783) |
Net cash (used in) financing activities | (3,712) | (3,711) | (2,783) |
Increase (decrease) in cash and cash equivalents | 11,693 | 19,451 | 13,494 |
Cash and cash equivalents at beginning of year | 80,184 | 60,733 | 47,239 |
Cash and cash equivalents at end of year | $ 91,877 | $ 80,184 | $ 60,733 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
Summary of Significant Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | (1) Summary of Significant Accounting Policies Principles of Consolidation The accompanying consolidated financial statements include the accounts of Adams Resources & Energy, Inc., a Delaware corporation (‟ARE”) together with its wholly owned subsidiaries (the ‟Company”) after elimination of all intercompany accounts and transactions. The impact on the accompanying financial statements of events occurring after December 31, 2015 was evaluated through the date of issuance of these financial statements. Nature of Operations The Company is engaged in the business of crude oil marketing, tank truck transportation of liquid chemicals, and oil and gas exploration and production. Its primary area of operation is within the Gulf Coast region of the United States. Cash and Cash Equivalents Cash and cash equivalents include any Treasury bill, commercial paper, money market fund or federal funds with maturity of 90 days or less. Depending on cash availability and market conditions, investments in corporate and municipal bonds, which are classified as investments in marketable securities, may also be made from time to time. Cash and cash equivalents are maintained with major financial institutions and such deposits may exceed the amount of federally backed insurance provided. While the Company regularly monitors the financial stability of such institutions, cash and cash equivalents ultimately remain at risk subject to the financial viability of such institutions. Allowance for Doubtful Accounts Accounts receivable are the product of sales of crude oil and natural gas and the sale of trucking services. Marketing segment wholesale level sales of crude oil comprise in excess of 90 percent of total accounts receivable and under industry practices, such items are ‟settled” and paid in cash within 20 days of the month following the transaction date. For such receivables, an allowance for doubtful accounts is determined based on specific account identification. The balance of accounts receivable results primarily from the sale of trucking services. For this component of receivables, the allowance for doubtful accounts is determined based on a review of specific accounts combined with a review of the general status of the aging of all accounts. Inventory Inventory consists of crude oil held in storage tanks and at third-party pipelines as part of the Company’s crude oil marketing operations. Crude oil inventory is carried at the lower of average cost or market. Due to declining crude oil prices, inventory valuation losses were as follows (in thousands): 2015 2014 Inventory valuation loss $ 5,357 $ 14,247 Prepayments The components of prepayments and other are as follows (in thousands): December 31, 2015 2014 Cash collateral deposits for commodity purchases $ 167 $ 7,872 Insurance premiums 1,609 2,316 Rents, license and other 813 752 $ 2,589 $ 10,940 Property and Equipment Expenditures for major renewals and betterments are capitalized, and expenditures for maintenance and repairs are expensed as incurred. Interest costs incurred in connection with major capital expenditures are capitalized and amortized over the lives of the related assets. When properties are retired or sold, the related cost and accumulated depreciation, depletion and amortization is removed from the accounts and any gain or loss is reflected in earnings. Oil and gas exploration and development expenditures are accounted for in accordance with the successful efforts method of accounting. Direct costs of acquiring developed or undeveloped leasehold acreage, including lease bonus, brokerage and other fees, are capitalized. Exploratory drilling costs are initially capitalized until the properties are evaluated and determined to be either productive or nonproductive. Such evaluations are made on a quarterly basis. If an exploratory well is determined to be nonproductive, the costs of drilling the well are charged to expense. Costs incurred to drill and complete development wells, including dry holes, are capitalized. As of December 31, 2015 and 2014, the Company had no unevaluated or ‟suspended” exploratory drilling costs. Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base or denominator used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. For lease and well equipment, development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. The numerator for such calculation is actual production volumes for the period. All other property and equipment is depreciated using the straight-line method over the estimated average useful lives of three to twenty years. The Company reviews its long-lived assets for impairment whenever there is evidence that the carrying value of such assets may not be recoverable. Any impairment recognized is permanent and may not be restored. Producing oil and gas properties are reviewed on a field-by-field basis. For properties requiring impairment, the fair value is estimated based on an internal discounted cash flow model. Cash flows are developed based on estimated future production and prices and then discounted using a market based rate of return consistent with that used by the Company in evaluating cash flows for other assets of a similar nature. On a quarterly basis, management evaluates the carrying value of non-producing oil and gas leasehold properties and may deem them impaired based on remaining lease term, area drilling activity and the Company’s plans for the property. This fair value measure depends highly on management’s assessment of the likelihood of continued exploration efforts in a given area. Therefore, such data inputs are categorized as ‟unobservable or Level 3” inputs. (See ‟Fair Value Measurements” below). Importantly, this fair value measure only applies to the write-down of capitalized costs and will never result in an increase to reported earnings. Impairment provisions including in oil and gas segment operating losses were as follows (in thousands): 2015 2014 2013 Producing property impairments $ 10,324 $ 4,001 $ 1,373 Non-producing property impairments $ 1,758 $ 4,008 $ 1,257 Fair value measurements for producing oil and gas properties that were subject to fair value impairment for the years ended December 31, 2015 and 2014 summarize as follows (in thousands): Producing Properties Subject to Fair Value Impairment 2015 2014 Net book value at January 1 $ 18,744 $ 10,180 Property additions 2,117 469 Depletion taken (4,454 ) (1,792 ) Impairment valuation loss (10,324 ) (4,001 ) Net book value at December 31 $ 6,083 $ 4,856 Capitalized costs for non-producing oil and gas leasehold interests currently represent approximately three percent of remaining unamortized oil and gas property carrying costs and categorize as follows (in thousands): December 31, December 31, 2015 2014 Napoleonville Louisiana acreage $ 49 $ 48 South Texas project acreage - 357 Wyoming and other acreage 182 554 Total Non-producing Leasehold Costs $ 231 $ 959 Since the Company is generally not the operator of its oil and gas property interests, it does not maintain underlying detail acreage data and is dependent on the operator when determining which specific acreage will ultimately be drilled. However, the capitalized cost detail on a property-by-property basis is reviewed by management and deemed impaired if development is not anticipated prior to lease expiration. Onshore leasehold periods are normally three years and may contain renewal options. Capitalized cost activity and fair value measurements on non-producing leasehold were as follows (in thousands): Leasehold Costs 2015 2014 Net book value January 1 $ 959 $ 4,906 Leasehold additions 106 865 Advanced royalty payment 529 - In-process wells suspended 395 73 Property sales - (877 ) Impairments valuation loss (1,758 ) (4,008 ) Net book value December 31 $ 231 $ 959 During 2014, the Company sold substantially all of its producing property interests in Oklahoma. Proceeds totaled $1,731,000 and the Company recorded a $1,149,000 pre-tax gain from this sale. Also during 2014 the Company sold one-half of its interest in sections of a South Texas project interest. Proceeds totaled $1,509,000 and the Company recorded a $632,000 pre-tax gain from this sale. Certain other oil and gas property interests were also sold in 2014 for proceeds totaling $822,000 and gains totaling $747,000. The Company sold certain used trucks and equipment from its marketing and transportation segments and recorded net pre-tax gains as follows (in thousands): 2015 2014 2013 Sales of used trucks and equipment $ 535 $ 1,028 $ 683 Cash Deposits and Other Assets The Company has established certain deposits to support participation in its liability insurance program and remittance of state crude oil severance taxes and other state collateral deposits. Insurance collateral deposits are invested at the discretion of the Company’s insurance carrier and such investments primarily consist of intermediate term federal government bonds and bonds backed by federal agencies. This fair value measure relies on inputs from quoted prices for similar assets and is thus categorized as a ‟Level 2” valuation in the fair value hierarchy. Components of cash deposits and other assets are as follows (in thousands): As of December 31, 2015 2014 Insurance collateral deposits $ 6,531 $ 4,536 State collateral deposits 140 155 Materials and supplies 292 307 $ 6,963 $ 4,998 Revenue Recognition Certain commodity purchase and sale contracts utilized by the Company’s marketing business generally qualify as derivative instruments with certain specifically identified crude oil contracts designated as trading activities. From the time of contract origination, such trading activity contracts are marked-to-market and recorded on a net revenue basis in the accompanying consolidated financial statements. Most all crude oil purchase and sale contracts qualify and are designated as non-trading activities and the Company considers such contracts as normal purchases and sales activity. For normal purchases and sales the Company’s customers are invoiced monthly based upon contractually agreed upon terms with revenue recognized in the month in which the physical product is delivered to the customer. Such sales are recorded gross in the financial statements because the Company takes title, has risk of loss for the products, is the primary obligor for the purchase, establishes the sale price independently with a third party, and maintains credit risk associated with the sale of the product. Certain crude oil contracts may be with a single counterparty to provide for similar quantities of crude oil to be bought and sold at different locations. These contracts are entered into for a variety of reasons, including effecting the transportation of the commodity, to minimize credit exposure, and/or to meet the competitive demands of the customer. Such buy/sell arrangements are reflected on a net revenue basis in the accompanying consolidated financial statements. Reporting such crude oil contracts on a gross revenue basis would increase the Company’s reported revenues as follows (in thousands): 2015 2014 2013 Revenue gross-up $ 480,111 $ 1,272,034 $ 1,602,626 Transportation segment customers are invoiced, and the related revenue is recognized as the service is provided. Oil and gas revenue from the Company’s interests in producing wells is recognized as title and physical possession of the oil and gas passes to the purchaser. Sales of long-lived assets Gains and losses from the sale or disposal of long-lived assets that do not meet the criteria for presentation as a discontinued operation are presented in the accompanying financial statements as a component of operating earnings. Letter of Credit Facility The Company maintains a Credit and Security Agreement with Wells Fargo Bank to provide a $60 million stand-by letter of credit facility used to support crude oil purchases within the marketing segment. This facility is collateralized by the eligible accounts receivable within the segment and certain marketing and transportation equipment. Stand-by letters of credit issued were as follows (in thousands): As of December 31, 2015 2014 Stand-by letters of credit $ 1,000 $ 15,300 The issued stand-by letters of credit are cancelled as the underlying purchase obligations are satisfied by cash payment when due. The letter of credit facility places certain restrictions on the Company’s Gulfmark Energy, Inc. subsidiary. Such restrictions included the maintenance of a combined 1.1 to 1.0 current ratio and the maintenance of positive net earnings excluding inventory valuation changes, as defined, among other restrictions. The Company is currently in compliance with all such financial covenants. Statement of Cash Flows There were no significant non-cash financing activities in any of the periods reported. Statement of cash flow items include the following (in thousands): 2015 2014 2013 Interest paid $ 13 $ 2 $ 24 Federal and state tax paid $ 6,197 $ 8,169 $ 9,949 State tax refund $ - $ 18 $ 4 Capitalized amounts included in property and equipment that were not included in amounts reported for cash additions in the Statements of Cash Flows for the applicable report dates were as follows (in thousands): As of December 31, 2015 2014 2013 Property and equipment additions $ 1,707 $ 1,137 $ 1,507 Earnings per Share Earnings per share are based on the weighted average number of shares of common stock and potentially dilutive common stock shares outstanding during the period. The weighted average number of shares outstanding was 4,217,596 for 2015, 2014 and 2013. There were no potentially dilutive securities outstanding during those periods. Share-Based Payments During the periods presented herein, the Company had no stock-based employee compensation plans, nor any other share-based payment arrangements. Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Examples of significant estimates used in the accompanying consolidated financial statements include the oil and gas reserve volumes forming the foundation for calculating depreciation, depletion and amortization and for estimating cash flows when assessing impairment triggers and when estimating values associated with oil and gas properties. Other examples include revenue accruals, the provision for bad debts, insurance related accruals, income tax permanent and timing differences, contingencies, and valuation of fair value contracts. Income Taxes Income taxes are accounted for using the asset and liability method. