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 (‟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, 2013 were 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 a 1,000 mile radius of Houston, Texas.
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.
Marketable Securities
From time to time, the Company may invest in marketable securities consisting of investment grade corporate bonds traded in liquid markets. Such bonds are held for the purpose of investing in liquid funds and are not generally intended to be retained on a long term basis. Marketable securities are initially recognized at acquisition costs inclusive of transaction costs and are classified as trading securities. In subsequent periods, marketable securities are valued at fair value. Changes in these fair values are recognized as gains or losses in the accompanying statement of operations under the caption ‟Costs and Expenses – Marketing”. Interest on marketable securities is recognized directly in the statement of operations during the period earned.
Allowance for Doubtful Accounts
Accounts receivable result from sales of crude oil, natural gas and trucking services. Marketing business wholesale level sales of crude oil comprise in excess of 90 percent of 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 sales 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.
Inventories
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):
|
|
|
|
|
|
|
|
|
|
|
Cash collateral deposits for commodity purchases
|
|
$
|
13,705
|
|
|
$
|
5,000
|
|
Insurance premiums
|
|
|
2,490
|
|
|
|
1,872
|
|
Rents, license and other
|
|
|
584
|
|
|
|
840
|
|
|
|
$
|
16,779
|
|
|
$
|
7,712
|
|
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, 2013, 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 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 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. For the years ended December 31, 2013, 2012 and 2011, there were $1,373,000, $4,699,000 and $7,105,000 respectively, of impairment provisions on producing oil and gas properties.
Fair value measurements for producing oil and gas properties that were subject to fair value impairment for the years ended December 31, 2013 and 2012 summarized as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
Producing Properties
Subject to Fair
|
|
|
|
|
|
|
|
|
Net book value at January 1
|
|
$
|
13,180
|
|
|
$
|
11,073
|
|
Property additions
|
|
|
5,661
|
|
|
|
13,083
|
|
Depletion taken
|
|
|
(3,727
|
)
|
|
|
(6,371
|
)
|
Impairment valuation loss
|
|
|
(1,373
|
)
|
|
|
(4,699
|
)
|
Net book at December 31
|
|
$
|
13,741
|
|
|
$
|
13,086
|
|
Fair value measurements for producing oil and gas properties are based on Level 3 – Significant Unobservable Inputs – (see “Fair Value Measurements” below).
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 $1,257,000, $856,000 and $7,644,000 were recorded for the years ending December 31, 2013, 2012 and 2011, respectively. Capitalized costs for non-producing oil and gas leasehold interests currently represent approximately five percent of total oil and gas property costs and are categorized as follows
(in thousands):
|
|
December 31,
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South Texas Project acreage
|
|
$
|
4,217
|
|
|
$
|
3,263
|
|
West Texas Project
|
|
|
116
|
|
|
|
180
|
|
Napoleonville Louisiana acreage
|
|
|
162
|
|
|
|
323
|
|
Other acreage areas
|
|
|
411
|
|
|
|
329
|
|
|
|
|
|
|
|
|
|
|
Total Non-producing Leasehold Costs
|
|
$
|
4,906
|
|
|
$
|
4,095
|
|
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 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 the ‟Other Acreage Areas” was as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
Net book value January 1
|
|
$
|
329
|
|
|
$
|
475
|
|
Property additions
|
|
|
304
|
|
|
|
810
|
|
Property sale
|
|
|
-
|
|
|
|
(100
|
)
|
Impairments
|
|
|
(222
|
)
|
|
|
(856
|
)
|
|
|
|
|
|
|
|
|
|
Net book value December 31
|
|
$
|
411
|
|
|
$
|
329
|
|
During 2012, the Company sold half of its interest in certain non-producing Kansas oil and gas properties. Proceeds from the sale totaled $578,000 and the Company recorded a $475,000 pre-tax gain from this sale. Also during 2012, the Company sold its interest in two oil and gas producing property units for total proceeds of $3,049,000. The Company realized a $1,728,000 pre-tax gain from these two sales. In January 2011, the Company completed the sale of its interest in certain producing oil and gas properties located in the on-shore Gulf Coast region of Texas. Proceeds from the 2011 sale totaled $6.2 million and the pre-tax gain totaled $2,708,000. Also during 2011, the Company sold a portion of its interest in certain non-producing oil and gas properties located in West Texas for $329,000 with a $125,000 pre-tax gain from this transaction.
During 2013, 2012 and 2011, the Company sold certain used trucks and equipment from its marketing and transportation segments and recorded pre-tax gains totaling $372,000, $2,482,000 and $1,246,000, respectively.
