ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(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 (‟AE”) 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, 2016 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 dry bulk, 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. 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.
Prepayments
The components of prepayments and other are as follows
(in thousands):
|
|
December 31,
|
|
|
|
2016
|
|
|
2015
|
|
Cash collateral deposits for commodity purchases
|
|
$
|
-
|
|
|
$
|
167
|
|
Insurance premiums
|
|
|
1,403
|
|
|
|
1,609
|
|
Rents, license and other
|
|
|
694
|
|
|
|
813
|
|
|
|
$
|
2,097
|
|
|
$
|
2,589
|
|
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, 2016 and 2015, 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. No impairment triggers were identified for the Company’s Marketing or Transportation property and equipment during the years ending December 31, 2016, 2015 or 2014. 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. 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.
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.
Impairment provisions including in oil and gas segment operating losses were as follows
(in thousands):
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Producing property impairments
|
|
$
|
30
|
|
|
$
|
10,324
|
|
|
$
|
4,001
|
|
Non-producing property impairments
|
|
$
|
283
|
|
|
$
|
1,758
|
|
|
$
|
4,008
|
|
|
|
$
|
313
|
|
|
$
|
12,082
|
|
|
$
|
8,009
|
|
Fair value measurements for producing oil and gas properties that were subject to fair value impairment for the years ended December 31, 2016 and 2015 summarize as follows
(in thousands):
|
|
Producing Properties
|
|
|
|
Subject to Fair
|
|
|
|
Value Impairment
|
|
|
|
2016
|
|
|
2015
|
|
Net book value at January 1
|
|
$
|
70
|
|
|
$
|
18,744
|
|
Property additions
|
|
|
2
|
|
|
|
2,117
|
|
Depletion taken
|
|
|
(15
|
)
|
|
|
(4,454
|
)
|
Impairment valuation loss
|
|
|
(30
|
)
|
|
|
(10,324
|
)
|
Net book value at December 31
|
|
$
|
27
|
|
|
$
|
6,083
|
|
Capitalized costs for non-producing oil and gas leasehold interests are categorized as follows
(in thousands):
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
Napoleonville Louisiana acreage
|
|
$
|
-
|
|
|
$
|
49
|
|
South Texas project acreage
|
|
|
-
|
|
|
|
-
|
|
Wyoming and other acreage
|
|
|
-
|
|
|
|
182
|
|
Total Non-producing Leasehold Costs
|
|
$
|
-
|
|
|
$
|
231
|
|
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 on non-producing leasehold were as follows
(in thousands):
|
|
Leasehold Costs
|
|
|
|
2016
|
|
|
2015
|
|
Net book value January 1
|
|
$
|
231
|
|
|
$
|
959
|
|
Leasehold additions
|
|
|
52
|
|
|
|
106
|
|
Advanced royalty payment
|
|
|
-
|
|
|
|
529
|
|
In-process wells suspended
|
|
|
-
|
|
|
|
395
|
|
Property sales
|
|
|
-
|
|
|
|
-
|
|
Impairments valuation loss
|
|
|
(283
|
)
|
|
|
(1,758
|
)
|
Net book value December 31
|
|
$
|
-
|
|
|
$
|
231
|
|
The Company sold certain used trucks and equipment from its marketing and transportation segments and recorded net pre-tax gains as follows
(in thousands):
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Sales of used trucks and equipment
|
|
$
|
1,966
|
|
|
$
|
535
|
|
|
$
|
1,028
|
|
Investments
In December 2015 the Company formed a new wholly owned subsidiary, Adams Resources Medical Management, Inc. (ARMM), and in January 2016 ARMM acquired a 30% member interest in Bencap LLC (Bencap) for a $2.2 million cash payment. Bencap provides medical insurance brokerage and medical claims auditing services to employers utilizing ERISA governed employee benefit plans. The Company has accounted for this investment under the equity method of accounting.