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of such items and their respective tax basis (See also Note (2) to consolidated financial statements). Use of Derivative Instruments The Company’s marketing segment is involved in the purchase and sale of crude oil. The Company seeks to make a profit by procuring this commodity as it is produced and then delivering the material to end users or the intermediate use marketplace. As is typical for the industry, such transactions are made pursuant to the terms of forward month commodity purchase and/or sale contracts. Some of these contracts meet the definition of a derivative instrument and therefore, the Company accounts for such contracts at fair value, unless the normal purchase and sale exception is applicable. Such underlying contracts are standard for the industry and are the governing document for the Company’s crude oil wholesale distribution businesses. None of the Company’s derivative instruments have been designated as hedging instruments. The accounting methodology utilized by the Company for its commodity contracts is further discussed below under the caption ‟Fair Value Measurements”. The estimated fair value of forward month commodity contracts (derivatives) is reflected in the accompanying Consolidated Balance Sheet as of December 31, 2015 as follows (in thousands): Balance Sheet Location and Amount Current Other Current Other Assets Assets Liabilities Liabilities Asset Derivatives - Fair Value Commodity Contracts at Gross Valuation $ - $ - $ - $ - Liability Derivatives - Fair Value Commodity Contracts at Gross Valuation - - 195 - Less Counterparty Offsets - - - - As Reported Fair Value Contracts $ - $ - $ 195 $ - As of December 31, 2015, one contract comprised the Company’s derivative valuations. The purchase and sale contract encompass approximately 65 barrels of diesel fuel per day in each of January, February and March 2016. The estimated fair value of forward month commodity contracts (derivatives) is reflected in the accompanying Consolidated Balance Sheet as of December 31, 2014 as follows (in thousands): Balance Sheet Location and Amount Current Other Current Other Assets Assets Liabilities Liabilities Asset Derivatives - Fair Value Commodity Contracts at Gross Valuation $ 1,332 $ - $ - $ - Liability Derivatives - Fair Value Commodity Contracts at Gross Valuation - - 1,339 - Less Counterparty Offsets (396 ) - (396 ) - As Reported Fair Value Contracts $ 936 $ - $ 943 $ - As of December 31, 2014, three commodity purchase and sale contracts comprised the Company’s derivative valuations. These contracts encompass approximately 294 barrels per day of crude oil for January and February 2015 plus 129 barrels per day of crude oil from March 2015 through December 2015. The Company only enters into commodity contracts with creditworthy counterparties or obtains collateral support for such activities. As of December 31, 2015 and 2014, the Company was not holding nor had it posted any collateral to support its forward month fair value derivative activity. The Company is not subject to any credit-risk related trigger events. The Company has no other financial investment arrangements that would serve to offset its derivative contracts. Forward month commodity contracts (derivatives) are reflected in the accompanying Consolidated Statement of Operations for the years ended December 31, 2015, 2014 and 2013 as follows (in thousands): Gain (Loss) Location 2015 2014 2013 Revenues – marketing $ (188 ) $ 312 $ (193 ) Fair Value Measurements The carrying amount reported in the Consolidated Balance Sheet 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. Fair value contracts consist of derivative financial instruments and are recorded as either an asset or liability measured at fair value. Changes in fair value are recognized immediately in earnings unless the derivatives qualify for, and the Company elects, cash flow hedge accounting. The Company had no contracts designated for hedge accounting during any reporting periods. Fair value estimates are based on assumptions that market participants would use when pricing an asset or liability and the Company uses a fair value hierarchy of three levels that prioritizes the information used to develop those assumptions. Currently, for all items presented herein, the Company utilizes a market approach to valuing its contracts. On a contract by contract, forward month by forward month basis, the Company obtains observable market data for valuing its contracts. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data. The fair value hierarchy is summarized as follows: Level 1 – quoted prices in active markets for identical assets or liabilities that may be accessed at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. For Level 1 valuation of marketable securities, the Company utilizes market quotations provided by its primary financial institution and for the valuations of derivative financial instruments, the Company utilizes the New York Mercantile Exchange ‟NYMEX” for such valuations. Level 2 – (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 – Unobservable market data inputs for assets or liabilities. As of December 31, 2015, the Company’s fair value assets and liabilities are summarized and categorized as follows (in thousands): Market Data Inputs Gross Level 1 Gross Level 2 Gross Level 3 Counterparty Quoted Prices Observable Unobservable Offsets Total Derivatives - Current assets $ - $ - $ - $ - $ - - Current liabilities - (195 ) - - (195 ) Net Value $ - $ (195 ) $ - $ - $ (195 ) As of December 31, 2014, the Company’s fair value assets and liabilities are summarized and categorized as follows (in thousands): Market Data Inputs Gross Level 1 Gross Level 2 Gross Level 3 Counterparty Quoted Prices Observable Unobservable Offsets Total Derivatives - Current assets $ - $ 1,332 $ - $ (396 ) $ 936 - Current liabilities - (1,339 ) - 396 (943 ) Net Value $ - $ (7 ) $ - $ - $ (7 ) When determining fair value measurements, the Company makes credit valuation adjustments to reflect both its own nonperformance risk and its counterparty’s nonperformance risk. When adjusting the fair value of derivative contracts for the effect of nonperformance risk, the impact of netting and applicable credit enhancements, such as collateral postings, thresholds, and guarantees are considered. Credit valuation adjustments utilize Level 3 inputs, such as credit scores to evaluate the likelihood of default by the Company or its counterparties. As of December 31, 2015 and 2014, credit valuation adjustments were not significant to the overall valuation of the Company’s fair value contracts. As a result, fair value assets and liabilities are included in their entirety in the fair value hierarchy. The following table illustrates the factors impacting the change in the net value of the Company’s fair value contracts for the year ended December 31, 2015 (in thousands): Level 1 Level 2 Quoted Prices Observable Total Net Fair Value January 1 $ - $ (7 ) $ (7 ) - Net realized (gains) losses - 7 7 - Net unrealized gains (losses) - (195 ) (195 ) Net Fair Value December 31 $ - $ (195 ) $ (195 ) The following table illustrates the factors impacting the change in the net value of the Company’s fair value contracts for the year ended December 31, 2014 (in thousands): Level 1 Level 2 Quoted Prices Observable Total Net Fair Value January 1 $ - $ 395 $ 395 - Net realized (gains) losses - 220 220 - Option deposit - (714 ) (714 ) - Option gain - 99 99 - Net unrealized gains (losses) - (7 ) (7 ) Net Fair Value December 31 $ - $ (7 ) $ (7 ) Asset Retirement Obligations The Company records a liability for the estimated retirement costs associated with certain tangible long-lived assets. The estimated fair value of asset retirement obligations are recorded in the period in which they are incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the asset or the units of production associated with the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. A summary of the Company’s asset retirement obligations is presented as follows (in thousands): 2015 2014 Balance on January 1 $ 2,464 $ 2,564 -Liabilities incurred 39 111 -Accretion of discount 93 94 -Liabilities settled (127 ) (305 ) Balance on December 31 $ 2,469 $ 2,464 In addition to an accrual for asset retirement obligations, the Company maintains $75,000 in escrow cash, which is legally restricted for the potential purpose of settling asset retirement costs in accordance with certain state regulations. Such cash deposits are included in other assets in the accompanying consolidated balance sheet. Recent Accounts Pronouncement In May 2014, the FASB amended the existing accounting standards for revenue recognition. The amendments are based on the principle that revenue should be recognized to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new guidance is effective for the annual period ending after December 15, 2017. Early adoption is not permitted. The amendments may be applied retrospectively to each prior period presented or retrospectively with the cumulative effect recognized as of the date of initial application. Management is currently evaluating the impact of these amendments on the Company’s consolidated financial statements and the transition alternatives. In August 2014, the FASB issued guidance requiring management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. The standard also provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new guidance is effective for the annual period ending after December 15, 2016, and interim periods thereafter, with early adoption permitted. Management does not expect the adoption of this guidance to have an impact on the Consolidated Financial Statements. In July 2015, the FASB amended the existing accounting standards for inventory to provide for the measurement of inventory at the lower of cost of ‟ In November 2015, the FASB issued guidance to simplify the presentation of deferred taxes in the statement of financial position. The amendment requires that deferred tax assets and liabilities be classified as non-current in the balance sheet. The Company adjusted this guidance on a prospective basis effective January 1, 2015. Management believes the impact of other recently issued standards and updates, which are not yet effective, will not have a material impact on the Company’s consolidated financial position, results of operations or cash flows upon adoption. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2015 | |
Income Taxes [Abstract] | |
Income Taxes | (2) Income Taxes The following table shows the components of the Company’s income tax (provision) benefit (in thousands): Years ended December 31, 2015 2014 2013 Current: Federal $ (3,883 ) $ (8,626 ) $ (8,102 ) State (190 ) (1,249 ) (892 ) (4,073 ) (9,875 ) (8,994 ) Deferred: Federal 5,011 5,878 (2,682 ) State (168 ) 273 (478 ) 4,843 6,151 (3,160 ) $ 770 $ (3,724 ) $ (12,154 ) The following table summarizes the components of the income tax (provision) benefit (in thousands): Years ended December 31, 2015 2014 2013 From continuing operations $ 770 $ (3,561 ) $ (12,429 ) From discontinued operations - (163 ) 275 $ 770 $ (3,724 ) $ (12,154 ) Taxes computed at the corporate federal income tax rate reconcile to the reported income tax (provision) as follows (in thousands): Years ended December 31, 2015 2014 2013 Statutory federal income tax (provision) benefit $ 716 $ (3,587 ) $ (11,819 ) State income tax (provision) benefit (233 ) (634 ) (891 ) Federal statutory depletion 144 549 522 Other 143 (52 ) 34 $ 770 $ (3,724 ) $ (12,154 ) Deferred income taxes reflect the net difference between the financial statement carrying amounts and the underlying income tax basis in such items. Effective January 1, 2015 the Company adopted on a prospective basis an FASB guidance requiring that deferred tax assets and liabilities be classified as non-current in the balance sheet. The components of the federal deferred tax asset (liability) are as follows (in thousands): Years Ended December 31, 2015 2014 Current deferred tax asset (liability) Allowance for doubtful accounts $ - $ 62 Prepaid and other insurance - (719 ) Fair value contracts - (1 ) Net current deferred liability - (658 ) Long-term deferred tax asset (liability) Prepaid and other insurance (1,243 ) - Property (7,408 ) (12,673 ) Uniform capitalization 704 661 Other (51 ) (170 ) Net long-term deferred tax liability (7,998 ) (12,182 ) Net deferred tax liability $ (7,998 ) $ (12,840 ) Financial statement recognition and measurement of positions taken, or expected to be taken, by an entity in its income tax returns must consider the uncertainty and judgment involved in the determination and filing of income taxes. Tax positions taken in an income tax return that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the tax position will be examined by taxing authorities with full knowledge of all relevant information. The Company has 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 2012 Texas 2011 Louisiana 2012 Michigan 2011 |
Concentration of Credit Risk
Concentration of Credit Risk | 12 Months Ended |
Dec. 31, 2015 | |
Concentration of Credit Risk [Abstract] | |
Concentration of Credit Risk | (3) Concentration of Credit Risk Credit risk encompasses the amount of loss absorbed should the Company’s customers fail to perform pursuant to contractual terms. Managing credit risk 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. The Company has established various procedures to manage credit exposure, including initial credit approval, credit limits, and rights of offset. Letters of credit and guarantees are also utilized to limit exposure. Accounts receivable associated with crude oil marketing activities comprise approximately 90 percent of the Company’s total receivables and industry practice requires payment for such sales to occur within 20 days of the end of the month following a transaction. The Company’s customer makeup, credit policies and the relatively short duration of receivables mitigate the uncertainty typically associated with receivables management. An allowance for doubtful accounts is provided where appropriate. An analysis of the changes in the allowance for doubtful accounts is presented as follows (in thousands): 2015 2014 2013 Balance, beginning of year $ 179 $ 252 $ 206 Provisions for bad debts 116 50 147 Less: Write-offs and recoveries (89 ) (123 ) (101 ) Balance, end of year $ 206 $ 179 $ 252 The Company’s largest customers consist of large multinational integrated oil companies and independent domestic refiners of crude oil. In addition, the Company transacts business with independent oil producers, major chemical concerns, crude oil trading companies and a variety of commercial energy users. Within this group of customers, the Company generally derives approximately 50 percent of its revenues from three to five large crude oil refining concerns. While the Company has ongoing established relationships with certain domestic refiners of crude oil, alternative markets are readily available since the Company supplies less than one percent of U.S. domestic refiner demand. As a fungible commodity delivered to major Gulf Coast supply points, the Company’s crude oil sales can be readily delivered to alternative end markets. Management believes that a loss of any of those customers where the Company currently derives more than 10 percent of its revenues would not have a material adverse effect on the Company’s operations as shown below: Individual customer sales Individual customer receivables in excess in excess of 10% of revenues of 10% of total receivables as of December 31, 2015 2014 2013 2015 2014 2013 24.4 % 20.3 % 18.5 % 20.3 % 16.6 % 16.0 % 13.8 % 14.0 % 17.7 % 16.5 % 16.6 % 15.8 % - - 15.8 % 12.7 % 10.4 % 12.7 % - - 10.4 % - - - |
Employee Benefits
Employee Benefits | 12 Months Ended |
Dec. 31, 2015 | |
Employee Benefits [Abstract] | |
Employee Benefits | (4) Employee Benefits The Company maintains a 401(k) savings plan for the benefit of its employees. No other pension or retirement plans are maintained by the Company. The Company’s 401K plan contributory expenses were as follows (in thousands): 2015 2014 2013 Contributory expenses $ 768 $ 691 $ 674 |
Transactions with Affiliates
Transactions with Affiliates | 12 Months Ended |
Dec. 31, 2015 | |
Transactions with Affiliates [Abstract] | |
Transactions with Affiliates | (5) Transactions with Affiliates The late Mr. K. S. Adams, Jr., former Chairman of the Board and certain of his family partnerships and affiliates have participated as working interest owners with Adams Resources Exploration Corporation (‟AREC”). Mr. Adams and the affiliates participated on terms similar to those afforded other non-affiliated working interest owners. While the affiliates have generally maintained their existing property interest, they have not participated in any such transactions originating after the death of Mr. Adams in October 2013. In connection with the operation of certain of these oil and gas properties, the Company charges such related parties for administrative overhead as prescribed by the Council of Petroleum Accountants Society Bulletin 5. The Company also enters into certain transactions in the normal course of business with other affiliated entities including direct cost reimbursement for shared phone and administrative services. In addition the Company leases its corporate office space from an affiliated entity based on a lease rental rate determined by an independent appraisal. Activities with affiliates were as follows (in thousands): 2015 2014 2013 Overhead recoveries $ 97 $ 151 $ 152 Affiliate billings to Company $ 68 $ 65 $ 69 Company billings to affiliate $ 35 $ 42 $ 99 Rentals paid to affiliate $ 618 $ 607 $ 481 Additionally, in 2014, the Company engaged a professional services firm controlled by Townes Pressler, a member of the Company’s Board of Directors, to conduct a crude oil supply availability study. Total study costs, all of which occurred in 2014 were $70,420. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies [Abstract] | |