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):
|
|
|
|
|
|
|
|
|
|
|
Insurance collateral deposits
|
|
$
|
3,718
|
|
|
$
|
3,413
|
|
State collateral deposits
|
|
|
160
|
|
|
|
170
|
|
Materials and supplies
|
|
|
609
|
|
|
|
616
|
|
|
|
$
|
4,487
|
|
|
$
|
4,199
|
|
Revenue Recognition
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 by $1,602,626,000, $1,381,352,000 and $1,812,561,000 for the years ended December 31, 2013, 2012 and 2011, 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.
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 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 totaled $14.6 million and $21.9 million as of December 31, 2013 and 2012, 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 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
Interest paid totaled $24,000, $10,000 and $8,000 during the years ended December 31, 2013, 2012 and 2011, respectively. Income taxes paid during these same periods totaled $9,949,000, $12,650,000, and $5,597,000, respectively. In addition, State and Federal income tax refunds totaled $4,000, $10,000 and $2,743,000 in 2013, 2012 and 2011, respectively. Non-cash investing activities for property and equipment items included in accounts payable as of period end were $1,507,000, $2,419,000 and $4,070,000 as of December 31, 2013, 2012 and 2011, 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. The weighted average number of shares outstanding was 4,217,596 for 2013, 2012 and 2011. There were no potentially dilutive securities 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 that form the foundation for calculating depreciation, depletion and amortization and estimating cash flows to assess impairment triggers and estimated 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 (see Note 2).
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. 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 Consolidated Balance Sheet as of December 31, 2013 as follows
(in thousands):
|
|
Balance Sheet Location and Amount
|
|
|
|
Current
|
|
|
Other
|
|
|
Current
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
- Fair Value Commodity
|
|
|
|
|
|
|
|
|
|
|
|
|
Contracts at Gross Valuation
|
|
$
|
449
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Liability Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- Fair Value 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 of crude oil per day in each of January and February 2014.
Forward month commodity contracts (derivatives) are reflected in the accompanying Consolidated Balance Sheet as of December 31, 2012 as follows
(in thousands):
|
|
Balance Sheet Location and Amount
|
|
|
|
Current
|
|
|
Other
|
|
|
Current
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
- Fair Value Commodity
|
|
|
|
|
|
|
|
|
|
|
|
|
Contracts at Gross Valuation
|
|
$
|
354
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Liability Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- Fair Value Commodity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contracts at Gross Valuation
|
|
|
-
|
|
|
|
-
|
|
|
|
381
|
|
|
|
-
|
|
Less Counterparty Offsets
|
|
|
(270
|
)
|
|
|
-
|
|
|
|
(270
|
)
|
|
|
-
|
|
As Reported Fair Value Contracts
|
|
$
|
84
|
|
|
$
|
-
|
|
|
$
|
111
|
|
|
$
|
-
|
|
As of December 31, 2012, three commodity purchase and sales contracts comprised substantially all of the Company’s derivative valuations. Such contracts encompassed the purchase and sale of approximately 900 barrels of crude oil per day in January 2013 and continuing at 200 barrels per day through June 2013.
The Company only enters into commodity contracts with creditworthy counterparties or obtains collateral support for such activities. As of December 31, 2013 and 2012, 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, 2013, 2012 and 2011 as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues – marketing
|
|
$
|
(193
|
)
|
|
$
|
(1,365
|
)
|
|
$
|
119
|
|
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, 2013, the Company’s fair value assets and liabilities are summarized and categorized as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
Gross Level 1
|
|
|
Gross Level 2
|
|
|
Gross Level 3
|
|
|
Counterparty
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- Current assets
|
|
$
|
-
|
|
|
$
|
449
|
|
|
$
|
-
|
|
|
$
|
(54
|
)
|
|
$
|
395
|
|
- Current liabilities
|
|
|
-
|
|
|
|
(54
|
)
|
|
|
-
|
|
|
|
54
|
|
|
|
-
|
|
Net Value
|
|
$
|
-
|
|
|
$
|
395
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
395
|
|
As of December 31, 2012, the Company’s fair value assets and liabilities are summarized and categorized as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
Gross Level 1
|
|
|
Gross Level 2
|
|
|
Gross Level 3
|
|
|
Counterparty
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- Current assets
|
|
$
|
-
|
|
|
$
|
354
|
|
|
$
|
-
|
|
|
$
|
(270
|
)
|
|