During the third quarter of 2016, the Company completed a review of its equity method investment in Bencap and determined there was an other than temporary impairment. Underlying this decision are the terms of the investment agreement where Bencap has the option to request borrowings up to $1.5 million (on or after December 5, 2016 but before October 31, 2018) that the Company must provide or forfeit its 30% member interest. During the third quarter of 2016, management of the Company determined that it was unlikely to provide additional funding due to Bencap’s lower than projected revenue growth and operating losses since investment inception. As a result, the Company recognized a net loss of $1.4 million from its investment in Bencap as of September 30, 2016. This loss included a pre-tax impairment charge of $1.7 million and pre-tax losses from the equity method investment of $0.5 million. In February 2017, Bencap requested additional funding of approximately $0.5 million and the Company declined the additional funding request.
In April 2016 the Company, through its ARMM subsidiary, acquired an approximate 15% equity interest (less than 3% voting interest) in VestaCare, Inc., a California corporation (“VestaCare”), for a $2.5 million cash payment. VestaCare provides an array of software as a service (“SaaS”) electronic payment technologies to medical providers, payers and patients including VestaCare’s most recent product offering, VestaPay™. VestaPay™ allows medical care providers to structure fully automated and dynamically updating electronic payment plans for their patients. The Company does not currently have any plans to pursue additional medical-related investments.
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,
|
|
|
|
2016
|
|
|
2015
|
|
Insurance collateral deposits
|
|
$
|
5,032
|
|
|
$
|
6,531
|
|
State collateral deposits
|
|
|
143
|
|
|
|
140
|
|
Materials and supplies
|
|
|
354
|
|
|
|
292
|
|
|
|
$
|
5,529
|
|
|
$
|
6,963
|
|
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):
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Revenue gross-up
|
|
$
|
314,270
|
|
|
$
|
480,111
|
|
|
$
|
1,272,034
|
|
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. Stand-by letters of credit issued were as follows
(in thousands):
|
|
As of December 31,
|
|
|
|
2016
|
|
|
2015
|
|
Stand-by letters of credit
|
|
$
|
-
|
|
|
$
|
1,000
|
|
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):
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
Interest paid
|
|
$
|
2
|
|
|
$
|
13
|
|
|
$
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal and state tax paid
|
|
$
|
2,589
|
|
|
$
|
6,197
|
|
|
$
|
8,169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State tax refund
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
18
|
|
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,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment additions
|
|
$
|
679
|
|
|
$
|
1,707
|
|
|
$
|
1,137
|
|
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 2016, 2015 and 2014. 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 Company foregoes the trading designation and the normal purchase and sale exception is made. 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. Derivatives instruments are presented net on the balance sheet where the Company has a legal right of offset. 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, 2016 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
|
|
$
|
378
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Liability Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- Fair Value Commodity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contracts at Gross Valuation
|
|
|
-
|
|
|
|
-
|
|
|
|
330
|
|
|
|
-
|
|
Less Counterparty Offsets
|
|
|
(266
|
)
|
|
|
-
|
|
|
|
(266
|
)
|
|
|
-
|
|
As Reported Fair Value Contracts
|
|
$
|
112
|
|
|
$
|
-
|
|
|
$
|
64
|
|
|
$
|
-
|
|
As of December 31, 2016, two contracts comprised the Company’s derivative valuations. These contracts encompass approximately 65 barrels of diesel fuel per day during January through March 2017 and 145,000 barrels of crude oil during January 2017 through April 2017.
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 encompasses approximately 65 barrels of diesel fuel per day in each of January, February and March 2016.
