ADAMS RESOURCES & ENERGY, INC. - Quarter Report: 2006 September (Form 10-Q)

Adams Resources & Eenrgy, Inc. 10-Q 9-30-2006

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-Q

(Mark One)

x	Quarterly report pursuant to Section 13 or 15 (d) of the Securities Exchange Act of 1934

For the quarterly period ended September 30, 2006

o	Transition report pursuant to Section 13 or 15 (d) of the Securities Exchange Act of 1934

For the transition period from ______________to

Commission File Number 1-7908

ADAMS RESOURCES & ENERGY, INC.

(Exact name of Registrant as specified in its charter)

Delaware		74-1753147
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

4400 Post Oak Pkwy Ste 2700 , Houston, Texas 77027

(Address of principal executive office & Zip Code)

Registrant's telephone number, including area code (713) 881-3600

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES x NO o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 126-2 of the Exchange Act. (Check one)

Large accelerated filer o Accelerated filer o Non-accelerated filer x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES o NO x

A total of 4,217,596 shares of Common Stock were outstanding at November 7, 2006.

PART 1 - FINANCIAL INFORMATION

Item 1. Financial Statements

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	Nine Months Ended						Three Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
REVENUES:
Marketing	$	1,647,062		$	1,654,585		$	604,977		$	618,395
Transportation		48,277			41,765			16,180			13,867
Oil and gas		12,687			10,495			3,841			4,745
		1,708,026			1,706,845			624,998			637,007
COSTS AND EXPENSES:
Marketing		1,636,839			1,641,614			602,757			612,170
Transportation		40,438			35,401			13,719			11,814
Oil and gas		3,761			3,882			1,403			2,272
General and administrative		6,230			6,494			2,110			1,959
Depreciation, depletion and amortization		7,177			5,113			2,741			1,723
		1,694,445			1,692,504			622,730			629,938

Operating earnings		13,581			14,341			2,268			7,069
Other income (expense):
Interest income		487			116			238			57
Interest expense		(112	)		(80	)		(40	)		(28	)
Earnings from continuing operations
before income taxes		13,956			14,377			2,466			7,098

Income tax provision		4,597			4,622			789			2,102

Earnings from continuing operations		9,359			9,755			1,677			4,996
Income from discontinued operations, net of tax
provision of zero, $143, zero and $155, respectively		-			279			-			301
Net earnings	$	9,359		$	10,034		$	1,677		$	5,297

EARNINGS PER SHARE:
From continuing operations	$	2.22		$	2.31		$	.40		$	1.19
From discontinued operation		-			.07			-			.07
Basic and diluted net earnings
per common share	$	2.22		$	2.38		$	.40		$	1.26

DIVIDENDS PER COMMON SHARE	$	-		$	-		$	-		$	-

The accompanying notes are an integral part of these financial statements.

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands)

	September 30,			December 31,
	2006			2005
ASSETS

Current assets:
Cash and cash equivalents	$	22,312		$	18,817
Accounts receivable, net of allowance for doubtful
accounts of $670 and $608, respectively		184,485			217,727
Inventories		8,863			11,692
Risk management receivables		9,408			13,324
Income tax receivables		2,293			1,304
Prepayments		3,612			7,586

Total current assets		230,973			270,450

Property and equipment		109,355			98,861
Less - accumulated depreciation,
depletion and amortization		(65,860	)		(58,965	)
		43,495			39,896
Other assets:
Risk management assets		15			47
Other assets		2,913			2,269
	$	277,396		$	312,662

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	178,279		$	213,668
Risk management payables		7,997			11,542
Accrued and other liabilities		6,759			4,790
Current deferred income taxes		13			1,129
Total current liabilities		193,048			231,129

Long-term debt		3,000			11,475

Other liabilities:
Asset retirement obligations		1,112			1,058
Deferred income taxes and other		5,221			3,296
Risk management liabilities		-			48
		202,381			247,006
Commitments and contingencies (Note 6)

Shareholders’ equity:
Preferred stock - $1.00 par value, 960,000 shares
authorized, none outstanding		-			-
Common stock - $.10 par value, 7,500,000 shares
authorized, 4,217,596 shares outstanding		422			422
Contributed capital		11,693			11,693
Retained earnings		62,900			53,541
Total shareholders’ equity		75,015			65,656
	$	277,396		$	312,662

The accompanying notes are an integral part of these financial statements.