$
|
84
|
|
- Current liabilities
|
|
|
-
|
|
|
|
(381
|
)
|
|
|
-
|
|
|
|
270
|
|
|
|
(111
|
)
|
Net Value
|
|
$
|
-
|
|
|
$
|
(27
|
)
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
(27
|
)
|
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, 2013 and 2012, 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, 2013
(in thousands):
|
|
Level 1
|
|
|
Level 2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Fair Value January 1,
|
|
$
|
-
|
|
|
$
|
(27
|
)
|
|
$
|
(27
|
)
|
- Net realized (gains) losses
|
|
|
-
|
|
|
|
27
|
|
|
|
27
|
|
- Option deposit
|
|
|
-
|
|
|
|
615
|
|
|
|
615
|
|
- Net unrealized gains (losses)
|
|
|
-
|
|
|
|
(220
|
)
|
|
|
(220
|
)
|
Net Fair Value December 31,
|
|
$
|
-
|
|
|
$
|
395
|
|
|
$
|
395
|
|
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, 2012
(in thousands):
|
|
Level 1
|
|
|
Level 2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Fair Value January 1,
|
|
$
|
-
|
|
|
$
|
1,338
|
|
|
$
|
1,338
|
|
- Net realized (gains) losses
|
|
|
-
|
|
|
|
(1,338
|
)
|
|
|
(1,338
|
)
|
- Net unrealized gains (losses)
|
|
|
-
|
|
|
|
(27
|
)
|
|
|
(27
|
)
|
Net Fair Value December 31,
|
|
$
|
-
|
|
|
$
|
(27
|
)
|
|
$
|
(27
|
)
|
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):
|
|
|
|
|
|
|
Balance on January 1,
|
|
$
|
1,886
|
|
|
$
|
1,568
|
|
-Liabilities incurred
|
|
|
431
|
|
|
|
358
|
|
-Accretion of discount
|
|
|
85
|
|
|
|
63
|
|
-Liabilities settled
|
|
|
(138
|
)
|
|
|
(103
|
)
|
-Revisions to estimates
|
|
|
300
|
|
|
|
-
|
|
Balance on December 31,
|
|
$
|
2,564
|
|
|
$
|
1,886
|
|
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 December 2011, the Financial Accounting Standards Board (‟FASB”) issued ASU 2011-11. This update requires additional disclosures about an entity’s right of setoff and related arrangements associated with its financial and derivative instruments. The ASU requires a tabular presentation that reflects the gross, net and setoff amounts associated with such assets and liabilities among other requirements. The Company adopted ASU 2011-11 effective January 1, 2013 and the adoption of ASU 2011-11 did not have a material impact on the Company’s consolidated financial statements, but additional disclosures regarding fair value measurements resulted.
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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
(8,102
|
)
|
|
$
|
(10,282
|
)
|
|
$
|
(4,336
|
)
|
State
|
|
|
(892
|
)
|
|
|
(1,176
|
)
|
|
|
(1,187
|
)
|
|
|
|
(8,994
|
)
|
|
|
(11,458
|
)
|
|
|
(5,523
|
)
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
(2,682
|
)
|
|
|
(4,940
|
)
|
|
|
(7,407
|
)
|
State
|
|
|
(478
|
)
|
|
|
(438
|
)
|
|
|
99
|
|
|
|
|
(3,160
|
)
|
|
|
(5,378
|
)
|
|
|
(7,308
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(12,154
|
)
|
|
$
|
(16,836
|
)
|
|
$
|
(12,831
|
)
|
The following table summarizes the components of the income tax (provision) benefit
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
From continuing operations
|
|
$
|
(12,429
|
)
|
|
$
|
(16,664
|
)
|
|
$
|
(12,717
|
)
|
From discontinued operations
|
|
|
275
|
|
|
|
(172
|
)
|
|
|
(114
|
)
|
|
|
$
|
(12,154
|
)
|
|
$
|
(16,836
|
)
|
|
$
|
(12,831
|
)
|
Taxes computed at the corporate federal income tax rate reconcile to the reported income tax (provision) as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statutory federal income tax (provision) benefit
|
|
$
|
(11,819
|
)
|
|
$
|
(15,619
|
)
|
|
$
|
(12,517
|
)
|
State income tax (provision) benefit
|
|
|
(891
|
)
|
|
|
(1,049
|
)
|
|
|
(707
|
)
|
Federal statutory depletion
|
|
|
522
|
|
|
|
36
|
|
|
|
393
|
|
Other
|
|
|
34
|
|
|
|
(204
|
)
|
|
|
-
|
|
|
|
$
|
(12,154
|
)
|
|
$
|
(16,836
|
)
|
|
$
|
(12,831
|
)
|
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):
|
|
|
|
|
|
|
|
|
|
|
Current deferred tax asset (liability)
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
$
|
424
|
|
|
$
|
581
|
|
Prepaid and other insurance
|
|
|
(855
|
)
|
|
|
(815
|
)
|
Fair value contracts
|
|
|
73
|
|
|
|
(6
|
)
|
Net current deferred liability
|
|
|
(358
|
)
|
|
|
(240
|
)
|
|
|
|
|
|
|
|
|
|
Long-term deferred tax asset (liability)
|
|
|
|
|
|
|
|
|
Property
|
|
|
(18,964
|
)
|
|
|
(15,957
|
)
|
Uniform capitalization
|
|
|
613
|
|
|
|
552
|
|
Other
|
|
|
(283
|
)
|
|
|
(221
|
)
|
Net long-term deferred tax liability
|
|
|
(18,634
|
)
|
|
|
(15,626
|
)
|
Net deferred tax liability
|
|
$
|
(18,992
|
)
|
|
$
|
(15,866
|
)
|
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
|
|
|
|
|
Federal
|
2010
|
Texas
|
2009
|
Louisiana
|
2010
|
Michigan
|
2010
|
(3) Concentration of Credit Risk
Credit risk represents the amount of loss the Company would absorb if its customers failed to perform pursuant to contractual terms. Management of 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 credit risk. 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.