The Company only enters into commodity contracts with creditworthy counterparties or obtains collateral support for such activities. As of December 31, 2016 and 2015, 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, 2016, 2015 and 2014 as follows
(in thousands):
|
|
Gain (Loss)
|
|
Location
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Revenues – marketing
|
|
$
|
243
|
|
|
$
|
(188
|
)
|
|
$
|
312
|
|
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, 2016, 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
(fair value contracts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- Current assets
|
|
$
|
-
|
|
|
$
|
378
|
|
|
$
|
-
|
|
|
$
|
(266
|
)
|
|
$
|
112
|
|
- Current liabilities
|
|
|
-
|
|
|
|
(330
|
)
|
|
|
-
|
|
|
|
266
|
|
|
|
(64
|
)
|
Net Value
|
|
$
|
-
|
|
|
$
|
48
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
48
|
|
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
(fair value contracts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- Current assets
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
- Current liabilities
|
|
|
-
|
|
|
|
(195
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(195
|
)
|
Net Value
|
|
$
|
-
|
|
|
$
|
(195
|
)
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
(195
|
)
|
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, 2016 and 2015, 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, 2016
(in thousands):
|
|
Level 1
|
|
|
Level 2
|
|
|
|
|
|
|
Quoted Prices
|
|
|
Observable
|
|
|
Total
|
|
Net Fair Value January 1
|
|
$
|
-
|
|
|
$
|
(195
|
)
|
|
$
|
(195
|
)
|
- Net realized (gains) losses
|
|
|
-
|
|
|
|
195
|
|
|
|
195
|
|
- Net unrealized gains (losses)
|
|
|
-
|
|
|
|
48
|
|
|
|
48
|
|
Net Fair Value December 31
|
|
$
|
-
|
|
|
$
|
48
|
|
|
$
|
48
|
|
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
|
)
|
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):
|
|
2016
|
|
|
2015
|
|
Balance on January 1
|
|
$
|
2,469
|
|
|
$
|
2,464
|
|
-Liabilities incurred
|
|
|
162
|
|
|
|
39
|
|
-Accretion of discount
|
|
|
92
|
|
|
|
93
|
|
-Liabilities settled
|
|
|
(394
|
)
|
|
|
(127
|
)
|
Balance on December 31
|
|
$
|
2,329
|
|
|
$
|
2,469
|
|
Recent Accounting Pronouncements
In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which supersedes the revenue recognition requirements in “Revenue Recognition (Topic 605).” Topic 606 is based on the core principle that revenue is 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 to in exchange for those goods or services. Topic 606 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract.
Topic 606 is effective for fiscal years beginning after December 15, 2017, and interim periods within those years, with early adoption permitted in 2017; however we do not plan to adopt the standard early. Entities will have the option to apply the standard using a full retrospective or modified retrospective adoption method.
The Company has not yet selected a transition method. The Company has a team in place to analyze the impact of Update 2014-09, and the related ASU's, across all revenue streams to evaluate the impact of the new standard on revenue contracts. This includes reviewing current accounting policies and practices to identify potential differences that would result from applying the requirements under the new standard
.
Our evaluation of the impact on our Consolidated Financial Statements and related disclosures is ongoing and not complete. The Company is continuing our review of contracts relative to the provisions of Topic 606.
In July 2015, the FASB amended the existing accounting standards for inventory to provide for the measurement of inventory at the lower of cost or ‟net realizable value,” as defined in the standard. The new guidance is effective for the annual period ending after December 15, 2016, and interim periods thereafter, with early adoption permitted. The adoption of this guidance did not have an impact on the Consolidated Financial Statements.
In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” This standard requires, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company expects to adopt this standard in the first quarter of 2019 and is currently evaluating the impact of this standard on our Consolidated Financial Statements and related disclosures. In connection with our assessment work,
The Company has a team in place to analyze the impact of ASU 2016-02
and is continuing a review of our contracts relative to the provisions of the lease standard.
In August 2016, the FASB issued ASU No. 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.” This standard is intended to reduce existing diversity in practice in how certain transactions are presented on the statement of cash flows. The standard is effective for interim and annual reporting periods beginning after December 15, 2017, although early adoption is permitted. The guidance requires application using a retrospective transition method. The Company will adopt ASU No. 2016-15 in the first quarter of 2017 and has determined the amendment will not have a material impact on our Consolidated Financial Statements and related disclosures.
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.