Commitments and Contingencies | (6) Commitments and Contingencies The Company maintains certain operating lease arrangements with independent truck owner-operators for use of their equipment and driver services on a month-to-month basis. In addition, the Company enters into office space and certain lease and terminal access contracts in order to provide tank storage and dock access for its crude oil marketing business. All lease commitments qualify for off-balance sheet treatment. Such contracts require certain minimum monthly payments for the term of the contracts. The Company has no capital lease arrangements. Rental expense is as follows (in thousands): Years ended December 31, 2015 2014 2013 Rental expense $ 11,168 $ 9,755 $ 8,281 At December 31, 2015, rental obligations under long-term non-cancelable operating leases and terminal arrangements for the next five years and thereafter are payable as follows ( in thousands): 2016 2017 2018 2019 2020 Thereafter Total $ 6,218 $ 4,160 $ 1,697 $ 318 $ - $ - $ 12,393 Under the Company’s automobile and workers’ compensation insurance policies, the Company can 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 is shared with a group of similarly situated entities. The Company has appropriately recognized estimated expenses and liabilities related to these policies for losses incurred but not reported to the Company or its insurance carrier as follows (in thousands): As of December 31, 2015 2014 2013 Estimated expenses and liabilities $ 2,086 $ 2,585 $ 1,796 The Company maintains a self-insurance program for managing employee medical claims. A liability for expected claims incurred is established on a monthly basis. As claims are paid, the liability is relieved. The Company also maintains third party insurance stop-loss coverage for annual individual medical claims exceeding $100,000. In addition, the Company maintains $2 million of umbrella insurance coverage for aggregate medical claims exceeding approximately $4.5 million for the calendar years 2015 and 2014. Medical accrual amounts are as follows (in thousands): As of December 31, 2015 2014 2013 Accrued medical claims $ 1,107 $ 1,057 $ 1,129 AREC is named as a defendant in a number of Louisiana based suits involving alleged environmental contamination from prior drilling operations. Such suits typically allege improper disposal of oilfield wastes in earthen pits with one suit alleging subsidence contributing of the formation of a sink hole. AREC is currently involved in three such suits. The suits are styled LePetit Chateau Deluxe v. Adams Resources Exploration Corporation dated March 2004, Gustave J. LaBarre, Jr., et. al. v. Adams Resources Exploration Corporation et al dated October 2012 and Henning Management, LLC v. Adams Resources Exploration Corporation dated November 2013. Each suit involves multiple industry defendants with substantially larger proportional interest in the properties except all the larger defendants have settled their claims in the LePetit Chateau Deluxe matter. The plaintiffs in each of these matters are seeking unspecified compensatory and punitive damages. While management does not believe that a material adverse effect will result from the claims, significant attorney fees will be incurred to defend these items. As of December 31, 2015 and 2014 the Company has accrued $500,000 of future legal and/or settlement costs for these matters. From time to time as incidental to its operations, the Company may become involved in various lawsuits and/or disputes. Primarily as an operator of an extensive trucking fleet, the Company is a party to motor vehicle accidents, worker compensation claims and other items of general liability as would be typical for the industry. Management of the Company is presently unaware of any claims against the Company that are either outside the scope of insurance coverage, or that may exceed the level of insurance coverage and, therefore could potentially represent a material adverse effect on the Company’s financial position or results of operations. |
Guarantees
Guarantees | 12 Months Ended |
Dec. 31, 2015 | |
Guarantees [Abstract] | |
Guarantees | (7) Guarantees ARE issues parent guarantees of commitments associated with the activities of its subsidiary companies. The guarantees generally result from subsidiary commodity purchase obligations, subsidiary operating lease commitments and subsidiary banking transactions. The nature of such items is to guarantee the performance of the subsidiary companies in meeting their respective underlying obligations. Except for operating lease commitments and letters of credit, all such underlying obligations are recorded on the books of the subsidiary companies and are included in the Consolidated Financial Statements included herein. Therefore, no such obligation is recorded again on the books of the parent. The parent would only be called upon to perform under the guarantee in the event of a payment default by the applicable subsidiary company. In satisfying such obligations, the parent would first look to the assets of the defaulting subsidiary company. As of December 31, 2015, parental guaranteed obligations are approximately as follows (in thousands): 2016 2017 2018 2019 Thereafter Total Commodity purchases $ 15,855 - - - - $ 15,855 Letters of credit 1,000 - - - - 1,000 $ 16,855 $ - $ - $ - $ - $ 16,855 Presently, neither ARE nor any of its subsidiaries has any other types of guarantees outstanding that require liability recognition. |
Segment Reporting
Segment Reporting | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
Segment Reporting | (8) Segment Reporting The Company is engaged in the business of crude oil marketing as well as tank truck transportation of liquid chemicals, and oil and gas exploration and production. Information concerning the Company’s various business activities is summarized as follows (in thousands): Segment Operating Depreciation Depletion and Property and Equipment Revenues Earnings (loss) Amortization Additions Year ended December 31, 2015- Marketing $ 1,875,885 $ 22,895 (1) $ 11,097 $ 2,126 Transportation 63,331 3,701 7,554 6,579 Oil and gas 5,063 (19,016 ) (2) 5,066 2,369 $ 1,944,279 $ 7,580 $ 23,717 $ 11,074 Year ended December 31, 2014- Marketing $ 4,050,497 $ 20,854 (1) $ 9,626 $ 13,598 Transportation 68,968 4,750 7,416 8,994 Oil and gas 13,361 (7,510 ) (2) 7,573 7,931 $ 4,132,826 $ 18,094 $ 24,615 $ 30,523 Year ended December 31, 2013- Marketing $ 3,863,057 $ 40,369 (1) $ 7,682 $ 11,343 Transportation 68,783 5,180 7,099 3,165 Oil and gas 14,129 (2,113 ) (2) 7,494 13,094 $ 3,945,969 $ 43,436 $ 22,275 $ 27,602 __________________________________ (1) (2) Segment operating earnings reflect revenues net of operating costs and depreciation, depletion and amortization and are reconciled to earnings from continuing operations before income taxes, as follows (in thousands): Years Ended December 31, 2015 2014 2013 Segment operating earnings $ 7,580 $ 18,094 $ 43,436 - General and administrative expenses (9,939 ) (8,613 ) (9,060 ) Operating earnings (loss) (2,359 ) 9,481 34,376 - Interest income 327 301 198 - Interest expense (13 ) (2 ) (24 ) Earnings (loss) from continuing operations before income taxes and discontinued operations $ (2,045 ) $ 9,780 $ 34,550 Identifiable assets by industry segment are as follows (in thousands): Years Ended December 31, 2015 2014 2013 Marketing $ 96,723 $ 189,332 $ 306,693 Transportation 35,010 37,643 34,406 Oil and gas 8,930 25,888 37,093 Cash and other 102,552 87,951 69,890 $ 243,215 $ 340,814 $ 448,082 Intersegment sales are insignificant and all sales occurred in the United States. Other identifiable assets are primarily corporate cash, corporate accounts receivable, and properties not identified with any specific segment of the Company’s business. Accounting policies for transactions between reportable segments are consistent with applicable accounting policies as disclosed herein. |
Discontinued Operations
Discontinued Operations | 12 Months Ended |
Dec. 31, 2015 | |
Discontinued Operations [Abstract] | |
Discontinued Operations | (9) Discontinued Operations In 2014, the Company sold for $664,000 in cash the warehouse and real estate used by its former petroleum refined products marketing operation to yield a pre-tax gain of $553,000 with such gain reported in discontinued operations for 2014. In 2013 the Company completed an orderly wind-down and closure of its natural gas marketing segment. Revenues from this segment included in net earnings from discontinued operations totaled $2,377,000 for the year ended December 31, 2013. All obligations from these ventures were satisfied and no further events are anticipated. |
Subsequent Event
Subsequent Event | 12 Months Ended |
Dec. 31, 2015 | |
Subsequent Event [Abstract] | |
Subsequent Event | (10) Subsequent Event On January 14, 2016 the Company’s wholly owned subsidiary Adams Resources Medical Management acquired a 30% member interest in Bencap LLC (Bencap) for a $2,200,000 cash payment. Bencap provides medical insurance brokerage and medical claims auditing services to employers utilizing ERISA governed employee benefit plans. The Company will account for this investment on the equity method of accounting. |
Quarterly Financial Data (Unaud
Quarterly Financial Data (Unaudited) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Data (Unaudited) [Abstract] | |
Quarterly Financial Data (Unaudited) | (11) Quarterly Financial Data (Unaudited) Selected quarterly financial data and earnings per share of the Company are presented below for the years ended December 31, 2015 and 2014 (in thousands, except per share data): Earnings (Loss) from Continuing Operations Net Earnings (Loss) Dividends Revenues Amount Per Share Amount Per Share Amount Per Share 2015 - March 31 $ 555,573 $ 3,097 $ .73 $ 3,097 $ .73 $ 928 $ .22 June 30 600,558 4,340 1.03 4,340 1.03 928 .22 September 30 439,893 (308 ) (.07 ) (308 ) (.07 ) 928 .22 December 31 348,255 (8,404 ) (1.99 ) (8,404 ) (1.99 ) 928 .22 Total $ 1,944,279 $ (1,275 ) $ (.30 ) $ (1,275 ) $ (.30 ) $ 3,712 $ .88 2014 - March 31 $ 949,189 $ 5,363 $ 1.27 $ 5,363 $ 1.27 $ 928 $ .22 June 30 1,159,931 3,975 .94 3,975 .94 928 .22 September 30 1,173,970 3,855 .92 3,855 .92 928 .22 December 31 849,736 (6,974 ) (1.65 ) (6,670 ) (1.58 ) 927 .22 Total $ 4,132,826 $ 6,219 $ 1.48 $ 6,523 $ 1.55 $ 3,711 $ .88 The above unaudited interim financial data reflect all adjustments that are in the opinion of management necessary to a fair statement of the results for the period presented. All such adjustments are of a normal recurring nature. |
Oil and Gas Producing Activitie
Oil and Gas Producing Activities (Unaudited) | 12 Months Ended |
Dec. 31, 2015 | |
Oil and Gas Producing Activities (Unaudited) [Abstract] | |
Oil and Gas Producing Activities (Unaudited) | (12) Oil and Gas Producing Activities (Unaudited) The Company’s oil and gas exploration and production activities are conducted in Texas and the south central region of the United States, primarily along the Gulf Coast of Texas and Louisiana. Oil and Gas Producing Activities - Total costs incurred in oil and gas exploration and development activities, all within the United States, were as follows (in thousands): For the year Ended December 31, 2015 2014 2013 Property acquisition costs Unproved $ 348 $ 1,144 $ 1,444 Proved - - - Exploration costs Expensed 1,667 5,054 1,619 Capitalized - - - Development costs 370 1,745 10,160 Total costs incurred $ 2,385 $ 7,943 $ 13,223 The aggregate capitalized costs relative to oil and gas producing activities are as follows (in thousands): As of December 31, 2015 2014 Unproved oil and gas properties $ 231 $ 3,104 Proved oil and gas properties 76,886 85,557 77,117 88,661 Accumulated depreciation, depletion and amortization (69,116 ) (64,682 ) Net capitalized cost $ 8,001 $ 23,979 Estimated Oil and Natural Gas Reserves - The following information regarding estimates of the Company’s proved oil and gas reserves, substantially all located onshore in Texas and Louisiana, is based on reports prepared on behalf of the Company by its independent petroleum engineers. Because oil and 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. Proved developed and undeveloped reserves are presented as follows (in thousands): Years Ended December 31, 2015 2014 2013 Natural Natural Natural Gas Oil Gas Oil Gas Oil ( Mcf’s ( Bbls. ( Mcf’s ( Bbls. ( Mcf’s ( Bbls Total proved reserves- Beginning of year 5,611 318 6,286 368 8,837 307 Revisions of previous estimates 27 (2 ) 724 6 (1,438 ) (17 ) Oil and gas reserves sold - (3 ) (558 ) (11 ) (28 ) - Extensions, discoveries and other reserve additions 86 13 292 82 523 180 Production (889 ) (100 ) (1,133 ) (127 ) (1,608 ) (102 ) End of year 4,835 226 5,611 318 6,286 368 The components of proved oil and gas reserves for the three years ended December 31, 2015 is presented below. All reserves are in the United States (in thousands): Years Ended December 31, 2015 2014 2013 Natural Natural Natural Gas Oil Gas Oil Gas Oil ( Mcf’s ( Bbls. ( Mcf’s ( Bbls. ( Mcf’s ( Bbls Proved developed reserves 4,813 223 5,482 299 6,157 367 Proved undeveloped reserves 22 3 129 19 129 1 Total proved reserves 4,835 226 5,611 318 6,286 368 The Company has developed internal policies and controls for estimating and recording oil and gas reserve data. The estimation and recording of proved reserves is required to be in compliance with SEC definitions and guidance. The Company assigns responsibility for compliance in reserve bookings to the office of President of AREC. No portion of this individual’s compensation is directly dependent on the quantity of reserves booked. Reserve estimates are required to be made by qualified reserve estimators, as defined by Society of Petroleum Engineers’ Standards. The Company employed third party petroleum consultant, Ryder Scott Company, to prepare its oil and gas reserve data estimates as of December 31, 2015, 2014 and 2013. The firm of Ryder Scott is well recognized within the industry for more than 50 years. As prescribed by the SEC, such proved reserves were estimated using 12-month average oil and 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 oil and 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 oil and 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, oil and gas quantities ultimately recovered will vary from reserve estimates. Standardized Measure of Discounted Future Net Cash Flows from Oil and 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 are included in contracts. The disclosures below do not purport to present the fair market value of the Company’s oil and gas reserves. An estimate of the fair market value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, a discount factor more representative of the time value of money and risks inherent in reserve estimates. The standardized measure of discounted future net cash flows is presented as follows (in thousands): Years Ended December 31, 2015 2014 2013 Future gross revenues $ 23,040 $ 58,885 $ 64,495 Future costs - Lease operating expenses (14,524 ) (16,421 ) (19,207 ) Development costs (103 ) (1,068 ) (119 ) Future net cash flows before income taxes 8,413 41,396 45,169 Discount at 10% per annum (2,987 ) (17,175 ) (17,729 ) Discounted future net cash flows before income taxes 5,426 24,221 27,440 Future income taxes, net of discount at 10% per annum (1,899 ) (8,477 ) (9,604 ) Standardized measure of discounted future net cash flows $ 3,527 $ 15,744 $ 17,836 The estimated value of oil and natural gas reserves and future net revenues, derived therefrom are highly dependent upon oil and gas commodity price assumptions. For such estimates, the Company’s independent petroleum engineers assumed market prices as presented in the table below: Years ended December 31, 2015 2014 2013 Market price Crude oil per barrel $ 45.83 $ 89.60 $ 94.99 Natural gas per thousand cubic feet (mcf) $ 2.62 $ 5.42 $ 4.69 Such prices were based on the unweighted arithmetic average of the prices in effect on the first day of the month for each month of the respective twelve month periods as required by SEC regulations. The prices reported in the reserve disclosures for natural gas include the value of associated natural gas liquids. Oil and gas reserve values and future net cash flow estimates are very sensitive to pricing assumptions and will vary accordingly. The effect of income taxes and discounting on the standardized measure of discounted future net cash flows is presented as follows (in thousands): Years ended December 31, 2015 2014 2013 Future net cash flows before income taxes $ 8,413 $ 41,396 $ 45,169 Future income taxes (2,945 ) (14,489 ) (15,809 ) Future net cash flows 5,468 26,907 29,360 Discount at 10% per annum (1,941 ) (11,163 ) (11,524 ) Standardized measure of discounted future net cash flows $ 3,527 $ 15,744 $ 17,836 The principal sources of changes in the standardized measure of discounted future net flows are as follows (in thousands): Years Ended December 31, 2015 2014 2013 Beginning of year $ 15,744 $ 17,836 $ 16,355 Sale of oil and gas reserves (54 ) (981 ) - Net change in prices and production costs (17,622 ) (72 ) 9,341 New field discoveries and extensions, net of future production costs 292 4,456 9,767 Sales of oil and gas produced, net of production costs 1,038 (6,590 ) (8,373 ) Net change due to revisions in quantity estimates 38 2,460 (3,624 ) Accretion of discount 1,116 1,773 1,797 Production rate changes and other (3,603 ) (4,265 ) (6,629 ) Net change in income taxes 6,578 1,127 (798 ) End of year $ 3,527 $ 15,744 $ 17,836 Results of Operations for Oil and Gas Producing Activities - The results of oil and gas producing activities, excluding corporate overhead and interest costs, are as follows (in thousands): Years Ended December 31, 2015 2014 2013 Revenues $ 5,063 $ 13,361 $ 14,129 Costs and expenses - Production (7,022 ) (6,771 ) (5,756 ) Producing property impairment (10,324 ) (4,001 ) (1,373 ) Exploration (1,667 ) (5,054 ) (1,619 ) Oil and natural gas property sale gain - 2,528 - Depreciation, depletion and amortization (5,066 ) (7,573 ) (7,494 ) Operating income (loss) before income taxes (19,016 ) (7,510 ) (2,113 ) Income tax benefit 6,656 2,628 739 Operating income (loss) $ (12,360 ) $ (4,882 ) $ (1,374 ) |