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 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.
The Company had revenues from four customers in 2013 that comprised 18.5 percent, 17.7 percent, 15.8 percent and 10.4 percent of total revenues, respectively. During 2012, three customers comprised 20.2 percent, 17.9 percent and 16.8 percent of total revenues. During 2011, four customers comprised 18.2 percent, 15.4 percent, 13.4 percent and 11.3 percent of total revenues.
The Company had accounts receivable from three customers that comprised 16.0 percent, 15.8 percent and 12.7 percent, respectively of total accounts receivables at December 31, 2013. Three customers comprised 22.1 percent, 21.4 percent and 11.4 percent, respectively, of total accounts receivable as of December 31, 2012. Two customers comprised 24.5 percent and 21.5 percent, respectively, of total accounts receivable at December 31, 2011.
An allowance for doubtful accounts is provided where appropriate and accounts receivable presented herein are net of allowances for doubtful accounts of $252,000 and $206,000 at December 31, 2013 and 2012, respectively.
An analysis of the changes in the allowance for doubtful accounts is presented as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year
|
|
$
|
206
|
|
|
$
|
357
|
|
|
$
|
180
|
|
Provisions for bad debts
|
|
|
147
|
|
|
|
-
|
|
|
|
276
|
|
Less: Write-offs and recoveries
|
|
|
(101
|
)
|
|
|
(151
|
)
|
|
|
(99
|
)
|
Balance, end of year
|
|
$
|
252
|
|
|
$
|
206
|
|
|
$
|
357
|
|
(4) Employee Benefits
The Company maintains a 401(k) savings plan for the benefit of its employees. The Company’s contributory expenses for the plan were $674,000, $645,000 and $597,000 in 2013, 2012 and 2011, respectively. No other pension or retirement plans are maintained by the Company.
(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 the Company’s subsidiary, Adams Resources Exploration Corporation. Mr. Adams and such affiliates participated on terms similar to those afforded other non-affiliated working interest owners. In recent years, such related party transactions generally resulted after the Company first identified oil and gas prospects of interest. Typically the available dollar commitment to participate in such transactions was greater than the amount management was comfortable putting at risk. In such event, the Company first determined the percentage of the transaction it wanted to obtain, which allowed a related party to participate in the investment to the extent there was excess available. In those instances where there was no excess availability there was no related party participation. Similarly, related parties were not required to participate, nor was the Company obligated to offer any such participation to a related or other party. When such related party transactions occurred, they were individually reviewed and approved by the Audit Committee comprised of the independent directors on the Company’s Board of Directors. During 2013 and 2012, the Company’s investment commitments totaled approximately $12 million and $22.7 million, respectively, in those oil and gas projects where a related party was also participating in such investments. As of December 31, 2013 and 2012, the Company owed a combined net total of $38,000 and $42,000, respectively, to these related parties. In connection with the operation of certain oil and gas properties, the Company also charges such related parties for administrative overhead primarily as prescribed by the Council of Petroleum Accountants Society Bulletin 5. Such overhead recoveries totaled $152,000, $152,000 and $145,000 for the years ended December 31, 2013, 2012, and 2011, respectively.
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 secretarial services. For the years ended December 31, 2013, 2012 and 2011, the affiliated entities charged the Company $69,000, $64,000 and $42,000, respectively, of expense reimbursement and the Company charged the affiliates $99,000, $98,000 and $118,000, respectively, for such expense reimbursements. In January 2012, the Company relocated its primary office lease space to a building operated by an affiliated entity. The lease rental rate was determined by an independent appraisal. Rental expense paid to the related party for 2013 and 2012 totaled $481,000 and $442,000, respectively.