(2) Income Taxes
The following table shows the components of the Company’s income tax (provision) benefit
(in thousands):
|
|
Years ended December 31,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Current:
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
(2,103
|
)
|
|
$
|
(3,883
|
)
|
|
$
|
(8,626
|
)
|
State
|
|
|
(675
|
)
|
|
|
(190
|
)
|
|
|
(1,249
|
)
|
|
|
|
(2,778
|
)
|
|
|
(4,073
|
)
|
|
|
(9,875
|
)
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
777
|
|
|
|
5,011
|
|
|
|
5,878
|
|
State
|
|
|
80
|
|
|
|
(168
|
)
|
|
|
273
|
|
|
|
|
857
|
|
|
|
4,843
|
|
|
|
6,151
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(1,921
|
)
|
|
$
|
770
|
|
|
$
|
(3,724
|
)
|
The following table summarizes the components of the income tax (provision) benefit
(in thousands):
|
|
Years ended December 31,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
From continuing operations
|
|
$
|
(2,691
|
)
|
|
$
|
770
|
|
|
$
|
(3,561
|
)
|
From discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
(163
|
)
|
From equity investments
|
|
|
770
|
|
|
|
-
|
|
|
|
-
|
|
|
|
$
|
(1,921
|
)
|
|
$
|
770
|
|
|
$
|
(3,724
|
)
|
Taxes computed at the corporate federal income tax rate (inclusive of continuing operations, equity investments and discontinued operations) reconcile to the reported income tax (provision) as follows
(in thousands):
|
|
Years ended December 31,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Statutory federal income tax (provision) benefit
|
|
$
|
(1,552
|
)
|
|
$
|
716
|
|
|
$
|
(3,587
|
)
|
State income tax (provision) benefit
|
|
|
(387
|
)
|
|
|
(233
|
)
|
|
|
(634
|
)
|
Federal statutory depletion
|
|
|
62
|
|
|
|
144
|
|
|
|
549
|
|
Other
|
|
|
(44
|
)
|
|
|
143
|
|
|
|
(52
|
)
|
|
|
$
|
(1,921
|
)
|
|
$
|
770
|
|
|
$
|
(3,724
|
)
|
Deferred income taxes reflect the net difference between the financial statement carrying amounts and the underlying income tax basis in such items. The components of the federal deferred tax asset (liability) are as follows
(in thousands):
|
|
Years Ended December 31,
|
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
Long-term deferred tax asset (liability)
|
|
|
|
|
|
|
Prepaid and other insurance
|
|
$
|
(1,058
|
)
|
|
$
|
(1,243
|
)
|
Property
|
|
|
(7,341
|
)
|
|
|
(7,408
|
)
|
Equity method investment
|
|
|
606
|
|
|
|
-
|
|
Uniform capitalization
|
|
|
729
|
|
|
|
704
|
|
Other
|
|
|
(93
|
)
|
|
|
(51
|
)
|
Net long-term deferred tax liability
|
|
|
(7,157
|
)
|
|
|
(7,998
|
)
|
Net deferred tax liability
|
|
$
|
(7,157
|
)
|
|
$
|
(7,998
|
)
|
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
|
2013
|
Texas
|
2012
|
Louisiana
|
2013
|
Michigan
|
2012
|
(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):
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Balance, beginning of year
|
|
$
|
206
|
|
|
$
|
179
|
|
|
$
|
252
|
|
Provisions for bad debts
|
|
|
100
|
|
|
|
116
|
|
|
|
50
|
|
Less: Write-offs and recoveries
|
|
|
(81
|
)
|
|
|
(89
|
)
|
|
|
(123
|
)
|
Balance, end of year
|
|
$
|
225
|
|
|
$
|
206
|
|
|
$
|
179
|
|
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,
|
2016
|
2015
|
2014
|
2016
|
2015
|
2014
|
18.2%
|
24.4%
|
20.3%
|
20.9%
|
20.3%
|
16.6%
|
16.5%
|
13.8%
|
14.0%
|
14.0%
|
16.5%
|
16.6%
|
15.9%
|
-
|
-
|
10.1%
|
12.7%
|
10.4%
|
10.6%
|
-
|
-
|
-
|
-
|
-
|
(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):
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Contributory expenses
|
|
$
|
757
|
|
|
$
|
768
|
|
|
$
|
691
|
|
(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):
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Overhead recoveries
|
|
$
|
32
|
|
|
$
|
97
|
|
|
$
|
151
|
|
Affiliate billings to Company
|
|
$
|
65
|
|
|
$
|
68
|
|
|
$
|
65
|
|
Company billings to affiliate
|
|
$
|
5
|
|
|
$
|
35
|
|
|
$
|
42
|
|
Rentals paid to affiliate
|
|
$
|
628
|
|
|
$
|
618
|
|
|
$
|
607
|
|
Fee paid to Bencap
|
|
$
|
583
|
|
|
$
|
-
|
|
|
$
|
-
|
|
(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,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Rental expense
|
|
$
|
11,314
|
|
|
$
|
11,168
|
|
|
$
|
9,755
|
|
At December 31, 2016, 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):
2017
|
|
|
2018
|
|
|
2019
|
|
|
2020
|
|
|
2021
|