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Nine Months Ended
	September 30,
	2006			2005
CASH PROVIDED BY OPERATIONS:
Earnings from continuing operations	$	9,359		$	9,755
Adjustments to reconcile net earnings to net cash
provided by (used in) operating activities -
Depreciation, depletion and amortization		7,177			5,113
Gains on property sales		(46	)		(1,044	)
Impairment on non-producing oil and gas properties		420			313
Other, net		(116	)		(151	)
Decrease (increase) in accounts receivable		33,242			(43,852	)
Decrease (increase) in inventories		2,829			(2,127	)
Risk management activities		355			17
Decrease (increase) in tax receivable		(989	)		-
Decrease (increase) in prepayments		3,974			4,778
Increase (decrease) in accounts payable		(35,150	)		39,474
Increase (decrease) in accrued liabilities		1,969			(539	)
Deferred income taxes		750			85

Net cash provided by continuing operations		23,774			11,979
Net cash provided by discontinued operations		-			180

Net cash provided by operating activities		23,774			12,159

INVESTING ACTIVITIES:
Property and equipment additions		(11,334	)		(8,415	)
Insurance deposits		(530	)		(817	)
Proceeds from property sales		60			1,191

Net cash used in continuing operations		(11,804	)		(8,041	)
Proceeds from sale of discontinued property		-			550

Net cash used in investing activities		(11,804	)		(7,491	)

FINANCING ACTIVITIES:
Net repayments under credit agreements		(8,475	)		-

Net cash used in financing activities		(8,475	)		-

Increase in cash and cash equivalents		3,495			4,668

Cash at beginning of period		18,817			19,942

Cash at end of period	$	22,312		$	24,610

Supplemental disclosure of cash flow information:

Interest paid during the period	$	112		$	64

Income taxes paid during the period	$	4,842		$	4,031

The accompanying notes are an integral part of these financial statements.

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS

Note 1 - Basis of Presentation

The accompanying condensed consolidated financial statements are unaudited but, in the opinion of the Company's management, include all adjustments (consisting of normal recurring accruals) necessary for the fair presentation of its financial position at September 30, 2006 and December 31, 2005, its results of operations and its cash flows for the nine months ended September 30, 2006 and 2005. Certain information and note disclosures normally included in annual financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to Securities and Exchange Commission rules and regulations. Although the Company believes the disclosures made are adequate to make the information presented not misleading, it is suggested that these condensed consolidated financial statements be read in conjunction with the financial statements, and the notes thereto, included in the Company's latest annual report on Form 10-K for the year ended December 31, 2005. The interim statement of operations is not necessarily indicative of results to be expected for a full year.

Note 2 - Summary of Significant Accounting Policies

Principles of Consolidation

The accompanying 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 significant intercompany accounts and transactions.

Nature of Operations

The Company is engaged in the business of crude oil, natural gas and petroleum products marketing, as well as 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 30 days or less.

Inventories

Crude oil and petroleum product inventories are carried at the lower of cost or market. Petroleum products inventory includes gasoline, lubricating oils and other petroleum products purchased for resale and valued at cost determined on the first-in, first-out basis, while crude oil inventory is valued at average cost. Components of inventory are as follows (in thousands):

	September 30,		December 31,
	2006		2005

Crude oil	$	6,766	$	9,924
Petroleum products		2,097		1,768

	$	8,863	$	11,692

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 ("DD&A") 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 capitalized costs of drilling the well are charged to expense. Costs incurred to drill and complete development wells, including dry holes, are capitalized. As of September 30, 2006, the Company had no unevaluated or suspended exploratory drilling costs.

Producing oil and gas leases, equipment and intangible drilling costs are depleted or amortized over the estimated recoverable reserves using the units-of-production method. Other property and equipment is depreciated using the straight-line method over the estimated average useful lives of three to twenty years for marketing, three to fifteen years for transportation and ten to twenty years for all others.

The Company is required to periodically review long-lived assets for impairment whenever there is evidence that the carrying value of such assets may not be recoverable. This consists of comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. Proved oil and gas properties are reviewed for impairment on a field-by-field basis. Any impairment recognized is permanent and may not be restored. In addition, management evaluates the carrying value of non-producing properties and may deem them impaired for lack of drilling activity. Such evaluations are made on a quarterly basis. Accordingly, a $420,000 and a $313,000 impairment provision on non-producing properties was recorded in the nine-month periods ended September 30, 2006 and 2005, respectively. In addition, during the first nine months of 2006, a $520,000 impairment provision on producing oil and gas properties was recorded and included in DD&A as a result of relatively high costs incurred on certain properties relative to their oil and gas reserve additions.