(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 has entered into certain lease and terminal access contracts in order to provide tank storage and dock access for its crude oil marketing business. All operating lease commitments qualify for off-balance sheet treatment. Such contracts require certain minimum monthly payments for the term of the contracts. Rental expense for the years ended December 31, 2013, 2012, and 2011 was $8,281,000, $8,110,000 and $7,621,000, respectively. At December 31, 2013, commitments under long-term non-cancelable operating leases and terminal arrangements for the next five years and thereafter are payable as follows: 2014 - $3,138,000; 2015 - $1,931,000; 2016 - $1,910,000; 2017 - $1,690,000; 2018 - $804,000 and $40,000 thereafter.
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 of $1,796,000 and $1,545,000 as of December 31, 2013 and 2012, respectively.
Effective January 1, 2012, the Company began a self-insurance program for managing employee medical claims. On a monthly basis, the Company establishes a liability for expected claims incurred. As claims are paid, the liability is relieved. As of December 31, 2013 and 2012, accrued medical claims totaled $1,129,000 and $506,000, respectively. The Company 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 2013 and 2014.
During 2013 and continuing in 2014, AREC has been noticed 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. The Company is currently named as a defendant in four 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, Edward Conner, et al v. Adams Resources Exploration Corporation dated October 2013 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. 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 this item. As of December 31, 2013, the Company has accrued $200,000 of future legal 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
ARE issues parent guarantees of commitments resulting from the ongoing 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, 2013, parental guaranteed obligations are approximately as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity purchases
|
|
$
|
78,747
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
78,747
|
|
Letters of credit
|
|
|
14,600
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
14,600
|
|
|
|
$
|
93,347
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
93,347
|
|
Presently, neither Adams Resources & Energy, Inc. (‟ARE”) 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 and natural gas 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, 2013-
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketing
|
|
$
|
3,863,057
|
|
|
$
|
40,369
|
|
|
$
|
7,682
|
|
|
$
|
11,343
|
|
Transportation
|
|
|
68,783
|
|
|
|
5,180
|
|
|
|
7,099
|
|
|
|
3,165
|
|
Oil and gas
|
|
|
14,129
|
|
|
|
(2,113
|
)
|
|
|
7,494
|
|
|
|
13,094
|
|
|
|
$
|
3,945,969
|
|
|
$
|
43,436
|
|
|
$
|
22,275
|
|
|
$
|
27,602
|
|
Year ended December 31, 2012-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketing
|
|
$
|
3,292,948
|
|
|
$
|
46,145
|
|
|
$
|
5,945
|
|
|
$
|
12,391
|
|
Transportation
|
|
|
67,183
|
|
|
|
10,253
|
|
|
|
5,921
|
|
|
|
15,538
|
|
Oil and gas
|
|
|
15,954
|
|
|
|
(3,632
|
)
(1)
|
|
|
8,848
|
|
|
|
23,083
|
|
|
|
$
|
3,376,085
|
|
|
$
|
52,766
|
|
|
$
|
20,714
|
|
|
$
|
51,012
|
|
Year ended December 31, 2011-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketing
|
|
$
|
2,961,176
|
|
|
$
|
49,237
|
|
|
$
|
3,724
|
|
|
$
|
13,554
|
|
Transportation
|
|
|
63,501
|
|
|
|
8,521
|
|
|
|
3,912
|
|
|
|
14,118
|
|
Oil and gas
|
|
|
14,060
|
|
|
|
(13,874
|
)
(1)
|
|
|
8,249
|
|
|
|
24,580
|
|
|
|
$
|
3,038,737
|
|
|
$
|
43,884
|
|
|
$
|
15,885
|
|
|
$
|
52,252
|
|
|
__________________________________
|
(1)
|
Oil and gas
segment operating earnings include gains on property sales totaling $2,203,000 and $2,923,000 during 2012 and 2011, 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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating earnings
|
|
$
|
43,436
|
|
|
$
|
52,766
|
|
|
$
|
43,884
|
|
- General and administrative expenses
|
|
|
(9,060
|
)
|
|
|
(8,810
|
)
|
|
|
(8,678
|
)
|
Operating earnings
|