|
|
Thereafter
|
|
|
Total
|
|
$
|
4,768
|
|
|
$
|
2,018
|
|
|
$
|
365
|
|
|
$
|
4
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
7,155
|
|
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,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Estimated expenses and liabilities
|
|
$
|
2,657
|
|
|
$
|
2,086
|
|
|
$
|
2,585
|
|
The Company maintains a self-insurance program for managing employee medical claims. A liability for expected claims incurred but not reported is established on a monthly basis. As claims are paid, the liability is relieved. The Company also maintains third party insurance stop-loss coverage for aggregate medical claims exceeding $4.5 million. Medical accrual amounts are as follows
(in thousands):
|
|
As of December 31,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Accrued medical claims
|
|
$
|
1,411
|
|
|
$
|
1,107
|
|
|
$
|
1,057
|
|
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 to 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. In the LePetit Chateau Deluxe matter, all the larger defendants have settled the case. The plaintiffs in each of these matters are seeking unspecified compensatory and punitive damages. While 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, 2016 and 2015 the Company has accrued $0.5 million 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.
(7) Guarantees
AE issues parent guarantees of commitments associated with the activities of its subsidiary companies. The guarantees generally result from subsidiary commodity purchase obligations, subsidiary operating lease commitments and subsidiary banking transactions. The nature of 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, 2016, parental guaranteed obligations are approximately as follows
(in thousands):
|
|
2017
|
|
|
2018
|
|
|
2019
|
|
|
2020
|
|
|
Thereafter
|
|
|
Total
|
|
Commodity purchases
|
|
$
|
24,210
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
$
|
24,210
|
|
Letters of credit
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
$
|
24,210
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
24,210
|
|
Presently, neither AE nor any of its subsidiaries has any other types of guarantees outstanding that require liability recognition.
(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, 2016-
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketing
|
|
$
|
1,043,775
|
|
|
$
|
17,045
|
|
|
$
|
9,997
|
|
|
$
|
1,321
|
|
Transportation
|
|
|
52,355
|
|
|
|
(48
|
)
|
|
|
7,249
|
|
|
|
6,868
|
|
Oil and gas
|
|
|
3,410
|
|
|
|
(533
|
)
(2)
|
|
|
1,546
|
|
|
|
295
|
|
|
|
$
|
1,099,540
|
|
|
$
|
16,464
|
|
|
$
|
18,792
|
|
|
$
|
8,484
|
|
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
|
|
__________________________________
(1)
Marketing segment operating earnings included inventory valuation losses totaling $5.4 million and $14.3 million for 2015 and 2014, respectively.
(2)
Oil and gas
segment operating earnings include gains on property sales totaling $2.5 million during 2014 and property impairments totaling $12.1 million and $8.0 million for 2015 and 2014, respectively.
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,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Segment operating earnings
|
|
$
|
16,464
|
|
|
$
|
7,580
|
|
|
$
|
18,094
|
|
- General and administrative expenses
|
|
|
(10,410
|
)
|
|
|
(9,939
|
)
|
|
|
(8,613
|
)
|
Operating earnings (loss)
|
|
|
6,054
|
|
|
|
(2,359
|
)
|
|
|
9,481
|
|
- Interest income
|
|
|
582
|
|
|
|
327
|
|
|
|
301
|
|
- Interest expense
|
|
|
(2
|
)
|
|
|
(13
|
)
|
|
|
(2
|
)
|
Earnings (loss) from continuing operations before
|
|
|
|
|
|
|
|
|
|
|
|
|
income taxes and discontinued operations
|
|
$
|
6,634
|
|
|
$
|
(2,045
|
)
|
|
$
|
9,780
|
|
Identifiable assets by industry segment are as follows
(in thousands):
|
|
Years Ended December 31,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Marketing
|
|
$
|
107,257
|
|
|
$
|
96,723
|
|
|
$
|
189,332
|
|
Transportation
|
|
|
32,120
|
|
|
|
35,010
|
|
|
|
37,643
|
|
Oil and gas
|
|
|
7,279
|
|
|
|
8,930
|
|
|
|
25,888
|
|
Cash and other
|
|
|
100,216
|
|
|
|
102,552
|
|
|
|
87,951
|
|
|
|
$
|
246,872
|
|
|
$
|
243,215
|
|
|
$
|
340,814
|
|
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.