Summary of Significant Accoun20
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Summary of Significant Accounting Policies [Abstract] | |
Principles of Consolidation | Principles of Consolidation The accompanying consolidated financial statements include the accounts of Adams Resources & Energy, Inc., a Delaware corporation (‟ARE”) together with its wholly owned subsidiaries (the ‟Company”) after elimination of all intercompany accounts and transactions. The impact on the accompanying financial statements of events occurring after December 31, 2015 was evaluated through the date of issuance of these financial statements. |
Nature of Operations | Nature of Operations The Company is engaged in the business of crude oil marketing, tank truck transportation of liquid chemicals, and oil and gas exploration and production. Its primary area of operation is within the Gulf Coast region of the United States. |
Cash and Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents include any Treasury bill, commercial paper, money market fund or federal funds with maturity of 90 days or less. Depending on cash availability and market conditions, investments in corporate and municipal bonds, which are classified as investments in marketable securities, may also be made from time to time. Cash and cash equivalents are maintained with major financial institutions and such deposits may exceed the amount of federally backed insurance provided. While the Company regularly monitors the financial stability of such institutions, cash and cash equivalents ultimately remain at risk subject to the financial viability of such institutions. |
Allowance for Doubtful Accounts | Allowance for Doubtful Accounts Accounts receivable are the product of sales of crude oil and natural gas and the sale of trucking services. Marketing segment wholesale level sales of crude oil comprise in excess of 90 percent of total accounts receivable and under industry practices, such items are ‟settled” and paid in cash within 20 days of the month following the transaction date. For such receivables, an allowance for doubtful accounts is determined based on specific account identification. The balance of accounts receivable results primarily from the sale of trucking services. For this component of receivables, the allowance for doubtful accounts is determined based on a review of specific accounts combined with a review of the general status of the aging of all accounts. |
Inventory | Inventory Inventory consists of crude oil held in storage tanks and at third-party pipelines as part of the Company’s crude oil marketing operations. Crude oil inventory is carried at the lower of average cost or market. Due to declining crude oil prices, inventory valuation losses were as follows (in thousands): 2015 2014 Inventory valuation loss $ 5,357 $ 14,247 |
Prepayments | Prepayments The components of prepayments and other are as follows (in thousands): December 31, 2015 2014 Cash collateral deposits for commodity purchases $ 167 $ 7,872 Insurance premiums 1,609 2,316 Rents, license and other 813 752 $ 2,589 $ 10,940 |
Property and Equipment | Property and Equipment Expenditures for major renewals and betterments are capitalized, and expenditures for maintenance and repairs are expensed as incurred. Interest costs incurred in connection with major capital expenditures are capitalized and amortized over the lives of the related assets. When properties are retired or sold, the related cost and accumulated depreciation, depletion and amortization is removed from the accounts and any gain or loss is reflected in earnings. Oil and gas exploration and development expenditures are accounted for in accordance with the successful efforts method of accounting. Direct costs of acquiring developed or undeveloped leasehold acreage, including lease bonus, brokerage and other fees, are capitalized. Exploratory drilling costs are initially capitalized until the properties are evaluated and determined to be either productive or nonproductive. Such evaluations are made on a quarterly basis. If an exploratory well is determined to be nonproductive, the costs of drilling the well are charged to expense. Costs incurred to drill and complete development wells, including dry holes, are capitalized. As of December 31, 2015 and 2014, the Company had no unevaluated or ‟suspended” exploratory drilling costs. Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base or denominator used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. For lease and well equipment, development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. The numerator for such calculation is actual production volumes for the period. All other property and equipment is depreciated using the straight-line method over the estimated average useful lives of three to twenty years. The Company reviews its long-lived assets for impairment whenever there is evidence that the carrying value of such assets may not be recoverable. Any impairment recognized is permanent and may not be restored. Producing oil and gas properties are reviewed on a field-by-field basis. For properties requiring impairment, the fair value is estimated based on an internal discounted cash flow model. Cash flows are developed based on estimated future production and prices and then discounted using a market based rate of return consistent with that used by the Company in evaluating cash flows for other assets of a similar nature. On a quarterly basis, management evaluates the carrying value of non-producing oil and gas leasehold properties and may deem them impaired based on remaining lease term, area drilling activity and the Company’s plans for the property. This fair value measure depends highly on management’s assessment of the likelihood of continued exploration efforts in a given area. Therefore, such data inputs are categorized as ‟unobservable or Level 3” inputs. (See ‟Fair Value Measurements” below). Importantly, this fair value measure only applies to the write-down of capitalized costs and will never result in an increase to reported earnings. Impairment provisions including in oil and gas segment operating losses were as follows (in thousands): 2015 2014 2013 Producing property impairments $ 10,324 $ 4,001 $ 1,373 Non-producing property impairments $ 1,758 $ 4,008 $ 1,257 Fair value measurements for producing oil and gas properties that were subject to fair value impairment for the years ended December 31, 2015 and 2014 summarize as follows (in thousands): Producing Properties Subject to Fair Value Impairment 2015 2014 Net book value at January 1 $ 18,744 $ 10,180 Property additions 2,117 469 Depletion taken (4,454 ) (1,792 ) Impairment valuation loss (10,324 ) (4,001 ) Net book value at December 31 $ 6,083 $ 4,856 Capitalized costs for non-producing oil and gas leasehold interests currently represent approximately three percent of remaining unamortized oil and gas property carrying costs and categorize as follows (in thousands): December 31, December 31, 2015 2014 Napoleonville Louisiana acreage $ 49 $ 48 South Texas project acreage - 357 Wyoming and other acreage 182 554 Total Non-producing Leasehold Costs $ 231 $ 959 Since the Company is generally not the operator of its oil and gas property interests, it does not maintain underlying detail acreage data and is dependent on the operator when determining which specific acreage will ultimately be drilled. However, the capitalized cost detail on a property-by-property basis is reviewed by management and deemed impaired if development is not anticipated prior to lease expiration. Onshore leasehold periods are normally three years and may contain renewal options. Capitalized cost activity and fair value measurements on non-producing leasehold were as follows (in thousands): Leasehold Costs 2015 2014 Net book value January 1 $ 959 $ 4,906 Leasehold additions 106 865 Advanced royalty payment 529 - In-process wells suspended 395 73 Property sales - (877 ) Impairments valuation loss (1,758 ) (4,008 ) Net book value December 31 $ 231 $ 959 During 2014, the Company sold substantially all of its producing property interests in Oklahoma. Proceeds totaled $1,731,000 and the Company recorded a $1,149,000 pre-tax gain from this sale. Also during 2014 the Company sold one-half of its interest in sections of a South Texas project interest. Proceeds totaled $1,509,000 and the Company recorded a $632,000 pre-tax gain from this sale. Certain other oil and gas property interests were also sold in 2014 for proceeds totaling $822,000 and gains totaling $747,000. The Company sold certain used trucks and equipment from its marketing and transportation segments and recorded net pre-tax gains as follows (in thousands): 2015 2014 2013 Sales of used trucks and equipment $ 535 $ 1,028 $ 683 |
Cash Deposits and Other Assets | Cash Deposits and Other Assets The Company has established certain deposits to support participation in its liability insurance program and remittance of state crude oil severance taxes and other state collateral deposits. Insurance collateral deposits are invested at the discretion of the Company’s insurance carrier and such investments primarily consist of intermediate term federal government bonds and bonds backed by federal agencies. This fair value measure relies on inputs from quoted prices for similar assets and is thus categorized as a ‟Level 2” valuation in the fair value hierarchy. Components of cash deposits and other assets are as follows (in thousands): As of December 31, 2015 2014 Insurance collateral deposits $ 6,531 $ 4,536 State collateral deposits 140 155 Materials and supplies 292 307 $ 6,963 $ 4,998 |
Revenue Recognition | Revenue Recognition Certain commodity purchase and sale contracts utilized by the Company’s marketing business generally qualify as derivative instruments with certain specifically identified crude oil contracts designated as trading activities. From the time of contract origination, such trading activity contracts are marked-to-market and recorded on a net revenue basis in the accompanying consolidated financial statements. Most all crude oil purchase and sale contracts qualify and are designated as non-trading activities and the Company considers such contracts as normal purchases and sales activity. For normal purchases and sales the Company’s customers are invoiced monthly based upon contractually agreed upon terms with revenue recognized in the month in which the physical product is delivered to the customer. Such sales are recorded gross in the financial statements because the Company takes title, has risk of loss for the products, is the primary obligor for the purchase, establishes the sale price independently with a third party, and maintains credit risk associated with the sale of the product. Certain crude oil contracts may be with a single counterparty to provide for similar quantities of crude oil to be bought and sold at different locations. These contracts are entered into for a variety of reasons, including effecting the transportation of the commodity, to minimize credit exposure, and/or to meet the competitive demands of the customer. Such buy/sell arrangements are reflected on a net revenue basis in the accompanying consolidated financial statements. Reporting such crude oil contracts on a gross revenue basis would increase the Company’s reported revenues as follows (in thousands): 2015 2014 2013 Revenue gross-up $ 480,111 $ 1,272,034 $ 1,602,626 Transportation segment customers are invoiced, and the related revenue is recognized as the service is provided. Oil and gas revenue from the Company’s interests in producing wells is recognized as title and physical possession of the oil and gas passes to the purchaser. |
Sales of Long-lived Assets | Sales of long-lived assets Gains and losses from the sale or disposal of long-lived assets that do not meet the criteria for presentation as a discontinued operation are presented in the accompanying financial statements as a component of operating earnings. |
Letter of Credit Facility | Letter of Credit Facility The Company maintains a Credit and Security Agreement with Wells Fargo Bank to provide a $60 million stand-by letter of credit facility used to support crude oil purchases within the marketing segment. This facility is collateralized by the eligible accounts receivable within the segment and certain marketing and transportation equipment. Stand-by letters of credit issued were as follows (in thousands): As of December 31, 2015 2014 Stand-by letters of credit $ 1,000 $ 15,300 The issued stand-by letters of credit are cancelled as the underlying purchase obligations are satisfied by cash payment when due. The letter of credit facility places certain restrictions on the Company’s Gulfmark Energy, Inc. subsidiary. Such restrictions included the maintenance of a combined 1.1 to 1.0 current ratio and the maintenance of positive net earnings excluding inventory valuation changes, as defined, among other restrictions. The Company is currently in compliance with all such financial covenants. |
Statement of Cash Flows | Statement of Cash Flows There were no significant non-cash financing activities in any of the periods reported. Statement of cash flow items include the following (in thousands): 2015 2014 2013 Interest paid $ 13 $ 2 $ 24 Federal and state tax paid $ 6,197 $ 8,169 $ 9,949 State tax refund $ - $ 18 $ 4 Capitalized amounts included in property and equipment that were not included in amounts reported for cash additions in the Statements of Cash Flows for the applicable report dates were as follows (in thousands): As of December 31, 2015 2014 2013 Property and equipment additions $ 1,707 $ 1,137 $ 1,507 |
Earnings per Share | Earnings per Share Earnings per share are based on the weighted average number of shares of common stock and potentially dilutive common stock shares outstanding during the period. The weighted average number of shares outstanding was 4,217,596 for 2015, 2014 and 2013. There were no potentially dilutive securities outstanding during those periods. |