|
|
34,376
|
|
|
|
43,956
|
|
|
|
35,206
|
|
- Interest income
|
|
|
198
|
|
|
|
190
|
|
|
|
237
|
|
- Interest expense
|
|
|
(24
|
)
|
|
|
(10
|
)
|
|
|
(8
|
)
|
Earnings from continuing operations before
|
|
|
|
|
|
|
|
|
|
|
|
|
income taxes and discontinued operations
|
|
$
|
34,550
|
|
|
$
|
44,136
|
|
|
$
|
35,435
|
|
Identifiable assets by industry segment are as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketing
|
|
$
|
306,693
|
|
|
$
|
277,920
|
|
|
$
|
253,817
|
|
Transportation
|
|
|
34,406
|
|
|
|
38,940
|
|
|
|
27,221
|
|
Oil and gas
|
|
|
37,093
|
|
|
|
35,788
|
|
|
|
29,105
|
|
Other
|
|
|
69,890
|
|
|
|
66,853
|
|
|
|
68,697
|
|
|
|
$
|
448,082
|
|
|
$
|
419,501
|
|
|
$
|
378,840
|
|
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
On February 27, 2012, the Company completed the sale of contracts, inventory and certain equipment associated with the refined products segment of its marketing business. Revenues from this segment included in net earnings from discontinued operations totaled $25,717,000 and $169,412,000 for the years ended
D
ecember 31, 2012 and 2011, respectively. This business had experienced marginal results in recent years including an operating loss of $788,000 for the year 2011. The Company received $2 million in cash proceeds plus a cash payment of $1,546,000 for the agreed value of refined product inventories on the date of sale. The net gain recognized upon this sale totaled $1,622,000. The Company conducted an orderly wind-down of the operation during 2012 and 2013 which primarily consisted of collecting outstanding accounts receivable and satisfying all existing obligations. The Company’s fee interest in certain parcels of real estate was retained and the estimated fair value of such properties exceeded the Company’s cost basis in the properties. Therefore, an impairment assessment of long-lived assets was not necessary. The proceeds secured from this transaction exceeded the sum of carrying costs of the assets sold plus severance and other wind-down costs and, as a result, pre-tax earnings from this former segment totaled $398,000 for the year ended December 31, 2012.
Due to inadequate earnings, effective October 31, 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, $4,879,000 and $6,251,000 for the years ended December 31, 2013, 2012 and 2011, respectively. The Company incurred employee severance and other shut-down costs totaling $416,000 as a result of this event. All obligations were satisfied and no further events are anticipated.
(10) Quarterly Financial Data (Unaudited) -
Selected quarterly financial data and earnings per share of the Company are presented below for the years ended December 31, 2013 and 2012
(in thousands, except per share data):
|
|
|
|
|
|
Earnings from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013 -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31
|
|
|
$
|
952,435
|
|
|
$
|
8,073
|
|
|
$
|
1.91
|
|
|
$
|
8,015
|
|
|
$
|
1.90
|
|
|
$
|
-
|
|
|
$
|
-
|
|
June 30
|
|
|
|
965,098
|
|
|
|
6,521
|
|
|
|
1.55
|
|
|
|
6,330
|
|
|
|
1.50
|
|
|
|
928
|
|
|
|
.22
|
|
September 30
|
|
|
|
1,060,340
|
|
|
|
7,238
|
|
|
|
1.72
|
|
|
|
7,156
|
|
|
|
1.70
|
|
|
|
927
|
|
|
|
.22
|
|
December 31
|
|
|
|
968,096
|
|
|
|
289
|
|
|
|
.06
|
|
|
|
109
|
|
|
|
.02
|
|
|
|
928
|
|
|
|
.22
|
|
Total
|
|
|
$
|
3,945,969
|
|
|
$
|
22,121
|
|
|
$
|
5.24
|
|
|
$
|
21,610
|
|
|
$
|
5.12
|
|
|
$
|
2,783
|
|
|
$
|
.66
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012 -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31
|
|
|
$
|
875,905
|
|
|
$
|
5,944
|
|
|
$
|
1.41
|
|
|
$
|
6,575
|
|
|
$
|
1.56
|
|
|
$
|
-
|
|
|
$
|
-
|
|
June 30
|
|
|
|
830,110
|
|
|
|
5,333
|
|
|
|
1.26
|
|
|
|
5,386
|
|
|
|
1.28
|
|
|
|
-
|
|
|
|
-
|
|
September 30
|
|
|
|
794,404
|
|
|
|
8,355
|
|
|
|
1.98
|
|
|
|
8,263
|
|
|
|
1.96
|
|
|
|
-
|
|
|
|
-
|
|
December 31
|
|
|
|
875,666
|
|
|
|
7,840
|
|
|
|
1.86
|
|
|
|
7,567
|
|
|
|
1.79
|
|
|
|
2,615
|
|
|
|
.62
|
|
Total
|
|
|
$
|
3,376,085
|
|
|
$
|
27,472
|
|
|
$
|
6.51
|
|
|
$
|
27,791
|
|
|
$
|
6.59
|
|
|
$
|
2,615
|
|
|
$
|
.62
|
|
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.