(9) Discontinued Operations
In 2014, the Company sold for $0.7 million in cash the warehouse and real estate used by its former petroleum refined products marketing operation to yield a pre-tax gain of $0.6 million with such gain reported in discontinued operations for 2014.
(10) Subsequent Event
During the third quarter of 2016, the Company completed a review of its equity method investment in Bencap and determined there was an other than temporary impairment. Underlying this decision are the terms of the investment agreement where Bencap has the option to request borrowings up to $1.5 million (on or after December 5, 2016 but before October 31, 2018) that the Company must provide or forfeit its 30% member interest. During the third quarter of 2016, management of the Company determined that it was unlikely to provide additional funding due to Bencap’s lower than projected revenue growth and operating losses since investment inception. As a result, the Company recognized a net loss of $1.4 million from its investment in Bencap as of September 30, 2016. This loss included a pre-tax impairment charge of $1.7 million and pre-tax losses from the equity method investment of $0.5 million. In February 2017, Bencap requested additional funding of approximately $0.5 million and the Company declined the additional funding request.
(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, 2016 and 2015
(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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31
|
|
$
|
250,531
|
|
|
$
|
1,554
|
|
|
$
|
.37
|
|
|
$
|
1,430
|
|
|
$
|
.34
|
|
|
$
|
928
|
|
|
$
|
.22
|
|
June 30
|
|
|
293,163
|
|
|
|
3,540
|
|
|
|
.84
|
|
|
|
3,404
|
|
|
|
.81
|
|
|
|
928
|
|
|
|
.22
|
|
September 30
|
|
|
256,877
|
|
|
|
(983
|
)
|
|
|
(.23
|
)
|
|
|
(2,153
|
)
|
|
|
(.51
|
)
|
|
|
928
|
|
|
|
.22
|
|
December 31
|
|
|
298,969
|
|
|
|
(168
|
)
|
|
|
(.04
|
)
|
|
|
(168
|
)
|
|
|
(.04
|
)
|
|
|
927
|
|
|
|
.22
|
|
Total
|
|
$
|
1,099,540
|
|
|
$
|
3,943
|
|
|
$
|
.94
|
|
|
$
|
2,513
|
|
|
$
|
.60
|
|
|
$
|
3,711
|
|
|
$
|
.88
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
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.
(12)
Oil and Gas Producing Activities (Unaudited)
Adams Resources Exploration Corporation (‟AREC”), a subsidiary of AE, is in the exploration and development of domestic oil and natural gas properties primarily in the Permian Basin of West Texas and the Haynesville Shale. AREC’s offices are maintained in Houston and the Company holds an interest in 470 producing wells of which 6 are Company operated.
.
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,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Property acquisition costs
|
|
|
|
|
|
|
|
|
|
Unproved
|
|
$
|
32
|
|
|
$
|
348
|
|
|
$
|
1,144
|
|
Proved
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Exploration costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Expensed
|
|
|
291
|
|
|
|
1,667
|
|
|
|
5,054
|
|
Capitalized
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Development costs
|
|
|
-
|
|
|
|
370
|
|
|
|
1,745
|
|
Total costs incurred
|
|
$
|
323
|
|
|
$
|
2,385
|
|
|
$
|
7,943
|
|
The aggregate capitalized costs relative to oil and gas producing activities are as follows
(in thousands):
|
|
As of December 31,
|
|
|
|
2016
|
|
|
2015
|
|
Unproved oil and gas properties
|
|
$
|
-
|
|
|
$
|
231
|
|
Proved oil and gas properties
|
|
|
62,784
|
|
|
|
76,886
|
|
|
|
|
62,784
|
|
|
|
77,117
|
|
Accumulated depreciation, depletion
|
|
|
|
|
|
|
|
|
and amortization
|
|
|
(56,426
|
)
|
|
|
(69,116
|
)
|
Net capitalized cost
|
|
$
|
6,358
|
|
|
$
|
8,001
|
|
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,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
|
Natural
|
|
|
|
|
|
Natural
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
|
(
Mcf’s
)
|
|
|
(
Bbls.