Other Assets

Other assets primarily consist of cash deposits associated with the Company’s business activities. The Company has established certain deposits to support its participation in its liability insurance program and such deposits totaled $1,347,000 as of September 30, 2006. In addition, the Company maintains certain deposits to support the collection and remittance of state crude oil severance taxes. Such deposits totaled $1,008,000 as of September 30, 2006.

Revenue Recognition

Commodity purchases and sales associated with the Company’s natural gas marketing activities qualify as derivative instruments under Statement of Financial Accounting Standards (“SFAS”) No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”). Therefore, natural gas purchases and sales are recorded on a net revenue basis in the accompanying financial statements in accordance with Emerging Issues Task Force (“EITF”) 02-13 “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities”. In contrast, a significant portion of crude oil purchases and sales qualify, and have been designated as, normal purchases and sales. Therefore, such crude oil purchases and sales are recorded on a gross revenue basis in the accompanying condensed consolidated financial statements. Those purchases and sales of crude oil that do not qualify as “normal purchases and sales” are recorded on a net revenue basis in the accompanying condensed consolidated financial statements. For “normal purchase and sale” activities, the Company’s customers are invoiced monthly based on contractually agreed upon terms and revenue is recognized in the month in which the physical product is delivered to the customer. Where required, the Company recognizes fair value or mark-to-market gains and losses related to its natural gas and crude oil trading activities. A detailed discussion of the Company’s risk management activities is included later in this footnote.

Substantially all of the Company’s petroleum products marketing activity qualify as a “normal purchase and sale” and revenue is recognized in the period when the customer physically takes possession and title to the product upon delivery at their facility. The Company recognizes fair value or mark to market gains and losses on refined product marketing activities that do not qualify as “normal purchases and sales”.

Transportation 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.

Included in marketing segment activities is the gross proceeds and costs associated with certain crude oil buy/sell arrangements. Crude oil buy/sell arrangements result from a single contract or concurrent contracts with a single counterparty to provide for similar quantities of crude oil to be bought and sold at two different locations. Such contracts may be entered into for a variety of reasons, including to effect the transportation of the commodity, to minimize credit exposure, and to meet the competitive demands of the customer. In September 2005, the EITF of the Financial Accounting Standards Board (“FASB”) reached consensus in the issue of accounting for buy/sell arrangements as part of its EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” (“Issue 04-13”). As part of Issue 04-13, the EITF is requiring that all buy/sell arrangements be reflected on a net basis, such that the purchase and sale are netted and shown as either a net purchase or a net sale in the income statement. This requirement is effective for new arrangements, and modifications or renewals of existing arrangements, entered into after March 31, 2006. However, the Company adopted Issue 04-13 effective January 1, 2006. Prior period amounts for marketing revenues and marketing costs and expenses in the accompanying condensed consolidated statements of operations were not restated to reflect the requirements of Issue 04-13. Such buy/sell amounts totaled approximately $532,402,000 and $193,149,000 for marketing revenues and costs in the nine month and six month periods ended September 30, 2005, respectively.

Earnings Per Share

The Company computes and presents earnings per share in accordance with SFAS No. 128, “Earnings Per Share”, which requires the presentation of basic earnings per share and diluted earnings per share for potentially dilutive securities. 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 the nine-month periods ended September 30, 2006 and 2005. There were no potentially dilutive securities during those periods in 2006 and 2005.

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 condensed consolidated financial statements include the accounting for depreciation, depletion and amortization, oil and gas property impairments, the provision for bad debts, income taxes, contingencies and price risk management activities.

Price Risk Management Activities

SFAS No. 133, as amended by SFAS No. 137 and No. 138, establishes accounting and reporting standards that require every derivative instrument (including certain derivative instruments embedded in other contracts) to be recorded on the balance sheet as either an asset or liability measured at its fair value, unless the derivative qualifies and has been designated as a normal purchase or sale. 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 under SFAS No. 133 during any current reporting periods.