(11)
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 incurred within the United States, were as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition costs
|
|
|
|
|
|
|
|
|
|
Unproved
|
|
$
|
1,444
|
|
|
$
|
1,965
|
|
|
$
|
3,591
|
|
Proved
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Exploration costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Expensed
|
|
|
1,619
|
|
|
|
1,151
|
|
|
|
9,166
|
|
Capitalized
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Development costs
|
|
|
10,160
|
|
|
|
20,219
|
|
|
|
12,133
|
|
Total costs incurred
|
|
$
|
13,223
|
|
|
$
|
23,335
|
|
|
$
|
24,890
|
|
The aggregate capitalized costs relative to oil and gas producing activities are as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
Unproved oil and gas properties
|
|
$
|
7,578
|
|
|
$
|
8,349
|
|
Proved oil and gas properties
|
|
|
91,369
|
|
|
|
82,083
|
|
|
|
|
98,947
|
|
|
|
90,432
|
|
Accumulated depreciation, depletion
|
|
|
|
|
|
|
|
|
and amortization
|
|
|
(64,169
|
)
|
|
|
(57,833
|
)
|
Net capitalized cost
|
|
$
|
34,778
|
|
|
$
|
32,599
|
|
Estimated Oil and Natural Gas Reserves -
The following information regarding estimates of the Company’s proved oil and gas reserves, all located in Texas and the south central region of the United States, 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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
Natural
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
|
(
Mcf’s
)
|
|
|
(
Bbls.
)
|
|
|
(
Mcf’s
)
|
|
|
(
Bbls.
)
|
|
|
(
Mcf’s
)
|
|
|
(
Bbls
.)
|
|
Total proved reserves-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
|
8,837
|
|
|
|
307
|
|
|
|
9,661
|
|
|
|
292
|
|
|
|
7,794
|
|
|
|
267
|
|
Revisions of previous estimates
|
|
|
(1,438
|
)
|
|
|
(17
|
)
|
|
|
(507
|
)
|
|
|
29
|
|
|
|
(520
|
)
|
|
|
(24
|
)
|
Oil and gas reserves sold
|
|
|
(28
|
)
|
|
|
-
|
|
|
|
(104
|
)
|
|
|
(54
|
)
|
|
|
(2,148
|
)
|
|
|
(26
|
)
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
other reserve additions
|
|
|
523
|
|
|
|
180
|
|
|
|
2,395
|
|
|
|
138
|
|
|
|
6,430
|
|
|
|
137
|
|
Production
|
|
|
(1,608
|
)
|
|
|
(102
|
)
|
|
|
(2,608
|
)
|
|
|
(98
|
)
|
|
|
(1,895
|
)
|
|
|
(62
|
)
|
End of year
|
|
|
6,286
|
|
|
|
368
|
|
|
|
8,837
|
|
|
|
307
|
|
|
|
9,661
|
|
|
|
292
|
|
The components of proved oil and gas reserves for the three years ended December 31, 2013 is presented below. All reserves are in the United States
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
Natural
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
|
(
Mcf’s
)
|
|
|
(
Bbls.
)
|
|
|
(
Mcf’s
)
|
|
|
(
Bbls.
)
|
|
|
(
Mcf’s
)
|
|
|
(
Bbls
.)
|
|
Proved developed reserves
|
|
|
6,157
|
|
|
|
367
|
|
|
|
8,708
|
|
|
|
306
|
|
|
|
9,433
|
|
|
|
277
|
|
Proved undeveloped reserves
|
|
|
129
|
|
|
|
1
|
|
|
|
129
|
|
|
|
1
|
|
|
|
228
|
|
|
|
15
|
|
Total proved reserves
|
|
|
6,286
|
|
|
|
368
|
|
|
|
8,837
|
|
|
|
307
|
|
|
|
9,661
|
|
|
|
292
|
|
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 the Company’s AREC subsidiary. 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 employs third party petroleum consultant, Ryder Scott Company, to prepare its oil and gas reserve data estimates as of December 31, 2013, 2012 and 2011. 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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future gross revenues
|
|
$
|
64,495
|
|
|
$
|
59,793
|
|
|
$
|
73,626
|
|
Future costs -
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
(19,207
|
)
|
|
|
(16,357
|
)
|
|
|
(19,788
|
)
|
Development costs
|
|
|
(119
|
)
|
|
|
(299
|
)
|
|
|
(2,198
|
)
|
Future net cash flows before income taxes
|
|
|
45,169
|
|
|
|
43,137
|
|
|
|
51,640
|
|
Discount at 10% per annum
|
|
|
(17,729
|
)
|
|
|
(17,976
|
)
|
|
|
(19,439
|
)
|
Discounted future net cash flows
|
|
|
|
|
|
|
|
|
|
|
|
|
before income taxes
|
|
|
27,440
|
|
|
|
25,161
|
|
|
|
32,201
|
|
Future income taxes, net of discount at
|
|
|
|
|
|
|
|
|
|
|
|
|
10% per annum
|
|
|
(9,604
|
)
|
|
|
(8,806
|
)
|
|
|
(11,270
|
)
|
Standardized measure of discounted
|
|
|
|
|
|
|
|
|
|
|
|
|
future net cash flows
|
|
$
|
17,836
|
|
|
$
|
16,355
|
|
|
$
|
20,931
|
|
The reserve estimates provided at December 31, 2013, 2012 and 2011 are based on aggregate prices of $94.99, $93.85 and $95.85 per barrel for crude oil and $4.69, $3.51 and $4.69 per mcf for natural gas, respectively. 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 price reported in the reserve disclosure for natural gas for 2013 includes the value of associated natural gas liquids.