Share-Based Payments | Share-Based Payments During the periods presented herein, the Company had no stock-based employee compensation plans, nor any other share-based payment arrangements. |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Examples of significant estimates used in the accompanying consolidated financial statements include the oil and gas reserve volumes forming the foundation for calculating depreciation, depletion and amortization and for estimating cash flows when assessing impairment triggers and when estimating values associated with oil and gas properties. Other examples include revenue accruals, the provision for bad debts, insurance related accruals, income tax permanent and timing differences, contingencies, and valuation of fair value contracts. |
Income Taxes | Income Taxes Income taxes are accounted for using the asset and liability method. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of such items and their respective tax basis (See also Note (2) to consolidated financial statements). |
Use of Derivative Instruments | Use of Derivative Instruments The Company’s marketing segment is involved in the purchase and sale of crude oil. The Company seeks to make a profit by procuring this commodity as it is produced and then delivering the material to end users or the intermediate use marketplace. As is typical for the industry, such transactions are made pursuant to the terms of forward month commodity purchase and/or sale contracts. Some of these contracts meet the definition of a derivative instrument and therefore, the Company accounts for such contracts at fair value, unless the normal purchase and sale exception is applicable. Such underlying contracts are standard for the industry and are the governing document for the Company’s crude oil wholesale distribution businesses. None of the Company’s derivative instruments have been designated as hedging instruments. The accounting methodology utilized by the Company for its commodity contracts is further discussed below under the caption ‟Fair Value Measurements”. The estimated fair value of forward month commodity contracts (derivatives) is reflected in the accompanying Consolidated Balance Sheet as of December 31, 2015 as follows (in thousands): Balance Sheet Location and Amount Current Other Current Other Assets Assets Liabilities Liabilities Asset Derivatives - Fair Value Commodity Contracts at Gross Valuation $ - $ - $ - $ - Liability Derivatives - Fair Value Commodity Contracts at Gross Valuation - - 195 - Less Counterparty Offsets - - - - As Reported Fair Value Contracts $ - $ - $ 195 $ - As of December 31, 2015, one contract comprised the Company’s derivative valuations. The purchase and sale contract encompass approximately 65 barrels of diesel fuel per day in each of January, February and March 2016. The estimated fair value of forward month commodity contracts (derivatives) is reflected in the accompanying Consolidated Balance Sheet as of December 31, 2014 as follows (in thousands): Balance Sheet Location and Amount Current Other Current Other Assets Assets Liabilities Liabilities Asset Derivatives - Fair Value Commodity Contracts at Gross Valuation $ 1,332 $ - $ - $ - Liability Derivatives - Fair Value Commodity Contracts at Gross Valuation - - 1,339 - Less Counterparty Offsets (396 ) - (396 ) - As Reported Fair Value Contracts $ 936 $ - $ 943 $ - As of December 31, 2014, three commodity purchase and sale contracts comprised the Company’s derivative valuations. These contracts encompass approximately 294 barrels per day of crude oil for January and February 2015 plus 129 barrels per day of crude oil from March 2015 through December 2015. The Company only enters into commodity contracts with creditworthy counterparties or obtains collateral support for such activities. As of December 31, 2015 and 2014, the Company was not holding nor had it posted any collateral to support its forward month fair value derivative activity. The Company is not subject to any credit-risk related trigger events. The Company has no other financial investment arrangements that would serve to offset its derivative contracts. Forward month commodity contracts (derivatives) are reflected in the accompanying Consolidated Statement of Operations for the years ended December 31, 2015, 2014 and 2013 as follows (in thousands): Gain (Loss) Location 2015 2014 2013 Revenues – marketing $ (188 ) $ 312 $ (193 ) |
Fair Value Measurements | Fair Value Measurements The carrying amount reported in the Consolidated Balance Sheet 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. Fair value contracts consist of derivative financial instruments and are recorded as either an asset or liability measured at fair value. Changes in fair value are recognized immediately in earnings unless the derivatives qualify for, and the Company elects, cash flow hedge accounting. The Company had no contracts designated for hedge accounting during any reporting periods. Fair value estimates are based on assumptions that market participants would use when pricing an asset or liability and the Company uses a fair value hierarchy of three levels that prioritizes the information used to develop those assumptions. Currently, for all items presented herein, the Company utilizes a market approach to valuing its contracts. On a contract by contract, forward month by forward month basis, the Company obtains observable market data for valuing its contracts. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data. The fair value hierarchy is summarized as follows: Level 1 – quoted prices in active markets for identical assets or liabilities that may be accessed at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. For Level 1 valuation of marketable securities, the Company utilizes market quotations provided by its primary financial institution and for the valuations of derivative financial instruments, the Company utilizes the New York Mercantile Exchange ‟NYMEX” for such valuations. Level 2 – (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 – Unobservable market data inputs for assets or liabilities. As of December 31, 2015, the Company’s fair value assets and liabilities are summarized and categorized as follows (in thousands): Market Data Inputs Gross Level 1 Gross Level 2 Gross Level 3 Counterparty Quoted Prices Observable Unobservable Offsets Total Derivatives - Current assets $ - $ - $ - $ - $ - - Current liabilities - (195 ) - - (195 ) Net Value $ - $ (195 ) $ - $ - $ (195 ) As of December 31, 2014, the Company’s fair value assets and liabilities are summarized and categorized as follows (in thousands): Market Data Inputs Gross Level 1 Gross Level 2 Gross Level 3 Counterparty Quoted Prices Observable Unobservable Offsets Total Derivatives - Current assets $ - $ 1,332 $ - $ (396 ) $ 936 - Current liabilities - (1,339 ) - 396 (943 ) Net Value $ - $ (7 ) $ - $ - $ (7 ) When determining fair value measurements, the Company makes credit valuation adjustments to reflect both its own nonperformance risk and its counterparty’s nonperformance risk. When adjusting the fair value of derivative contracts for the effect of nonperformance risk, the impact of netting and applicable credit enhancements, such as collateral postings, thresholds, and guarantees are considered. Credit valuation adjustments utilize Level 3 inputs, such as credit scores to evaluate the likelihood of default by the Company or its counterparties. As of December 31, 2015 and 2014, credit valuation adjustments were not significant to the overall valuation of the Company’s fair value contracts. As a result, fair value assets and liabilities are included in their entirety in the fair value hierarchy. The following table illustrates the factors impacting the change in the net value of the Company’s fair value contracts for the year ended December 31, 2015 (in thousands): Level 1 Level 2 Quoted Prices Observable Total Net Fair Value January 1 $ - $ (7 ) $ (7 ) - Net realized (gains) losses - 7 7 - Net unrealized gains (losses) - (195 ) (195 ) Net Fair Value December 31 $ - $ (195 ) $ (195 ) The following table illustrates the factors impacting the change in the net value of the Company’s fair value contracts for the year ended December 31, 2014 (in thousands): Level 1 Level 2 Quoted Prices Observable Total Net Fair Value January 1 $ - $ 395 $ 395 - Net realized (gains) losses - 220 220 - Option deposit - (714 ) (714 ) - Option gain - 99 99 - Net unrealized gains (losses) - (7 ) (7 ) Net Fair Value December 31 $ - $ (7 ) $ (7 ) |
Asset Retirement Obligations | Asset Retirement Obligations The Company records a liability for the estimated retirement costs associated with certain tangible long-lived assets. The estimated fair value of asset retirement obligations are recorded in the period in which they are incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the asset or the units of production associated with the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. A summary of the Company’s asset retirement obligations is presented as follows (in thousands): 2015 2014 Balance on January 1 $ 2,464 $ 2,564 -Liabilities incurred 39 111 -Accretion of discount 93 94 -Liabilities settled (127 ) (305 ) Balance on December 31 $ 2,469 $ 2,464 In addition to an accrual for asset retirement obligations, the Company maintains $75,000 in escrow cash, which is legally restricted for the potential purpose of settling asset retirement costs in accordance with certain state regulations. Such cash deposits are included in other assets in the accompanying consolidated balance sheet. |
Recent Accounts Pronouncement | Recent Accounts Pronouncement In May 2014, the FASB amended the existing accounting standards for revenue recognition. The amendments are based on the principle that revenue should be recognized to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new guidance is effective for the annual period ending after December 15, 2017. Early adoption is not permitted. The amendments may be applied retrospectively to each prior period presented or retrospectively with the cumulative effect recognized as of the date of initial application. Management is currently evaluating the impact of these amendments on the Company’s consolidated financial statements and the transition alternatives. In August 2014, the FASB issued guidance requiring management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. The standard also provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new guidance is effective for the annual period ending after December 15, 2016, and interim periods thereafter, with early adoption permitted. Management does not expect the adoption of this guidance to have an impact on the Consolidated Financial Statements. In July 2015, the FASB amended the existing accounting standards for inventory to provide for the measurement of inventory at the lower of cost of ‟ In November 2015, the FASB issued guidance to simplify the presentation of deferred taxes in the statement of financial position. The amendment requires that deferred tax assets and liabilities be classified as non-current in the balance sheet. The Company adjusted this guidance on a prospective basis effective January 1, 2015. Management believes the impact of other recently issued standards and updates, which are not yet effective, will not have a material impact on the Company’s consolidated financial position, results of operations or cash flows upon adoption. |
Summary of Significant Accoun21
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Summary of Significant Accounting Policies [Abstract] | |
Summary of inventory valuation losses | Due to declining crude oil prices, inventory valuation losses were as follows (in thousands): 2015 2014 Inventory valuation loss $ 5,357 $ 14,247 |
Components of prepayments and other | The components of prepayments and other are as follows (in thousands): December 31, 2015 2014 Cash collateral deposits for commodity purchases $ 167 $ 7,872 Insurance premiums 1,609 2,316 Rents, license and other 813 752 $ 2,589 $ 10,940 |
Fair value of impairment provisions | Impairment provisions including in oil and gas segment operating losses were as follows (in thousands): 2015 2014 2013 Producing property impairments $ 10,324 $ 4,001 $ 1,373 Non-producing property impairments $ 1,758 $ 4,008 $ 1,257 |
Fair value measurements for producing oil and gas properties that were subject to fair value impairment | Fair value measurements for producing oil and gas properties that were subject to fair value impairment for the years ended December 31, 2015 and 2014 summarize as follows (in thousands): Producing Properties Subject to Fair Value Impairment 2015 2014 Net book value at January 1 $ 18,744 $ 10,180 Property additions 2,117 469 Depletion taken (4,454 ) (1,792 ) Impairment valuation loss (10,324 ) (4,001 ) Net book value at December 31 $ 6,083 $ 4,856 |
Capitalized costs for non-producing oil and gas leasehold interests | Capitalized costs for non-producing oil and gas leasehold interests currently represent approximately three percent of remaining unamortized oil and gas property carrying costs and categorize as follows (in thousands): December 31, December 31, 2015 2014 Napoleonville Louisiana acreage $ 49 $ 48 South Texas project acreage - 357 Wyoming and other acreage 182 554 Total Non-producing Leasehold Costs $ 231 $ 959 |
Capitalized cost activity on the other acreage areas | Capitalized cost activity and fair value measurements on non-producing leasehold were as follows (in thousands): Leasehold Costs 2015 2014 Net book value January 1 $ 959 $ 4,906 Leasehold additions 106 865 Advanced royalty payment 529 - In-process wells suspended 395 73 Property sales - (877 ) Impairments valuation loss (1,758 ) (4,008 ) Net book value December 31 $ 231 $ 959 |
Pre-tax gain on the sale of equipment | The Company sold certain used trucks and equipment from its marketing and transportation segments and recorded net pre-tax gains as follows (in thousands): 2015 2014 2013 Sales of used trucks and equipment $ 535 $ 1,028 $ 683 |
Components of cash deposits and other assets | Components of cash deposits and other assets are as follows (in thousands): As of December 31, 2015 2014 Insurance collateral deposits $ 6,531 $ 4,536 State collateral deposits 140 155 Materials and supplies 292 307 $ 6,963 $ 4,998 |
Reporting revenue of crude oil contracts on a gross revenue basis | Reporting such crude oil contracts on a gross revenue basis would increase the Company’s reported revenues as follows (in thousands): 2015 2014 2013 Revenue gross-up $ 480,111 $ 1,272,034 $ 1,602,626 |
Stand-by letters of credit issued | This facility is collateralized by the eligible accounts receivable within the segment and certain marketing and transportation equipment. Stand-by letters of credit issued were as follows (in thousands): As of December 31, 2015 2014 Stand-by letters of credit $ 1,000 $ 15,300 |
Non-cash financing activities | There were no significant non-cash financing activities in any of the periods reported. Statement of cash flow items include the following (in thousands): 2015 2014 2013 Interest paid $ 13 $ 2 $ 24 Federal and state tax paid $ 6,197 $ 8,169 $ 9,949 State tax refund $ - $ 18 $ 4 |
Capitalized costs included in property plant and equipment | Capitalized amounts included in property and equipment that were not included in amounts reported for cash additions in the Statements of Cash Flows for the applicable report dates were as follows (in thousands): As of December 31, 2015 2014 2013 Property and equipment additions $ 1,707 $ 1,137 $ 1,507 |
Derivatives reflected in the consolidated balance sheet | The estimated fair value of forward month commodity contracts (derivatives) is reflected in the accompanying Consolidated Balance Sheet as of December 31, 2015 as follows (in thousands): Balance Sheet Location and Amount Current Other Current Other Assets Assets Liabilities Liabilities Asset Derivatives - Fair Value Commodity Contracts at Gross Valuation $ - $ - $ - $ - Liability Derivatives - Fair Value Commodity Contracts at Gross Valuation - - 195 - Less Counterparty Offsets - - - - As Reported Fair Value Contracts $ - $ - $ 195 $ - As of December 31, 2015, one contract comprised the Company’s derivative valuations. The purchase and sale contract encompass approximately 65 barrels of diesel fuel per day in each of January, February and March 2016. The estimated fair value of forward month commodity contracts (derivatives) is reflected in the accompanying Consolidated Balance Sheet as of December 31, 2014 as follows (in thousands): Balance Sheet Location and Amount Current Other Current Other Assets Assets Liabilities Liabilities Asset Derivatives - Fair Value Commodity Contracts at Gross Valuation $ 1,332 $ - $ - $ - Liability Derivatives - Fair Value Commodity Contracts at Gross Valuation - - 1,339 - Less Counterparty Offsets (396 ) - (396 ) - As Reported Fair Value Contracts $ 936 $ - $ 943 $ - |