The Company’s trading and non-trading transactions give rise to market risk, which represents the potential loss that may result from a change in the market value of a particular commitment. The Company closely monitors and manages its exposure to market risk to ensure compliance with the Company’s risk management policies. Such policies are regularly assessed to ensure their appropriateness given management’s objectives, strategies and current market conditions.

The Company’s forward crude oil contracts are designated as normal purchases and sales. Natural gas forward contracts and energy trading contracts on crude oil and natural gas are recorded at fair value, depending on management’s assessments of the numerous accounting standards and positions that comply with generally accepted accounting principles. The undiscounted fair value of such contracts is reflected on the Company’s balance sheet as risk management assets and liabilities. The revaluation of such contracts is recognized in the Company’s results of operations. Current market price quotes from actively traded liquid markets are used in all cases to determine the contracts’ fair value. Risk management assets and liabilities are classified as short-term or long-term depending on contract terms. The estimated future net cash inflow based on market prices as of September 30, 2006 is $1,426,000, all of which will be received during the remainder of 2006 through December 2007. The estimated future cash inflow approximates the net fair value recorded in the Company’s risk management assets and liabilities.

The following table illustrates the factors impacting the change in the net value of the Company’s risk management assets and liabilities for the nine-month period ended September 30, 2006 and 2005 (in thousands):

	2006			2005
Net fair value on January 1,	$	1,781		$	630
Activity during the period
-Cash paid (received) from settled contracts		(1,979	)		(890	)
-Net realized gain from prior years’ contracts		360			308
-Net unrealized gain from prior years’ contracts		-			5
-Net unrealized (loss) from prior years’ contracts		(83	)		-
-Net unrealized gain from current year contracts		1,347			403
Net fair value on September 30,	$	1,426		$	456

Asset Retirement Obligations

SFAS No. 143 “Accounting for Asset Retirement Obligations” established an accounting model for accounting and reporting obligations associated with retirement of tangible long-lived assets and associated retirement costs. SFAS No. 143 requires that the fair value of a liability for an asset's retirement obligation be recorded in the period in which it is 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 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 recording of the estimated fair value of the Company’s asset retirement obligations is presented as follows (in thousands):

	2006			2005

Balance on January 1,	$	1,058		$	723
-Liabilities incurred		22			23
-Accretion of discount		46			57
-Liabilities settled		(14	)		(97	)
-Revisions to estimates		-			-
Balance on September 30,	$	1,112		$	706

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 on the accompanying balance sheet.

In March 2005, the FASB issued Interpretation No. (“FIN”) 47. FIN 47 clarifies that an entity must record a liability for a “conditional” asset retirement obligation if the fair value can be reasonably estimated. The adoption of FIN 47 had no impact on the Company’s financial statements.

New Accounting Pronouncements

In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment”, which established accounting standards for all transactions in which an entity exchanges its equity instruments for goods and services. SFAS No. 123(R) focuses primarily on accounting for such transactions with employees. As of September 30, 2006, the Company had no stock-based employee compensation plans, nor any other share-based payment arrangements.

In November 2004, the FASB issued SFAS No. 151, “Inventory Costs”. This statement clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material (spoilage). SFAS No. 151 requires that these items be charged to expense regardless of whether they meet the “so abnormal” criterion outlined in Accounting Research Bulletin 43. This statement was effective for inventory costs incurred during fiscal years beginning after September 15, 2005. The adoption of this statement did not have any material effect on the Company’s financial position, results of operations or cash flows.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections”. This statement establishes new standards on the accounting for and reporting of changes in accounting principles and error corrections. SFAS No. 154 requires retrospective application to the financial statements of prior periods for all such changes, unless it is impracticable to do so. SFAS No. 154 was effective for the Company in the first quarter of 2006.

In July 2006, the FASB issued FIN No. 48, “Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109.” FIN 48 addresses the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN 48 prescribes specific criteria for the financial statement recognition and measurement of the tax effects of a position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition of previously recognized tax benefits, classification of tax liabilities on the balance sheet, recording interest and penalties on tax underpayments, accounting in interim periods, and disclosure requirements. FIN 48 is effective for fiscal periods beginning after December 15, 2006. The Company is currently assessing the impact, if any, that the adoption of FIN 48 will have on its financial statements.