The effect of income taxes and discounting on the standardized measure of discounted future net cash flows is presented as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows before income taxes
|
|
$
|
45,169
|
|
|
$
|
43,137
|
|
|
$
|
51,640
|
|
Future income taxes
|
|
|
(15,809
|
)
|
|
|
(15,098
|
)
|
|
|
(18,074
|
)
|
Future net cash flows
|
|
|
29,360
|
|
|
|
28,039
|
|
|
|
33,566
|
|
Discount at 10% per annum
|
|
|
(11,524
|
)
|
|
|
(11,684
|
)
|
|
|
(12,635
|
)
|
Standardized measure of discounted
|
|
|
|
|
|
|
|
|
|
|
|
|
future net cash flows
|
|
$
|
17,836
|
|
|
$
|
16,355
|
|
|
$
|
20,931
|
|
The principal sources of changes in the standardized measure of discounted future net flows are as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
$
|
16,355
|
|
|
$
|
20,931
|
|
|
$
|
16,672
|
|
Sale of oil and gas reserves
|
|
|
-
|
|
|
|
(3,802
|
)
|
|
|
(7,429
|
)
|
Net change in prices and production costs
|
|
|
9,341
|
|
|
|
(5,313
|
)
|
|
|
791
|
|
New field discoveries and extensions, net of future
|
|
|
|
|
|
|
|
|
|
|
|
|
production costs
|
|
|
9,767
|
|
|
|
9,513
|
|
|
|
18,769
|
|
Sales of oil and gas produced, net of production costs
|
|
|
(8,373
|
)
|
|
|
(8,953
|
)
|
|
|
(7,723
|
)
|
Net change due to revisions in quantity estimates
|
|
|
(3,624
|
)
|
|
|
(940
|
)
|
|
|
(1,739
|
)
|
Accretion of discount
|
|
|
1,797
|
|
|
|
1,944
|
|
|
|
1,678
|
|
Production rate changes and other
|
|
|
(6,629
|
)
|
|
|
511
|
|
|
|
2,204
|
|
Net change in income taxes
|
|
|
(798
|
)
|
|
|
2,464
|
|
|
|
(2,292
|
)
|
End of year
|
|
$
|
17,836
|
|
|
$
|
16,355
|
|
|
$
|
20,931
|
|
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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
14,129
|
|
|
$
|
15,954
|
|
|
$
|
14,060
|
|
Costs and expenses -
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(5,756
|
)
|
|
|
(7,091
|
)
|
|
|
(6,337
|
)
|
Producing property impairment
|
|
|
(1,373
|
)
|
|
|
(4,699
|
)
|
|
|
(7,105
|
)
|
Exploration
|
|
|
(1,619
|
)
|
|
|
(1,151
|
)
|
|
|
(9,166
|
)
|
Oil and natural gas property sale gain
|
|
|
-
|
|
|
|
2,203
|
|
|
|
2,923
|
|
Depreciation, depletion and amortization
|
|
|
(7,494
|
)
|
|
|
(8,848
|
)
|
|
|
(8,249
|
)
|
Operating income (loss) before income taxes
|
|
|
(2,113
|
)
|
|
|
(3,632
|
)
|
|
|
(13,874
|
)
|
Income tax (expense) benefit
|
|
|
739
|
|
|
|
1,271
|
|
|
|
4,854
|
|
Operating income (loss)
|
|
$
|
(1,374
|
)
|
|
$
|
(2,361
|
)
|
|
$
|
(9,020
|
)
|