Derivatives reflected in the consolidated statement of operations | Forward month commodity contracts (derivatives) are reflected in the accompanying Consolidated Statement of Operations for the years ended December 31, 2015, 2014 and 2013 as follows (in thousands): Gain (Loss) Location 2015 2014 2013 Revenues – marketing $ (188 ) $ 312 $ (193 ) |
Fair value assets and liabilities | As of December 31, 2015, the Company’s fair value assets and liabilities are summarized and categorized as follows (in thousands): Market Data Inputs Gross Level 1 Gross Level 2 Gross Level 3 Counterparty Quoted Prices Observable Unobservable Offsets Total Derivatives - Current assets $ - $ - $ - $ - $ - - Current liabilities - (195 ) - - (195 ) Net Value $ - $ (195 ) $ - $ - $ (195 ) As of December 31, 2014, the Company’s fair value assets and liabilities are summarized and categorized as follows (in thousands): Market Data Inputs Gross Level 1 Gross Level 2 Gross Level 3 Counterparty Quoted Prices Observable Unobservable Offsets Total Derivatives - Current assets $ - $ 1,332 $ - $ (396 ) $ 936 - Current liabilities - (1,339 ) - 396 (943 ) Net Value $ - $ (7 ) $ - $ - $ (7 ) |
Factors impacting the change in the net value of the company's fair value contracts | The following table illustrates the factors impacting the change in the net value of the Company’s fair value contracts for the year ended December 31, 2015 (in thousands): Level 1 Level 2 Quoted Prices Observable Total Net Fair Value January 1 $ - $ (7 ) $ (7 ) - Net realized (gains) losses - 7 7 - Net unrealized gains (losses) - (195 ) (195 ) Net Fair Value December 31 $ - $ (195 ) $ (195 ) The following table illustrates the factors impacting the change in the net value of the Company’s fair value contracts for the year ended December 31, 2014 (in thousands): Level 1 Level 2 Quoted Prices Observable Total Net Fair Value January 1 $ - $ 395 $ 395 - Net realized (gains) losses - 220 220 - Option deposit - (714 ) (714 ) - Option gain - 99 99 - Net unrealized gains (losses) - (7 ) (7 ) Net Fair Value December 31 $ - $ (7 ) $ (7 ) |
Company's asset retirement obligations | A summary of the Company’s asset retirement obligations is presented as follows (in thousands): 2015 2014 Balance on January 1 $ 2,464 $ 2,564 -Liabilities incurred 39 111 -Accretion of discount 93 94 -Liabilities settled (127 ) (305 ) Balance on December 31 $ 2,469 $ 2,464 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Income Taxes [Abstract] | |
Components of the company's income tax (provision) benefit | The following table shows the components of the Company’s income tax (provision) benefit (in thousands): Years ended December 31, 2015 2014 2013 Current: Federal $ (3,883 ) $ (8,626 ) $ (8,102 ) State (190 ) (1,249 ) (892 ) (4,073 ) (9,875 ) (8,994 ) Deferred: Federal 5,011 5,878 (2,682 ) State (168 ) 273 (478 ) 4,843 6,151 (3,160 ) $ 770 $ (3,724 ) $ (12,154 ) |
Income tax (provision) benefit allocable to continuing and discontinued operations | The following table summarizes the components of the income tax (provision) benefit (in thousands): Years ended December 31, 2015 2014 2013 From continuing operations $ 770 $ (3,561 ) $ (12,429 ) From discontinued operations - (163 ) 275 $ 770 $ (3,724 ) $ (12,154 ) |
Reconciliation of taxes computed at the corporate federal income tax rate to the reported income tax (provision) | Taxes computed at the corporate federal income tax rate reconcile to the reported income tax (provision) as follows (in thousands): Years ended December 31, 2015 2014 2013 Statutory federal income tax (provision) benefit $ 716 $ (3,587 ) $ (11,819 ) State income tax (provision) benefit (233 ) (634 ) (891 ) Federal statutory depletion 144 549 522 Other 143 (52 ) 34 $ 770 $ (3,724 ) $ (12,154 ) |
Components of the federal deferred tax asset (liability) | The components of the federal deferred tax asset (liability) are as follows (in thousands): Years Ended December 31, 2015 2014 Current deferred tax asset (liability) Allowance for doubtful accounts $ - $ 62 Prepaid and other insurance - (719 ) Fair value contracts - (1 ) Net current deferred liability - (658 ) Long-term deferred tax asset (liability) Prepaid and other insurance (1,243 ) - Property (7,408 ) (12,673 ) Uniform capitalization 704 661 Other (51 ) (170 ) Net long-term deferred tax liability (7,998 ) (12,182 ) Net deferred tax liability $ (7,998 ) $ (12,840 ) |
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 2012 Texas 2011 Louisiana 2012 Michigan 2011 |
Concentration of Credit Risk (T
Concentration of Credit Risk (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Concentration of Credit Risk [Abstract] | |
Changes in the allowance for doubtful accounts | An analysis of the changes in the allowance for doubtful accounts is presented as follows (in thousands): 2015 2014 2013 Balance, beginning of year $ 179 $ 252 $ 206 Provisions for bad debts 116 50 147 Less: Write-offs and recoveries (89 ) (123 ) (101 ) Balance, end of year $ 206 $ 179 $ 252 |
Schedule of customers providing more than 10 percent of revenues | Management believes that a loss of any of those customers where the Company currently derives more than 10 percent of its revenues would not have a material adverse effect on the Company’s operations as shown below: Individual customer sales Individual customer receivables in excess in excess of 10% of revenues of 10% of total receivables as of December 31, 2015 2014 2013 2015 2014 2013 24.4 % 20.3 % 18.5 % 20.3 % 16.6 % 16.0 % 13.8 % 14.0 % 17.7 % 16.5 % 16.6 % 15.8 % - - 15.8 % 12.7 % 10.4 % 12.7 % - - 10.4 % - - - |
Employee Benefits (Tables)
Employee Benefits (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Employee Benefits [Abstract] | |
401K Plan contributory expenses | The Company’s 401K plan contributory expenses were as follows (in thousands): 2015 2014 2013 Contributory expenses $ 768 $ 691 $ 674 |
Transactions with Affiliates (T
Transactions with Affiliates (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Transactions with Affiliates [Abstract] | |
Schedule of activities with affiliates | Activities with affiliates were as follows (in thousands): 2015 2014 2013 Overhead recoveries $ 97 $ 151 $ 152 Affiliate billings to Company $ 68 $ 65 $ 69 Company billings to affiliate $ 35 $ 42 $ 99 Rentals paid to affiliate $ 618 $ 607 $ 481 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies [Abstract] | |
Rental expense | The Company has no capital lease arrangements. Rental expense is as follows (in thousands): Years ended December 31, 2015 2014 2013 Rental expense $ 11,168 $ 9,755 $ 8,281 |
Long-term non-cancelable operating leases and terminal arrangements for the next five years | At December 31, 2015, rental obligations under long-term non-cancelable operating leases and terminal arrangements for the next five years and thereafter are payable as follows ( in thousands): 2016 2017 2018 2019 2020 Thereafter Total $ 6,218 $ 4,160 $ 1,697 $ 318 $ - $ - $ 12,393 |
Estimated expenses and liabilities | The Company has appropriately recognized estimated expenses and liabilities related to these policies for losses incurred but not reported to the Company or its insurance carrier as follows (in thousands): As of December 31, 2015 2014 2013 Estimated expenses and liabilities $ 2,086 $ 2,585 $ 1,796 |
Medical accrual amounts | Medical accrual amounts are as follows (in thousands): As of December 31, 2015 2014 2013 Accrued medical claims $ 1,107 $ 1,057 $ 1,129 |
Guarantees (Tables)
Guarantees (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Guarantees [Abstract] | |
Parental guaranteed obligations | As of December 31, 2015, parental guaranteed obligations are approximately as follows (in thousands): 2016 2017 2018 2019 Thereafter Total Commodity purchases $ 15,855 - - - - $ 15,855 Letters of credit 1,000 - - - - 1,000 $ 16,855 $ - $ - $ - $ - $ 16,855 |
Segment Reporting (Tables)
Segment Reporting (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
Information concerning business activities and assets by segment | Information concerning the Company’s various business activities is summarized as follows (in thousands): Segment Operating Depreciation Depletion and Property and Equipment Revenues Earnings (loss) Amortization Additions Year ended December 31, 2015- Marketing $ 1,875,885 $ 22,895 (1) $ 11,097 $ 2,126 Transportation 63,331 3,701 7,554 6,579 Oil and gas 5,063 (19,016 ) (2) 5,066 2,369 $ 1,944,279 $ 7,580 $ 23,717 $ 11,074 Year ended December 31, 2014- Marketing $ 4,050,497 $ 20,854 (1) $ 9,626 $ 13,598 Transportation 68,968 4,750 7,416 8,994 Oil and gas 13,361 (7,510 ) (2) 7,573 7,931 $ 4,132,826 $ 18,094 $ 24,615 $ 30,523 Year ended December 31, 2013- Marketing $ 3,863,057 $ 40,369 (1) $ 7,682 $ 11,343 Transportation 68,783 5,180 7,099 3,165 Oil and gas 14,129 (2,113 ) (2) 7,494 13,094 $ 3,945,969 $ 43,436 $ 22,275 $ 27,602 __________________________________ (1) (2) |
Reconciliation of segment earnings to earnings before income taxes | Segment operating earnings reflect revenues net of operating costs and depreciation, depletion and amortization and are reconciled to earnings from continuing operations before income taxes, as follows (in thousands): Years Ended December 31, 2015 2014 2013 Segment operating earnings $ 7,580 $ 18,094 $ 43,436 - General and administrative expenses (9,939 ) (8,613 ) (9,060 ) Operating earnings (loss) (2,359 ) 9,481 34,376 - Interest income 327 301 198 - Interest expense (13 ) (2 ) (24 ) Earnings (loss) from continuing operations before income taxes and discontinued operations $ (2,045 ) $ 9,780 $ 34,550 |
Identifiable assets by industry segment | Identifiable assets by industry segment are as follows (in thousands): Years Ended December 31, 2015 2014 2013 Marketing $ 96,723 $ 189,332 $ 306,693 Transportation 35,010 37,643 34,406 Oil and gas 8,930 25,888 37,093 Cash and other 102,552 87,951 69,890 $ 243,215 $ 340,814 $ 448,082 |
Quarterly Financial Data (Una29
Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Data (Unaudited) [Abstract] | |
Selected quarterly financial data and earnings per share | Selected quarterly financial data and earnings per share of the Company are presented below for the years ended December 31, 2015 and 2014 (in thousands, except per share data): Earnings (Loss) from Continuing Operations Net Earnings (Loss) Dividends Revenues Amount Per Share Amount Per Share Amount Per Share 2015 - March 31 $ 555,573 $ 3,097 $ .73 $ 3,097 $ .73 $ 928 $ .22 June 30 600,558 4,340 1.03 4,340 1.03 928 .22 September 30 439,893 (308 ) (.07 ) (308 ) (.07 ) 928 .22 December 31 348,255 (8,404 ) (1.99 ) (8,404 ) (1.99 ) 928 .22 Total $ 1,944,279 $ (1,275 ) $ (.30 ) $ (1,275 ) $ (.30 ) $ 3,712 $ .88 2014 - March 31 $ 949,189 $ 5,363 $ 1.27 $ 5,363 $ 1.27 $ 928 $ .22 June 30 1,159,931 3,975 .94 3,975 .94 928 .22 September 30 1,173,970 3,855 .92 3,855 .92 928 .22 December 31 849,736 (6,974 ) (1.65 ) (6,670 ) (1.58 ) 927 .22 Total $ 4,132,826 $ 6,219 $ 1.48 $ 6,523 $ 1.55 $ 3,711 $ .88 |
Oil and Gas Producing Activit30
Oil and Gas Producing Activities (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Oil and Gas Producing Activities (Unaudited) [Abstract] | |
Cost incurred in oil and gas exploration and development activities | Total costs incurred in oil and gas exploration and development activities, all within the United States, were as follows (in thousands): For the year Ended December 31, 2015 2014 2013 Property acquisition costs Unproved $ 348 $ 1,144 $ 1,444 Proved - - - Exploration costs Expensed 1,667 5,054 1,619 Capitalized - - - Development costs 370 1,745 10,160 Total costs incurred $ 2,385 $ 7,943 $ 13,223 |
Capitalized costs relating to oil and gas producing activities | The aggregate capitalized costs relative to oil and gas producing activities are as follows (in thousands): As of December 31, 2015 2014 Unproved oil and gas properties $ 231 $ 3,104 Proved oil and gas properties 76,886 85,557 77,117 88,661 Accumulated depreciation, depletion and amortization (69,116 ) (64,682 ) Net capitalized cost $ 8,001 $ 23,979 |
Proved developed and undeveloped oil and gas reserves | Proved developed and undeveloped reserves are presented as follows (in thousands): Years Ended December 31, 2015 2014 2013 Natural Natural Natural Gas Oil Gas Oil Gas Oil ( Mcf’s ( Bbls. ( Mcf’s ( Bbls. ( Mcf’s ( Bbls Total proved reserves- Beginning of year 5,611 318 6,286 368 8,837 307 Revisions of previous estimates 27 (2 ) 724 6 (1,438 ) (17 ) Oil and gas reserves sold - (3 ) (558 ) (11 ) (28 ) - Extensions, discoveries and other reserve additions 86 13 292 82 523 180 Production (889 ) (100 ) (1,133 ) (127 ) (1,608 ) (102 ) End of year 4,835 226 5,611 318 6,286 368 |
Components of proved oil and gas reserves | The components of proved oil and gas reserves for the three years ended December 31, 2015 is presented below. All reserves are in the United States (in thousands): Years Ended December 31, 2015 2014 2013 Natural Natural Natural Gas Oil Gas Oil Gas Oil ( Mcf’s ( Bbls. ( Mcf’s ( Bbls. ( Mcf’s ( Bbls Proved developed reserves 4,813 223 5,482 299 6,157 367 Proved undeveloped reserves 22 3 129 19 129 1 Total proved reserves 4,835 226 5,611 318 6,286 368 |
Standardized measure of discounted future net cash flows | The standardized measure of discounted future net cash flows is presented as follows (in thousands): Years Ended December 31, 2015 2014 2013 Future gross revenues $ 23,040 $ 58,885 $ 64,495 Future costs - Lease operating expenses (14,524 ) (16,421 ) (19,207 ) Development costs (103 ) (1,068 ) (119 ) Future net cash flows before income taxes 8,413 41,396 45,169 Discount at 10% per annum (2,987 ) (17,175 ) (17,729 ) Discounted future net cash flows before income taxes 5,426 24,221 27,440 Future income taxes, net of discount at 10% per annum (1,899 ) (8,477 ) (9,604 ) Standardized measure of discounted future net cash flows $ 3,527 $ 15,744 $ 17,836 |
Assumed market prices of oil and natural gas reserves and future net revenues | The estimated value of oil and natural gas reserves and future net revenues, derived therefrom are highly dependent upon oil and gas commodity price assumptions. For such estimates, the Company’s independent petroleum engineers assumed market prices as presented in the table below: Years ended December 31, 2015 2014 2013 Market price Crude oil per barrel $ 45.83 $ 89.60 $ 94.99 Natural gas per thousand cubic feet (mcf) $ 2.62 $ 5.42 $ 4.69 |
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 is presented as follows (in thousands): Years ended December 31, 2015 2014 2013 Future net cash flows before income taxes $ 8,413 $ 41,396 $ 45,169 Future income taxes (2,945 ) (14,489 ) (15,809 ) Future net cash flows 5,468 26,907 29,360 Discount at 10% per annum (1,941 ) (11,163 ) (11,524 ) Standardized measure of discounted future net cash flows $ 3,527 $ 15,744 $ 17,836 |
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 flows are as follows (in thousands): Years Ended December 31, 2015 2014 2013 Beginning of year $ 15,744 $ 17,836 $ 16,355 Sale of oil and gas reserves (54 ) (981 ) - Net change in prices and production costs (17,622 ) (72 ) 9,341 New field discoveries and extensions, net of future production costs 292 4,456 9,767 Sales of oil and gas produced, net of production costs 1,038 (6,590 ) (8,373 ) Net change due to revisions in quantity estimates 38 2,460 (3,624 ) Accretion of discount 1,116 1,773 1,797 Production rate changes and other (3,603 ) (4,265 ) (6,629 ) Net change in income taxes 6,578 1,127 (798 ) End of year $ 3,527 $ 15,744 $ 17,836 |