)
|
|
|
(
Mcf’s
)
|
|
|
(
Bbls.
)
|
|
|
(
Mcf’s
)
|
|
|
(
Bbls
.)
|
|
Total proved reserves-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
|
4,835
|
|
|
|
226
|
|
|
|
5,611
|
|
|
|
318
|
|
|
|
6,286
|
|
|
|
368
|
|
Revisions of previous estimates
|
|
|
65
|
|
|
|
24
|
|
|
|
27
|
|
|
|
(2
|
)
|
|
|
724
|
|
|
|
6
|
|
Oil and gas reserves sold
|
|
|
(175
|
)
|
|
|
(4
|
)
|
|
|
-
|
|
|
|
(3
|
)
|
|
|
(558
|
)
|
|
|
(11
|
)
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
other reserve additions
|
|
|
151
|
|
|
|
18
|
|
|
|
86
|
|
|
|
13
|
|
|
|
292
|
|
|
|
82
|
|
Production
|
|
|
(662
|
)
|
|
|
(77
|
)
|
|
|
(889
|
)
|
|
|
(100
|
)
|
|
|
(1,133
|
)
|
|
|
(127
|
)
|
End of year
|
|
|
4,214
|
|
|
|
187
|
|
|
|
4,835
|
|
|
|
226
|
|
|
|
5,611
|
|
|
|
318
|
|
The components of proved oil and gas reserves for the three years ended December 31, 2016 is presented below. All reserves are in the United States
(in thousands):
|
|
Years Ended December 31,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
|
Natural
|
|
|
|
|
|
Natural
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
|
(
Mcf’s
)
|
|
|
(
Bbls.
)
|
|
|
(
Mcf’s
)
|
|
|
(
Bbls.
)
|
|
|
(
Mcf’s
)
|
|
|
(
Bbls
.)
|
|
Proved developed reserves
|
|
|
4,214
|
|
|
|
187
|
|
|
|
4,813
|
|
|
|
223
|
|
|
|
5,482
|
|
|
|
299
|
|
Proved undeveloped reserves
|
|
|
-
|
|
|
|
-
|
|
|
|
22
|
|
|
|
3
|
|
|
|
129
|
|
|
|
19
|
|
Total proved reserves
|
|
|
4,214
|
|
|
|
187
|
|
|
|
4,835
|
|
|
|
226
|
|
|
|
5,611
|
|
|
|
318
|
|
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, 2016, 2015 and 2014. 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,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Future gross revenues
|
|
$
|
17,938
|
|
|
$
|
23,040
|
|
|
$
|
58,885
|
|
Future costs -
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
(12,421
|
)
|
|
|
(14,524
|
)
|
|
|
(16,421
|
)
|
Development costs
|
|
|
(38
|
)
|
|
|
(103
|
)
|
|
|
(1,068
|
)
|
Future net cash flows before income taxes
|
|
|
5,479
|
|
|
|
8,413
|
|
|
|
41,396
|
|
Discount at 10% per annum
|
|
|
(2,002
|
)
|
|
|
(2,987
|
)
|
|
|
(17,175
|
)
|
Discounted future net cash flows
|
|
|
|
|
|
|
|
|
|
|
|
|
before income taxes
|
|
|
3,477
|
|
|
|
5,426
|
|
|
|
24,221
|
|
Future income taxes, net of discount at
|
|
|
|
|
|
|
|
|
|
|
|
|
10% per annum
|
|
|
(1,217
|
)
|
|
|
(1,899
|
)
|
|
|
(8,477
|
)
|
Standardized measure of discounted
|
|
|
|
|
|
|
|
|
|
|
|
|
future net cash flows
|
|
$
|
2,260
|
|
|
$
|
3,527
|
|
|
$
|
15,744
|
|
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,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Market price
|
|
|
|
|
|
|
|
|
|
