Note 2 - Summary of Significant Accounting Policies

Nature of Operations and Principles of Consolidation

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 a 1,000 mile radius of Houston, Texas. The accompanying unaudited condensed consolidated financial statements include the accounts of Adams Resources & Energy, Inc., a Delaware corporation, and its wholly owned subsidiaries (the ‟Company”) after elimination of all intercompany accounts and transactions.

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.

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):

	June 30,		December 31,
	2014		2013

Cash collateral deposits for commodity purchases	$	17,038	$	13,705
Insurance premiums		2,911		2,490
Rents, license and other		1,365		584

	$	21,314	$	16,779

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 June 30, 2014, the Company had no unevaluated or suspended exploratory drilling costs.

Depreciation, depletion and amortization of the cost of proved oil and gas properties are calculated using the unit-of-production method. The reserve base 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. 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 are 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. For the six-month periods ended June 30, 2014 and 2013 there were zero and $142,000, respectively of impairment provisions on producing oil and gas properties.

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 and, as such, data inputs are categorized as ‟unobservable” or ‟Level 3” inputs. Importantly, this fair value measure only applies to the write-down of capitalized costs and will never result in an increase to reported earnings. Accordingly, impairment provisions on non-producing properties totaling $405,000 and $100,000 were recorded for the six-month periods ended June 30, 2014 and 2013, respectively. Capitalized costs for non-producing oil and gas leasehold interests currently represent approximately four percent of total oil and gas property costs and are categorized as follows (in thousands):

	June 30,		December 31,
	2014		2013

South Texas Project acreage	$	4,185	$	4,217
West Texas Project acreage		14		116
Napoleonville, Louisiana acreage		48		162
Other acreage areas		557		411

Total Non-producing Leasehold Costs	$	4,804	$	4,906

The South Texas, West Texas and Napoleonville acreage areas have active or scheduled drilling operations underway and holding the underlying acreage is essential to the ongoing exploration effort. The ‟other acreage areas” category consists of smaller onshore interests dispersed over a wide geographical area. Since the Company is generally not the operator of its oil and gas property interest, it does not maintain the underlying detail acreage data and the Company 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 the ‟other acreage areas” was as follows (in thousands):

	Leasehold Costs
	June 30,			December 31,
	2014			2013
Net book value January 1	$	411		$	329
Property additions		183			304
Impairments		(37	)		(222	)

Net book value end of period	$	557		$	411

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. Components of cash deposits and other assets are as follows (in thousands):

	June 30,		December 31,
	2014		2013
Insurance collateral deposits	$	4,432	$	3,718
State collateral deposits		183		160
Materials and supplies		559		609
	$	5,174	$	4,487

Revenue Recognition

Certain commodity purchase and sale contracts utilized by the Company’s marketing business qualify as derivative instruments with certain specifically identified contracts also designated as trading activity. From the time of contract origination, such trading activity contracts are marked-to-market and recorded on a net revenue basis in the accompanying financial statements.

Most crude oil purchase contracts 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 unaudited condensed consolidated financial statements. Reporting such crude oil contracts on a gross revenue basis would increase the Company’s reported revenues by $782,601,000 and $714,489,000 for the six months ended June 30, 2014 and 2013, respectively.

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.

Concentration of Credit Risk

The Company’s largest customers consist of large multinational integrated oil companies and independent 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 or four 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.

Accounts receivable associated with crude oil activities comprise approximately 95 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.

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 that is used to support the Company’s crude oil purchases. This facility is collateralized by the eligible accounts receivable within the segment. Stand-by letters of credit issued totaled $13,100,000 and $14,600,000 as of June 30, 2014 and December 31, 2013, respectively. 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 include the maintenance of a combined 1.1 to 1.0 current ratio and the maintenance of positive net earnings excluding inventory valuation changes, as defined, among other restrictions. The Company is currently in compliance with all such financial covenants.

Statement of Cash Flows

Interest paid totaled zero and $23,000 during the six-month periods ended June 30, 2014 and 2013, respectively, while taxes paid during these same periods totaled $8,253,000 and $7,739,000, respectively. Non-cash investing activities for property and equipment were $846,000 and $1,507,000 as of June 30, 2014 and December 31, 2013, respectively and $2,468,000 and $2,419,000 as of June 30, 2013 and December 31, 2012, respectively. There were no significant non-cash financing activities in any of the periods reported.

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 presented herein. The weighted average number of shares outstanding was 4,217,596 for 2014 and 2013. There were no potentially dilutive securities during those periods.