Note 3 - Discontinued Operations

Effective September 30, 2005, the Company sold its ownership in its offshore Gulf of Mexico crude oil gathering pipeline. The sale was completed to eliminate abandonment obligations and because the Company was no longer purchasing crude oil in the affected region. The operating results for the pipeline for the nine months and third quarter of 2005 have been reflected in the accompanying unaudited condensed consolidated statement of operations as income from discontinued operations. As of September 30, 2005, the Company had no assets or liabilities associated with this former operation.

Note 4 - Segment Reporting

The Company is primarily engaged in the business of marketing crude oil, natural gas and petroleum products; 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):

- Nine Month Comparison

			Segment		Depreciation		Property and
			Operating		Depletion and		Equipment
	Revenues		Earnings		Amortization		Additions
Period Ended September 30, 2006
Marketing
- Crude Oil	$	1,498,007	$	3,568	$	656	$	1,324
- Natural gas		9,632		4,340		44		326
- Refined products		139,423		1,325		290		1,000
Marketing Total		1,647,062		9,233		990		2,650
Transportation		48,277		4,472		3,367		1,186
Oil and gas		12,687		6,106		2,820		7,498
	$	1,708,026	$	19,811	$	7,177	$	11,334
Period Ended September 30, 2005
Marketing
- Crude Oil	$	1,532,346	$	8,543	$	557	$	71
- Natural gas		6,527		3,352		43		12
- Refined products		115,712		124		352		161
Marketing Total		1,654,585		12,019		952		244
Transportation		41,765		4,225		2,139		3,836
Oil and gas		10,495		4,591		2,022		4,335
	$	1,706,845	$	20,835	$	5,113	$	8,415

- Three Month Comparison

	Revenues		Segment Operating Earnings (Loss)			Depreciation Depletion and Amortization		Property and Equipment Additions
Period Ended September 30, 2006
Marketing
- Crude Oil	$	550,879	$	(475	)	$	217	$	70
- Natural gas		4,087		1,918			15		106
- Refined products		50,011		447			98		98
Marketing Total		604,977		1,890			330		274
Transportation		16,180		1,327			1,134		217
Oil and gas		3,841		1,161			1,277		2,908
	$	624,998	$	4,378		$	2,741	$	3,399
Period Ended September 30, 2005
Marketing
- Crude Oil	$	569,336	$	3,555		$	185	$	14
- Natural gas		3,278		2,238			14		-
- Refined products		45,781		121			112		108
Marketing Total		618,395		5,914			311		122
Transportation		13,867		1,231			822		1,415
Oil and gas		4,745		1,883			590		715
	$	637,007	$	9,028		$	1,723	$	2,252

Identifiable assets by industry segment are as follows (in thousands):

	September 30,		December 31,
	2006		2005
Marketing
- Crude oil	$	130,292	$	145,097
- Natural gas		49,703		75,741
- Refined products		18,552		19,471
Marketing Total		198,547		240,309
Transportation		25,576		28,412
Oil and gas		24,520		20,780
Other		28,753		23,161
	$	277,396	$	312,662

Intersegment sales are insignificant. Other identifiable assets are primarily corporate cash, accounts receivable, and properties not identified with any specific segment of the Company’s business. All sales by the Company occurred in the United States.

Segment operating earnings reflect revenues net of operating costs and depreciation, depletion and amortization. Segment earnings reconcile to earnings from continuing operations before income taxes as follows (in thousands):

	Nine months ended						Three months ended
	September 30,						September 30,
	2006			2005			2006			2005
Segment operating earnings	$	19,811		$	20,835		$	4,378		$	9,028
- General and administrative		(6,230	)		(6,494	)		(2,110	)		(1,959	)
Operating earnings		13,581			14,341			2,268			7,069
- Interest income		487			116			238			57
- Interest expense		(112	)		(80	)		(40	)		(28	)
Earnings from continuing operations
Before income taxes	$	13,956		$	14,377		$	2,466		$	7,098

Note 5 - Transactions with Affiliates

Mr. K. S. “Bud” Adams, Jr., Chairman and Chief Executive Officer, and certain of his family limited partnerships and affiliates have participated as working interest owners with the Company’s subsidiary, Adams Resources Exploration Corporation. Mr. Adams and such affiliates participate on terms no better than those afforded other non-affiliated working interest owners. In recent years, such related party transactions generally result after the Company has first identified oil and gas prospects of interest. Typically the available dollar commitment to participate in such transactions is greater than the amount management is comfortable putting at risk. In such event, the Company first determines the percentage of the transaction it wants to obtain, which allows a related party to participate in the investment to the extent there is excess available. In those instances where there was no excess availability, there has been no related party participation. Similarly, related parties are not required to participate, nor is the Company obligated to offer any such participation to a related or other party. When such related party transactions occur, they are individually reviewed and approved by a committee of independent directors on the Company’s Board of Directors. As of September 30, 2006, the Company owed a combined net total of $116,576 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 (“COPAS”) Bulletin 5. Such overhead recoveries totaled $88,737 during the first nine months of 2006.