Results of operations for oil and gas producing activities | The results of oil and gas producing activities, excluding corporate overhead and interest costs, are as follows (in thousands): Years Ended December 31, 2015 2014 2013 Revenues $ 5,063 $ 13,361 $ 14,129 Costs and expenses - Production (7,022 ) (6,771 ) (5,756 ) Producing property impairment (10,324 ) (4,001 ) (1,373 ) Exploration (1,667 ) (5,054 ) (1,619 ) Oil and natural gas property sale gain - 2,528 - Depreciation, depletion and amortization (5,066 ) (7,573 ) (7,494 ) Operating income (loss) before income taxes (19,016 ) (7,510 ) (2,113 ) Income tax benefit 6,656 2,628 739 Operating income (loss) $ (12,360 ) $ (4,882 ) $ (1,374 ) |
Summary of Significant Accoun31
Summary of Significant Accounting Policies (Details) | 12 Months Ended | ||
Dec. 31, 2015USD ($)bblContractshares | Dec. 31, 2014USD ($)bblContractshares | Dec. 31, 2013USD ($)shares | |
Allowance for Doubtful Accounts [Abstract] | |||
Percentage of crude oil and natural gas sales in accounts receivable | 90.00% | ||
Number of days, cash is received from transaction date | 20 days | ||
Inventory [Abstract] | |||
Inventory valuation loss | $ 5,357,000 | $ 14,247,000 | |
Components of prepayments and other [Abstract] | |||
Cash collateral deposits for commodity purchases | 167,000 | 7,872,000 | |
Insurance premiums | 1,609,000 | 2,316,000 | |
Rents, license and other | 813,000 | 752,000 | |
Prepayments, total | 2,589,000 | 10,940,000 | |
Fair value measurements for producing and non-producing oil and gas properties that were subject to fair value impairment [Abstract] | |||
Leasehold additions | 2,385,000 | 7,943,000 | $ 13,223,000 |
Impairment valuation loss | (12,082,000) | (8,009,000) | (2,630,000) |
Sale of used trucks and equipment [Abstract] | |||
Sales of used trucks and equipment | 535,000 | 1,028,000 | 683,000 |
Total Non-producing Leasehold Costs | 231,000 | 959,000 | |
Pre-tax gain on sale of oil and gas properties | 0 | 2,528,000 | 0 |
Cash Deposits and Other Assets [Abstract] | |||
Insurance collateral deposits | 6,531,000 | 4,536,000 | |
State collateral deposits | 140,000 | 155,000 | |
Materials and supplies | 292,000 | 307,000 | |
Cash deposits and other | 6,963,000 | 4,998,000 | |
Revenue Recognition [Abstract] | |||
Revenue gross-up | 480,111,000 | 1,212,034,000 | 1,602,626,000 |
Statement of Cash Flows [Abstract] | |||
Interest paid | 13,000 | 2,000 | 24,000 |
Federal and state tax paid | 6,197,000 | 8,169,000 | 9,949,000 |
State tax refund | 0 | 18,000 | 4,000 |
Property and equipment additions | $ 1,707,000 | $ 1,137,000 | $ 1,507,000 |
Earnings Per Share [Abstract] | |||
Weighted average number of shares outstanding (in shares) | shares | 4,217,596 | 4,217,596 | 4,217,596 |
Minimum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment, useful life | 3 years | ||
Maximum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment, useful life | 20 years | ||
Producing Oil and Gas Properties [Member] | |||
Fair value measurements for producing and non-producing oil and gas properties that were subject to fair value impairment [Abstract] | |||
Impairment valuation loss | $ 10,324,000 | $ 4,001,000 | $ 1,373,000 |
Sale of used trucks and equipment [Abstract] | |||
Proceeds from sale of oil and gas properties | 1,731,000 | ||
Pre-tax gain on sale of oil and gas properties | 1,149,000 | ||
Producing Oil and Gas Properties Impaired in 2014 [Member] | |||
Fair value measurements for producing and non-producing oil and gas properties that were subject to fair value impairment [Abstract] | |||
Net book value at January 1 | 18,744,000 | ||
Leasehold additions | 2,117,000 | ||
Depletion taken | (4,454,000) | ||
Impairment valuation loss | (10,324,000) | ||
Net book value at December 31 | 6,083,000 | 18,744,000 | |
Producing Oil and Gas Properties Impaired in 2013 [Member] | |||
Fair value measurements for producing and non-producing oil and gas properties that were subject to fair value impairment [Abstract] | |||
Net book value at January 1 | 4,856,000 | 10,180,000 | |
Leasehold additions | 469,000 | ||
Depletion taken | (1,792,000) | ||
Impairment valuation loss | (4,001,000) | ||
Net book value at December 31 | 4,856,000 | 10,180,000 | |
Non-Producing Oil and Gas Properties [Member] | |||
Fair value measurements for producing and non-producing oil and gas properties that were subject to fair value impairment [Abstract] | |||
Impairment valuation loss | $ 1,758,000 | 4,008,000 | $ 1,257,000 |
Sale of used trucks and equipment [Abstract] | |||
Capitalized costs for non-producing oil and gas leasehold interests specified as percentage of total costs | 3.00% | ||
South Texas Project acreage [Member] | |||
Sale of used trucks and equipment [Abstract] | |||
Total Non-producing Leasehold Costs | $ 0 | 357,000 | |
South Texas Project [Member] | |||
Sale of used trucks and equipment [Abstract] | |||
Proceeds from sale of oil and gas properties | 1,509,000 | ||
Pre-tax gain on sale of oil and gas properties | 632,000 | ||
Number of oil and gas producing properties sold | 0.5 | ||
Napoleonville Louisiana acreage [Member] | |||
Sale of used trucks and equipment [Abstract] | |||
Total Non-producing Leasehold Costs | 49,000 | 48,000 | |
Other acreage [Member] | |||
Fair value measurements for producing and non-producing oil and gas properties that were subject to fair value impairment [Abstract] | |||
Net book value at January 1 | 959,000 | 4,906,000 | |
Leasehold additions | 106,000 | 865,000 | |
Advanced royalty payment | 529,000 | 0 | |
In-process wells suspended | 395,000 | 73,000 | |
Property sale | 0 | (877,000) | |
Impairment valuation loss | (1,758,000) | (4,008,000) | |
Net book value at December 31 | 231,000 | 959,000 | $ 4,906,000 |
Wyoming and other acreage [Member] | |||
Sale of used trucks and equipment [Abstract] | |||
Total Non-producing Leasehold Costs | $ 182,000 | 554,000 | |
Other Oil and Gas Property [Member] | |||
Sale of used trucks and equipment [Abstract] | |||
Proceeds from sale of oil and gas properties | 822,000 | ||
Pre-tax gain on sale of oil and gas properties | 747,000 | ||
Onshore Leasehold [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment, useful life | 3 years | ||
Wells Fargo Bank [Member] | |||
Letter of Credit Facility [Line Items] | |||
Line of credit facility, maximum borrowing capacity | $ 60,000,000 | ||
Standby letters of credit | $ 1,000,000 | $ 15,300,000 | |
Current ratio | 1.1 | ||
Commodity Contract [Member] | |||
Fair Value Forward Hydrocarbon Commodity Contracts at gross valuation [Abstract] | |||
Number of contracts held | Contract | 1 | 3 | |
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Current Assets [Member] | |||
Fair Value Forward Hydrocarbon Commodity Contracts at gross valuation [Abstract] | |||
Asset Derivatives | $ 0 | $ 1,332,000 | |
Liability Derivatives | 0 | 0 | |
Less Counterparty Offsets | 0 | (396,000) | |
As Reported Fair Value Contracts | 0 | 936,000 | |
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Other Assets [Member] | |||
Fair Value Forward Hydrocarbon Commodity Contracts at gross valuation [Abstract] | |||
Asset Derivatives | 0 | 0 | |
Liability Derivatives | 0 | 0 | |
Less Counterparty Offsets | 0 | 0 | |
As Reported Fair Value Contracts | 0 | 0 | |
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Current Liabilities [Member] | |||
Fair Value Forward Hydrocarbon Commodity Contracts at gross valuation [Abstract] | |||
Asset Derivatives | 0 | 0 | |
Liability Derivatives | 195,000 | 1,339,000 | |
Less Counterparty Offsets | 0 | (396,000) | |
As Reported Fair Value Contracts | 195,000 | 943,000 | |
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Other Liabilities [Member] | |||
Fair Value Forward Hydrocarbon Commodity Contracts at gross valuation [Abstract] | |||
Asset Derivatives | 0 | 0 | |
Liability Derivatives | 0 | 0 | |
Less Counterparty Offsets | 0 | 0 | |
As Reported Fair Value Contracts | $ 0 | $ 0 | |
Commodity Contract [Member] | January 2016 [Member] | |||
Fair Value Forward Hydrocarbon Commodity Contracts at gross valuation [Abstract] | |||
Volume committed per day under commodity purchase and sale contract (in barrels) | bbl | 65 | ||
Commodity Contract [Member] | February 2016 [Member] | |||
Fair Value Forward Hydrocarbon Commodity Contracts at gross valuation [Abstract] | |||
Volume committed per day under commodity purchase and sale contract (in barrels) | bbl | 65 | ||
Commodity Contract [Member] | March 2016 [Member] | |||
Fair Value Forward Hydrocarbon Commodity Contracts at gross valuation [Abstract] | |||
Volume committed per day under commodity purchase and sale contract (in barrels) | bbl | 65 | ||
Commodity Contract [Member] | Jan 2015 and Feb 2015 [Member] | |||
Fair Value Forward Hydrocarbon Commodity Contracts at gross valuation [Abstract] | |||
Volume committed per day under commodity purchase and sale contract (in barrels) | bbl | 294 | ||
Commodity Contract [Member] | Mar 2015 through Dec 2015 [Member] | |||
Fair Value Forward Hydrocarbon Commodity Contracts at gross valuation [Abstract] | |||
Volume committed per day under commodity purchase and sale contract (in barrels) | bbl | 129 |
Summary of Significant Accoun32
Summary of Significant Accounting Policies, Derivatives by Hedging Relationship and Fair Value Measurements (Details) - USD ($) | 12 Months Ended | ||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | |
Company's asset retirement obligations [Roll Forward] | |||||
Balance on January 1 | $ 2,464,000 | $ 2,564,000 | |||
Liabilities incurred | 39,000 | 111,000 | |||
Accretion of discount | 93,000 | 94,000 | |||
Liabilities settled | (127,000) | (305,000) | |||
Balance on December 31 | 2,469,000 | 2,464,000 | $ 2,564,000 | ||
Escrow cash | $ 75,000 | ||||
Level 1 Quoted Prices [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Net Value | 0 | 0 | 0 | 0 | $ 0 |
Factors impacting the change in the net value of the Company's fair value contracts [Abstract] | |||||
Net Fair Value January 1 | 0 | 0 | |||
Net realized (gains) losses | 0 | 0 | |||
Option deposit | 0 | ||||
Option gain | 0 | ||||
Net unrealized gains (losses) | 0 | 0 | |||
Net Fair Value December 31 | 0 | 0 | 0 | ||
Level 2 Observable [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Net Value | (7,000) | (7,000) | 395,000 | (195,000) | (7,000) |
Factors impacting the change in the net value of the Company's fair value contracts [Abstract] | |||||
Net Fair Value January 1 | (7,000) | 395,000 | |||
Net realized (gains) losses | 7,000 | 220,000 | |||
Option deposit | (714,000) | ||||
Option gain | 99,000 | ||||
Net unrealized gains (losses) | (195,000) | (7,000) | |||
Net Fair Value December 31 | (195,000) | (7,000) | 395,000 | ||
Total Fair Value [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Net Value | (7,000) | 395,000 | 395,000 | (195,000) | (7,000) |
Factors impacting the change in the net value of the Company's fair value contracts [Abstract] | |||||
Net Fair Value January 1 | (7,000) | 395,000 | |||
Net realized (gains) losses | 7,000 | 220,000 | |||
Option deposit | (714,000) | ||||
Option gain | 99,000 | ||||
Net unrealized gains (losses) | (195,000) | (7,000) | |||
Net Fair Value December 31 | (195,000) | (7,000) | 395,000 | ||
Fair Value, Measurements, Recurring [Member] | Level 1 Quoted Prices [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivatives - Current assets | 0 | 0 | |||
Derivatives - Current liabilities | 0 | 0 | |||
Net Value | 0 | 0 | 0 | 0 | |
Factors impacting the change in the net value of the Company's fair value contracts [Abstract] | |||||
Net Fair Value January 1 | 0 | ||||
Net Fair Value December 31 | 0 | 0 | |||
Fair Value, Measurements, Recurring [Member] | Level 2 Observable [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivatives - Current assets | 0 | 1,332,000 | |||
Derivatives - Current liabilities | (195,000) | (1,339,000) | |||
Net Value | (7,000) | (7,000) | (195,000) | (7,000) | |
Factors impacting the change in the net value of the Company's fair value contracts [Abstract] | |||||
Net Fair Value January 1 | (7,000) | ||||
Net Fair Value December 31 | (195,000) | (7,000) | |||
Fair Value, Measurements, Recurring [Member] | Level 3 Unobservable [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivatives - Current assets | 0 | 0 | |||
Derivatives - Current liabilities | 0 | 0 | |||
Net Value | 0 | 0 | 0 | 0 | |
Factors impacting the change in the net value of the Company's fair value contracts [Abstract] | |||||
Net Fair Value January 1 | 0 | ||||
Net Fair Value December 31 | 0 | 0 | |||
Fair Value, Measurements, Recurring [Member] | Counterparty Offsets [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivatives - Current assets | 0 | (396,000) | |||
Derivatives - Current liabilities | 0 | 396,000 | |||
Net Value | 0 | 0 | 0 | 0 | |
Factors impacting the change in the net value of the Company's fair value contracts [Abstract] | |||||
Net Fair Value January 1 | 0 | ||||
Net Fair Value December 31 | 0 | 0 | |||
Fair Value, Measurements, Recurring [Member] | Total Fair Value [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivatives - Current assets | 0 | 936,000 | |||
Derivatives - Current liabilities | (195,000) | (943,000) | |||
Net Value | (195,000) | (7,000) | $ (195,000) | $ (7,000) | |
Factors impacting the change in the net value of the Company's fair value contracts [Abstract] | |||||
Net Fair Value January 1 | (7,000) | ||||
Net Fair Value December 31 | (195,000) | (7,000) | |||
Commodity Contract [Member] | Revenues - Marketing [Member] | Not Designated as Hedging Instrument [Member] | |||||
Earnings (loss) recognized in income [Abstract] | |||||
Gain (Loss) | $ (188,000) | $ 312,000 | $ (193,000) |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Current [Abstract] | |||
Federal | $ (3,883) | $ (8,626) | $ (8,102) |
State | (190) | (1,249) | (892) |
Current income tax (provision) benefit | (4,073) | (9,875) | (8,994) |
Deferred [Abstract] | |||
Federal | 5,011 | 5,878 | (2,682) |
State | (168) | 273 | (478) |
Deferred income tax (provision) benefit | 4,843 | 6,151 | (3,160) |
Income tax (provision) benefit | 770 | (3,724) | (12,154) |
Income tax (provision) benefit, continuing and discontinued operations [Abstract] | |||
From continuing operations | 770 | (3,561) | (12,429) |
From discontinued operations | 0 | (163) | 275 |
Income tax (provision) benefit | 770 | (3,724) | (12,154) |
Reconciliation of taxes computed at the corporate federal income tax rate to the reported income tax (provision) [Abstract] | |||
Statutory federal income tax (provision) benefit | 716 | (3,587) | (11,819) |
State income tax (provision) benefit | (233) | (634) | (891) |
Federal statutory depletion | 144 | 549 | 522 |
Other | 143 | (52) | 34 |
Income tax (provision) benefit | 770 | (3,724) | $ (12,154) |
Current deferred tax asset (liability) [Abstract] | |||
Allowance for doubtful accounts | 0 | 62 | |
Prepaid and other insurance | 0 | (719) | |
Fair value contracts | 0 | (1) | |
Net current deferred tax liability | 0 | (658) | |
Long-term deferred tax asset (liability) [Abstract] | |||
Prepaid and other insurance | (1,243) | 0 | |
Property | (7,408) | (12,673) | |
Uniform capitalization | 704 | 661 | |
Other | (51) | (170) | |
Net long-term deferred tax liability | (7,998) | (12,182) | |
Net deferred tax liability | $ (7,998) | $ (12,840) | |
Federal [Member] | |||
Income Tax Examination [Line Items] | |||
Earliest Open Tax Year | 2,012 | ||
Texas [Member] | |||
Income Tax Examination [Line Items] | |||
Earliest Open Tax Year | 2,011 | ||
Louisiana [Member] | |||
Income Tax Examination [Line Items] | |||
Earliest Open Tax Year | 2,012 | ||
Michigan [Member] | |||
Income Tax Examination [Line Items] | |||
Earliest Open Tax Year | 2,011 |
Concentration of Credit Risk (D
Concentration of Credit Risk (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015USD ($)Customer | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Concentration Risk [Line Items] | |||
Industry practice payment of receivables | 20 days | ||
Percentage of U.S. demand supplied by company | 1.00% | ||
Allowance for doubtful accounts | $ 206 | $ 179 | |
Changes in the allowance for doubtful accounts [Roll Forward] | |||
Balance, beginning of year | 179 | 252 | $ 206 |
Provisions for bad debts | 116 | 50 | 147 |
Less: Write-offs and recoveries | (89) | (123) | (101) |
Balance, end of year | $ 206 | $ 179 | $ 252 |
Customer Concentration Risk [Member] | Minimum [Member] | |||
Concentration Risk [Line Items] | |||
Number of customers | Customer | 3 | ||
Customer Concentration Risk [Member] | Maximum [Member] | |||
Concentration Risk [Line Items] | |||