Share-Based Payments

During the periods presented herein, the Company had neither 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 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 assets and liabilities and their respective tax basis.

Use of Derivative Instruments

The Company’s marketing segment is involved in the purchase and sale of crude oil. The Company seeks to profit by procuring the commodity as it is produced and then delivering the material to the end users or the intermediate use marketplace. As typical for the industry, such transactions are made pursuant to the terms of forward month commodity purchase and/or sale contracts. Certain 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. The accounting methodology utilized by the Company for its commodity contracts is further discussed below under the caption ‟Fair Value Measurements”.

None of the Company’s derivative instruments have been designated as hedging instruments and the estimated fair value of forward month commodity contracts (derivatives) is reflected in the accompanying Unaudited Condensed Consolidated Balance Sheet as of June 30, 2014 as follows (in thousands):

	Balance Sheet Location and Amount
	Current		Other		Current		Other
	Assets		Assets		Liabilities		Liabilities
Asset Derivatives
- Fair Value Forward Hydrocarbon Commodity
Contracts at Gross Valuation	$	176	$	-	$	-	$	-
Liability Derivatives
- Fair Value Forward Hydrocarbon Commodity
Contracts at Gross Valuation		-		-		112		-
Less Counterparty Offsets		-		-		-		-

As Reported Fair Value Contracts	$	176	$	-	$	112	$	-

As of June 30, 2014, three commodity purchase and sale contracts comprised the Company’s derivative valuations. These contracts encompass approximately 433 barrels per day of crude oil in each of July and August 2014 plus 258 barrels per day during September 2014 through February 2015 and 129 barrels per day in March 2015.

Forward month commodity contracts (derivatives) are reflected in the accompanying Unaudited Condensed Consolidated Balance Sheet as of December 31, 2013 as follows (in thousands):

	Balance Sheet Location and Amount
	Current			Other		Current			Other
	Assets			Assets		Liabilities			Liabilities
Asset Derivatives
- Fair Value Forward Hydrocarbon Commodity
Contracts at Gross Valuation	$	449		$	-	$	-		$	-
Liability Derivatives
- Fair Value Forward Hydrocarbon Commodity
Contracts at Gross Valuation		-			-		54			-
Less Counterparty Offsets		(54	)		-		(54	)		-

As Reported Fair Value Contracts	$	395		$	-	$	-		$	-

As of December 31, 2013, one 100,000 barrel crude oil commodity put option and one commodity purchase and sale contract comprised the Company’s derivative valuations. The purchase and sale contract encompasses approximately 175 barrels per day of crude oil in each of January and February 2014.

The Company only enters into commodity contracts with credit worthy counterparties or obtains collateral support for such activities. As of June 30, 2014 and December 31, 2013, the Company was not holding nor has 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 Unaudited Condensed Consolidated Statement of Operations for the six months ended June 30, 2014 and 2013 as follows (in thousands):

	Earnings (Loss)					Earnings (Loss)
	Six Months Ended					Three Months Ended
	June 30,					June 30,
	2014		2013			2014			2013

Revenues – Marketing	$	383	$	(1	)	$	(15	)	$	(151	)

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 its 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 current 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 valuation 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 June 30, 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	$	-	$	176		$	-	$	-	$	176
- Current liabilities		-		(112	)		-		-		(112	)
Net Value	$	-	$	64		$	-	$	-	$	64

As of December 31, 2013, 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	$	-	$	449		$	-	$	(54	)	$	395
- Current liabilities		-		(54	)		-		54			-
Net Value	$	-	$	395		$	-	$	-		$	395

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 any 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 June 30, 2014 and December 31, 2013, credit valuation adjustments were not significant to the overall valuation of the Company’s fair value contracts. As a result, applicable fair value assets and liabilities are included in their entirety in the fair value hierarchy.

Recent Accounting Pronouncement

In April 2014, the Financial Accounting Standards Board (‟FASB”) issued updated guidance that changes the criteria for reporting discontinued operations including enhanced disclosure requirements. Under the new guidance, only activities representing a strategic shift in operations will be presented as discontinued operations. Such strategic shifts should have a major effect on the organization’s operations and financial results. The new guidance is effective for the first quarter of 2015 and the Company does not expect the adoption to have a material effect on the consolidated financial statements.

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 January 1, 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. The impact of these amendments on the consolidated financial statements and the transition alternatives are currently being evaluated.

Management believes the impact of 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.