Crude oil per barrel
|
|
$
|
38.34
|
|
|
$
|
45.83
|
|
|
$
|
89.60
|
|
Natural gas per thousand cubic feet (mcf)
|
|
$
|
2.56
|
|
|
$
|
2.62
|
|
|
$
|
5.42
|
|
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,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Future net cash flows before income taxes
|
|
$
|
5,479
|
|
|
$
|
8,413
|
|
|
$
|
41,396
|
|
Future income taxes
|
|
|
(1,918
|
)
|
|
|
(2,945
|
)
|
|
|
(14,489
|
)
|
Future net cash flows
|
|
|
3,561
|
|
|
|
5,468
|
|
|
|
26,907
|
|
Discount at 10% per annum
|
|
|
(1,301
|
)
|
|
|
(1,941
|
)
|
|
|
(11,163
|
)
|
Standardized measure of discounted
|
|
|
|
|
|
|
|
|
|
|
|
|
future net cash flows
|
|
$
|
2,260
|
|
|
$
|
3,527
|
|
|
$
|
15,744
|
|
The principal sources of changes in the standardized measure of discounted future net cash flows are as follows
(in thousands):
|
|
Years Ended December 31,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Beginning of year
|
|
$
|
3,527
|
|
|
$
|
15,744
|
|
|
$
|
17,836
|
|
Sale of oil and gas reserves
|
|
|
(350
|
)
|
|
|
(54
|
)
|
|
|
(981
|
)
|
Net change in prices and production costs
|
|
|
(1,391
|
)
|
|
|
(17,622
|
)
|
|
|
(72
|
)
|
New field discoveries and extensions, net of future
|
|
|
|
|
|
|
|
|
|
|
|
|
production costs
|
|
|
275
|
|
|
|
292
|
|
|
|
4,456
|
|
Sales of oil and gas produced, net of production costs
|
|
|
87
|
|
|
|
1,038
|
|
|
|
(6,590
|
)
|
Net change due to revisions in quantity estimates
|
|
|
181
|
|
|
|
38
|
|
|
|
2,460
|
|
Accretion of discount
|
|
|
194
|
|
|
|
1,116
|
|
|
|
1,773
|
|
Production rate changes and other
|
|
|
(945
|
)
|
|
|
(3,603
|
)
|
|
|
(4,265
|
)
|
Net change in income taxes
|
|
|
682
|
|
|
|
6,578
|
|
|
|
1,127
|
|
End of year
|
|
$
|
2,260
|
|
|
$
|
3,527
|
|
|
$
|
15,744
|
|
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,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Revenues
|
|
$
|
3,410
|
|
|
$
|
5,063
|
|
|
$
|
13,361
|
|
Costs and expenses -
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(3,337
|
)
|
|
|
(7,022
|
)
|
|
|
(6,771
|
)
|
Producing property impairment
|
|
|
(30
|
)
|
|
|
(10,324
|
)
|
|
|
(4,001
|
)
|
Exploration
|
|
|
-
|
|
|
|
(1,667
|
)
|
|
|
(5,054
|
)
|
Oil and natural gas property sale gain
|
|
|
-
|
|
|
|
-
|
|
|
|
2,528
|
|
Depreciation, depletion and amortization
|
|
|
(1,546
|
)
|
|
|
(5,066
|
)
|
|
|
(7,573
|
)
|
Operating income (loss) before income taxes
|
|
|
(1,503
|
)
|
|
|
(19,016
|
)
|
|
|
(7,510
|
)
|
Income tax benefit
|
|
|
526
|
|
|
|
6,656
|
|
|
|
2,628
|
|
Operating income (loss)
|
|
$
|
(977
|
)
|
|
$
|
(12,360
|
)
|
|
$
|
(4,882
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|