Number of customers | Customer | 5 | ||
Accounts Receivable [Member] | Product Concentration Risk [Member] | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 90.00% | ||
Accounts Receivable [Member] | Customer One [Member] | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 20.30% | 16.60% | 16.00% |
Accounts Receivable [Member] | Customer Two [Member] | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 16.50% | 16.60% | 15.80% |
Accounts Receivable [Member] | Customer Three [Member] | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 12.70% | 10.40% | 12.70% |
Accounts Receivable [Member] | Customer Four [Member] | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 0.00% | 0.00% | 0.00% |
Revenue [Member] | Customer Concentration Risk [Member] | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 50.00% | ||
Revenue [Member] | Customer One [Member] | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 24.40% | 20.30% | 18.50% |
Revenue [Member] | Customer Two [Member] | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 13.80% | 14.00% | 17.70% |
Revenue [Member] | Customer Three [Member] | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 0.00% | 0.00% | 15.80% |
Revenue [Member] | Customer Four [Member] | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 0.00% | 0.00% | 10.40% |
Employee Benefits (Details)
Employee Benefits (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Employee Benefits [Abstract] | |||
Contributory expenses | $ 768 | $ 691 | $ 674 |
Transactions with Affiliates (D
Transactions with Affiliates (Details) - Affiliated Entities [Member] - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Related Party Transaction [Line Items] | |||
Overhead recoveries | $ 97,000 | $ 151,000 | $ 152,000 |
Affiliate billings to company | 68,000 | 65,000 | 69,000 |
Company billings to affiliate | 35,000 | 42,000 | 99,000 |
Rentals paid to affiliate | $ 618,000 | 607,000 | $ 481,000 |
Total study costs incurred | $ 70,420 |
Commitments and Contingencies37
Commitments and Contingencies (Details) | 12 Months Ended | ||
Dec. 31, 2015USD ($)Lawsuit | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Rental Expenses [Abstract] | |||
Rental expense | $ 11,168,000 | $ 9,755,000 | $ 8,281,000 |
Commitments under long-term non-cancelable operating leases [Abstract] | |||
2,016 | 6,218,000 | ||
2,017 | 4,160,000 | ||
2,018 | 1,697,000 | ||
2,019 | 318,000 | ||
2,020 | 0 | ||
Thereafter | 0 | ||
Total | 12,393,000 | ||
Estimated expenses and liabilities [Abstract] | |||
Estimated expenses and liabilities | 2,086,000 | 2,585,000 | 1,796,000 |
Medical Accrual [Abstract] | |||
Accrued medical claims | 1,107,000 | 1,057,000 | $ 1,129,000 |
Minimum annual individual medical claims for stop loss coverage | 100,000 | ||
Umbrella insurance coverage | 2,000,000 | ||
Minimum aggregate medical claims for umbrella insurance coverage for 2014 | $ 4,500,000 | 4,500,000 | |
Number of suits alleging oil and gas production | Lawsuit | 1 | ||
Total number of lawsuits | Lawsuit | 3 | ||
Accrued future legal costs | $ 500,000 | $ 500,000 |
Guarantees (Details)
Guarantees (Details) $ in Thousands | Dec. 31, 2015USD ($) |
Commodity Purchases [Member] | |
Parental guaranteed obligations [Abstract] | |
Commodity purchases, 2016 | $ 15,855 |
Commodity purchases, 2017 | 0 |
Commodity purchases, 2018 | 0 |
Commodity purchases, 2019 | 0 |
Commodity purchases, Thereafter | 0 |
Commodity purchases, Total | 15,855 |
Letters of Credit [Member] | |
Parental guaranteed obligations [Abstract] | |
Letters of credit, 2016 | 1,000 |
Letters of credit, 2017 | 0 |
Letters of credit, 2018 | 0 |
Letters of credit, 2019 | 0 |
Letters of credit, Thereafter | 0 |
Letters of credit, Total | 1,000 |
Guarantor Obligation [Member] | |
Parental guaranteed obligations [Abstract] | |
Guaranteed obligations, 2016 | 16,855 |
Guaranteed obligations, 2017 | 0 |
Guaranteed obligations, 2018 | 0 |
Guaranteed obligations, 2019 | 0 |
Guaranteed obligations Thereafter | 0 |
Guaranteed obligations, Total | $ 16,855 |
Segment Reporting (Details)
Segment Reporting (Details) - USD ($) | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Activities by segment [Abstract] | ||||||||||||
Revenues | $ 348,255,000 | $ 439,893,000 | $ 600,558,000 | $ 555,573,000 | $ 849,736,000 | $ 1,173,970,000 | $ 1,159,931,000 | $ 949,189,000 | $ 1,944,279,000 | $ 4,132,826,000 | $ 3,945,969,000 | |
Segment Operating Earnings (loss) | 7,580,000 | 18,094,000 | 43,436,000 | |||||||||
Depreciation Depletion and Amortization | 23,717,000 | 24,615,000 | 22,275,000 | |||||||||
Inventory liquidation and valuation losses | 5,357,000 | 14,247,000 | 5,357,000 | 14,247,000 | ||||||||
Segment operating earnings [Abstract] | ||||||||||||
Segment operating earnings | 7,580,000 | 18,094,000 | 43,436,000 | |||||||||
General and administrative expenses | (9,939,000) | (8,613,000) | (9,060,000) | |||||||||
Operating (Loss) Earnings | (2,359,000) | 9,481,000 | 34,376,000 | |||||||||
Interest income | 327,000 | 301,000 | 198,000 | |||||||||
Interest expense | (13,000) | (2,000) | (24,000) | |||||||||
Earnings (loss) from continuing operations before income taxes | (2,045,000) | 9,780,000 | 34,550,000 | |||||||||
Identifiable Assets By Segment [Abstract] | ||||||||||||
Assets | 243,215,000 | 340,814,000 | 243,215,000 | 340,814,000 | ||||||||
Reportable Segments [Member] | ||||||||||||
Activities by segment [Abstract] | ||||||||||||
Revenues | 1,944,279,000 | 4,132,826,000 | 3,945,969,000 | |||||||||
Segment Operating Earnings (loss) | 7,580,000 | 18,094,000 | 43,436,000 | |||||||||
Depreciation Depletion and Amortization | 23,717,000 | 24,615,000 | 22,275,000 | |||||||||
Property and Equipment Additions | 11,074,000 | 30,523,000 | 27,602,000 | |||||||||
Segment operating earnings [Abstract] | ||||||||||||
Segment operating earnings | 7,580,000 | 18,094,000 | 43,436,000 | |||||||||
Identifiable Assets By Segment [Abstract] | ||||||||||||
Assets | 243,215,000 | 340,814,000 | 243,215,000 | 340,814,000 | 448,082,000 | |||||||
Marketing [Member] | ||||||||||||
Activities by segment [Abstract] | ||||||||||||
Inventory liquidation and valuation losses | 5,357,000 | 14,247,000 | 5,357,000 | 14,247,000 | 3,824,000 | |||||||
Marketing [Member] | Reportable Segments [Member] | ||||||||||||
Activities by segment [Abstract] | ||||||||||||
Revenues | 1,875,885,000 | 4,050,497,000 | 3,863,057,000 | |||||||||
Segment Operating Earnings (loss) | [1] | 22,895,000 | 20,854,000 | 40,369,000 | ||||||||
Depreciation Depletion and Amortization | 11,097,000 | 9,626,000 | 7,682,000 | |||||||||
Property and Equipment Additions | 2,126,000 | 13,598,000 | 11,343,000 | |||||||||
Segment operating earnings [Abstract] | ||||||||||||
Segment operating earnings | [1] | 22,895,000 | 20,854,000 | 40,369,000 | ||||||||
Identifiable Assets By Segment [Abstract] | ||||||||||||
Assets | 96,723,000 | 189,332,000 | 96,723,000 | 189,332,000 | 306,693,000 | |||||||
Transportation [Member] | Reportable Segments [Member] | ||||||||||||
Activities by segment [Abstract] | ||||||||||||
Revenues | 63,331,000 | 68,968,000 | 68,783,000 | |||||||||
Segment Operating Earnings (loss) | 3,701,000 | 4,750,000 | 5,180,000 | |||||||||
Depreciation Depletion and Amortization | 7,554,000 | 7,416,000 | 7,099,000 | |||||||||
Property and Equipment Additions | 6,579,000 | 8,994,000 | 3,165,000 | |||||||||
Segment operating earnings [Abstract] | ||||||||||||
Segment operating earnings | 3,701,000 | 4,750,000 | 5,180,000 | |||||||||
Identifiable Assets By Segment [Abstract] | ||||||||||||
Assets | 35,010,000 | 37,643,000 | 35,010,000 | 37,643,000 | 34,406,000 | |||||||
Oil and Gas [Member] | ||||||||||||
Activities by segment [Abstract] | ||||||||||||
Gain on property sale | 2,528,000 | |||||||||||
Property impairments | 12,082,000 | 8,009,000 | 2,630,000 | |||||||||
Oil and Gas [Member] | Reportable Segments [Member] | ||||||||||||
Activities by segment [Abstract] | ||||||||||||
Revenues | 5,063,000 | 13,361,000 | 14,129,000 | |||||||||
Segment Operating Earnings (loss) | [2] | (19,016,000) | (7,510,000) | (2,113,000) | ||||||||
Depreciation Depletion and Amortization | 5,066,000 | 7,573,000 | 7,494,000 | |||||||||
Property and Equipment Additions | 2,369,000 | 7,931,000 | 13,094,000 | |||||||||
Segment operating earnings [Abstract] | ||||||||||||
Segment operating earnings | [2] | (19,016,000) | (7,510,000) | (2,113,000) | ||||||||
Identifiable Assets By Segment [Abstract] | ||||||||||||
Assets | 8,930,000 | 25,888,000 | 8,930,000 | 25,888,000 | 37,093,000 | |||||||
Cash and other [Member] | Reportable Segments [Member] | ||||||||||||
Identifiable Assets By Segment [Abstract] | ||||||||||||
Assets | $ 102,552,000 | $ 87,951,000 | $ 102,552,000 | $ 87,951,000 | $ 69,890,000 | |||||||
[1] | Marketing segment operating earnings included inventory liquidation and valuation losses totaling $5,357,000, $14,247,000 and $3,824,000 for 2015, 2014 and 2013, respectively. | |||||||||||
[2] | Oil and gas segment operating earnings include gains on property sales totaling $2,528,000 during 2014 and property impairments totaling $12,082,000, $8,009,000 and $2,630,000 for 2015, 2014 and 2013, respectively. |
Discontinued Operations (Detail
Discontinued Operations (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Pre-tax earnings from discontinued operation | $ 553,000 | |
Cash proceeds for sale | $ 664,000 | |
Natural Gas Marketing Segment [Member] | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Revenues from discontinued operations | $ 2,377,000 |
Subsequent Event (Details)
Subsequent Event (Details) - Subsequent Event [Member] | Jan. 14, 2016USD ($) |
Subsequent Event [Line Items] | |
Percentage of member interest acquired | 30.00% |
Cash payment for acquisition | $ 2,200,000 |
Quarterly Financial Data (Una42
Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Selected quarterly financial data and earnings per share [Abstract] | |||||||||||
Revenues | $ 348,255 | $ 439,893 | $ 600,558 | $ 555,573 | $ 849,736 | $ 1,173,970 | $ 1,159,931 | $ 949,189 | $ 1,944,279 | $ 4,132,826 | $ 3,945,969 |
Earnings (Loss) from continuing operations | $ (8,404) | $ (308) | $ 4,340 | $ 3,097 | $ (6,974) | $ 3,855 | $ 3,975 | $ 5,363 | $ (1,275) | $ 6,219 | $ 22,121 |
Earnings (Loss) from continuing operations, Per Share (in dollars per share) | $ (1.99) | $ (0.07) | $ 1.03 | $ 0.73 | $ (1.65) | $ 0.92 | $ 0.94 | $ 1.27 | $ (0.30) | $ 1.48 | $ 5.24 |
Net Earnings (Loss), Amount | $ (8,404) | $ (308) | $ 4,340 | $ 3,097 | $ (6,670) | $ 3,855 | $ 3,975 | $ 5,363 | $ (1,275) | $ 6,523 | $ 21,610 |
Net Earnings (Loss), Per Share (in dollars per share) | $ (1.99) | $ (0.07) | $ 1.03 | $ 0.73 | $ (1.58) | $ 0.92 | $ 0.94 | $ 1.27 | $ (0.30) | $ 1.55 | $ 5.12 |
Dividends | $ 928 | $ 928 | $ 928 | $ 928 | $ 927 | $ 928 | $ 928 | $ 928 | $ 3,712 | $ 3,711 | $ 2,783 |
Dividends, Per share (in dollars per share) | $ 0.22 | $ 0.22 | $ 0.22 | $ 0.22 | $ 0.22 | $ 0.22 | $ 0.22 | $ 0.22 | $ 0.88 | $ 0.88 |
Oil and Gas Producing Activit43
Oil and Gas Producing Activities (Unaudited) (Details) bbl in Thousands, MMcf in Thousands, $ in Thousands | 12 Months Ended | |||||
Dec. 31, 2015USD ($)$ / MMcf$ / bblbblMMcf | Dec. 31, 2014USD ($)$ / MMcf$ / bblbblMMcf | Dec. 31, 2013USD ($)$ / MMcf$ / bblbblMMcf | Dec. 31, 2015USD ($)bblMMcf | Dec. 31, 2014USD ($)bblMMcf | Dec. 31, 2013USD ($)bblMMcf | |
Property acquisition costs [Abstract] | ||||||
Unproved | $ 348 | $ 1,144 | $ 1,444 | |||
Proved | 0 | 0 | 0 | |||
Exploration costs [Abstract] | ||||||
Expensed | 1,667 | 5,054 | 1,619 | |||
Capitalized | 0 | 0 | 0 | |||
Development costs | 370 | 1,745 | 10,160 | |||
Total costs incurred | $ 2,385 | 7,943 | 13,223 | |||
Capitalized costs relating to oil and gas producing activities [Abstract] | ||||||
Unproved oil and gas properties | $ 231 | $ 3,104 | ||||
Proved oil and gas properties | 76,886 | 85,557 | ||||
Gross capitalized cost | 77,117 | 88,661 | ||||
Accumulated depreciation, depletion and amortization | (69,116) | (64,682) | ||||
Net capitalized cost | 8,001 | 23,979 | ||||
Components of proved oil and gas reserves [Abstract] | ||||||
Period of average estimated price of proved reserves | 12 months | |||||
Standardized measure of discounted future net cash flows [Abstract] | ||||||
Future gross revenues | 23,040 | 58,885 | $ 64,495 | |||
Future costs [Abstract] | ||||||
Lease operating expenses | (14,524) | (16,421) | (19,207) | |||
Development costs | (103) | (1,068) | (119) | |||
Future net cash flows before income taxes | 8,413 | 41,396 | 45,169 | |||
Discount at 10% per annum | (2,987) | (17,175) | (17,729) | |||
Discounted future net cash flows before income taxes | 5,426 | 24,221 | 27,440 | |||
Future income taxes, net of discount at 10% per annum | (1,899) | (8,477) | (9,604) | |||
Standardized measure of discounted future net cash flows | $ 3,527 | 15,744 | 17,836 | 3,527 | 15,744 | 17,836 |
Effect of income taxes and discounting on the standardized measure of discounted future net cash flows [Abstract] | ||||||
Future net cash flows before income taxes | 8,413 | 41,396 | 45,169 | |||
Future income taxes | (2,945) | (14,489) | (15,809) | |||
Future net cash flows | 5,468 | 26,907 | 29,360 | |||
Discount at 10% per annum | (1,941) | (11,163) | (11,524) | |||
Standardized measure of discounted future net cash flows | 3,527 | 15,744 | 17,836 | $ 3,527 | $ 15,744 | $ 17,836 |
Principal sources of changes in the standardized measure of discounted future net flows [Abstract] | ||||||
Beginning of year | 15,744 | 17,836 | 16,355 | |||
Sale of oil and gas reserves | (54) | (981) | 0 | |||
Net change in prices and production costs | (17,622) | (72) | 9,341 | |||
New field discoveries and extensions, net of future production costs | 292 | 4,456 | 9,767 | |||
Sales of oil and gas produced, net of production costs | 1,038 | (6,590) | (8,373) | |||
Net change due to revisions in quantity estimates | 38 | 2,460 | (3,624) | |||
Accretion of discount | 1,116 | 1,773 | 1,797 | |||
Production rate changes and other | (3,603) | (4,265) | (6,629) | |||
Net change in income taxes | 6,578 | 1,127 | (798) | |||
End of year | 3,527 | 15,744 | 17,836 | |||
Results of operations for oil and gas producing activities [Abstract] | ||||||
Revenues | 5,063 | 13,361 | 14,129 | |||
Costs and expenses [Abstract] | ||||||
Production | (7,022) | (6,771) | (5,756) | |||
Producing property impairment | (10,324) | (4,001) | (1,373) | |||
Exploration | (1,667) | (5,054) | (1,619) | |||
Oil and natural gas property sale gain | 0 | 2,528 | 0 | |||
Depreciation, depletion and amortization | (5,066) | (7,573) | (7,494) | |||
Operating income (loss) before income taxes | (19,016) | (7,510) | (2,113) | |||
Income tax benefit | 6,656 | 2,628 | 739 | |||
Operating income (loss) | $ (12,360) | $ (4,882) | $ (1,374) | |||
Oil [Member] | ||||||
Total proved reserves [Abstract] | ||||||
Beginning of year | bbl | 318 | 368 | 307 | |||
Revisions of previous estimates | bbl | (2) | 6 | (17) | |||
Oil and gas reserves sold | bbl | (3) | (11) | 0 | |||
Extensions, discoveries and other reserve additions | bbl | 13 | 82 | 180 | |||
Production | bbl | (100) | (127) | (102) | |||
End of year | bbl | 226 | 318 | 368 | |||
Components of proved oil and gas reserves [Abstract] | ||||||
Proved developed reserves | bbl | 223 | 299 | 367 | |||
Proved undeveloped reserves | bbl | 3 | 19 | 1 | |||
Total proved reserves | bbl | 318 | 318 | 307 | 226 | 318 | 368 |
Natural Gas [Member] | ||||||
Total proved reserves [Abstract] | ||||||
Beginning of year | MMcf | 5,611 | 6,286 | 8,837 | |||
Revisions of previous estimates | MMcf | 27 | 724 | (1,438) | |||
Oil and gas reserves sold | MMcf | 0 | (558) | (28) | |||
Extensions, discoveries and other reserve additions | MMcf | 86 | 292 | 523 | |||
Production | MMcf | (889) | (1,133) | (1,608) | |||
End of year | MMcf | 4,835 | 5,611 | 6,286 | |||
Components of proved oil and gas reserves [Abstract] | ||||||
Proved developed reserves | MMcf | 4,813 | 5,482 | 6,157 | |||
Proved undeveloped reserves | MMcf | 22 | 129 | 129 | |||
Total proved reserves | MMcf | 5,611 | 6,286 | 6,286 | 4,835 | 5,611 | 6,286 |
Crude Oil [Member] | ||||||
Market Price [Abstract] | ||||||
Average sales prices | $ / bbl | 45.83 | 89.60 | 94.99 | |||
Natural Gas [Member] | ||||||
Market Price [Abstract] | ||||||
Average sales prices | $ / MMcf | 2.62 | 5.42 | 4.69 |