David B. Hurst, Secretary of the Company, is a partner in the law firm of Chaffin & Hurst. The Company has been represented by Chaffin & Hurst since 1974 and plans to use the services of that firm in the future. Chaffin & Hurst currently leases office space from the Company. Transactions with Chaffin & Hurst are on the same terms as those prevailing at the time for comparable transactions with unrelated entities.

The Company also enters into certain transactions in the normal course of business with other affiliated entities. These transactions with affiliated companies are on the same terms as those prevailing at the time for comparable transactions with unrelated entities.

Note 6 - Commitments and Contingencies

In March 2004, a suit styled Le Petit Chateau De Luxe, et. al. vs Great Southern Oil & Gas Co., et. al. was filed in the Civil District Court for Orleans Parish, Louisiana against the Company and its subsidiary, Adams Resources Exploration Corporation, among other defendants. The suit alleges that certain property in Acadia Parish, Louisiana was environmentally contaminated by oil and gas exploration and production activities during the 1970s and 1980s. An alleged amount of damage has not been specified. Management believes the Company has consistently conducted its oil and gas exploration and production activities in accordance with all environmental rules and regulations in effect at the time of operation. Management notified its insurance carrier about this claim, and thus far the insurance carrier has declined to offer coverage. The Company is litigating this matter with its insurance carrier. In any event, management does not believe the outcome of this matter will have a material adverse effect on the Company’s financial position or results of operations.

From time to time as incident to its operations, the Company becomes involved in various lawsuits and/or disputes. Primarily as an operator of an extensive trucking fleet, the Company may be a party to motor vehicle accidents, worker compensation claims or other items of general liability as would be typical for the industry. Except as disclosed herein, 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 could potentially represent a material adverse effect on the Company’s financial position or results of operations.

Note 7 - Guarantees

Pursuant to arranging operating lease financing for truck tractors and tank trailers, individual subsidiaries of the Company may guarantee the lessor a minimum residual sales value upon the expiration of a lease and sale of the underlying equipment. Aggregate guaranteed residual values for tractors and trailers under operating leases as of September 30, 2006 are as follows (in thousands):

		2006			2007			2008			2009			2010			Thereafter			Total
Lease residual values		$	-		$	-		$	304		$	1,475		$	217		$	469		$	2,465

In connection with certain contracts for the purchase and resale of branded motor fuels, the Company has received certain price discounts from its suppliers toward the purchase of gasoline and diesel fuel. Such discounts have been passed through to the Company’s customers as an incentive to offset a portion of the costs associated with offering branded motor fuels for sale to the general public. Under the terms of the supply contracts, the Company and its customers are not obligated to return the price discounts, provided the gasoline service station offering such product for sale remains as a branded station for periods ranging from three to ten years. The Company has a number of customers and stations operating under such arrangements and the Company’s customers are contractually obligated to remain a branded dealer for the required periods of time. Should the Company’s customers seek to void such contracts, the Company would be obligated to return a portion of such discounts received to its suppliers. As of September 30, 2006, the maximum amount of such potential obligation is approximately $1,381,000. Management of the Company believes its customers will adhere to their branding obligations and no such refunds will result.

Presently, the Company and its subsidiaries have no other types of guarantees outstanding that in the future would require liability recognition under the provisions of FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”.

Adams Resources & Energy, Inc. frequently issues parent guarantees of commitments resulting from the ongoing activities of its subsidiary companies. The guarantees generally result from subsidiary commodity purchase obligation, subsidiary lease commitments and subsidiary bank debt. The nature of such guarantees 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 accompanying condensed consolidated financial statements. 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 September 30, 2006, the amount of parental guaranteed obligations are as follows (in thousands):

	2006		2007		2008		2009		2010		Thereafter		Total
Bank debt	$	-	$	375	$	1,500	$	1,125	$	-	$	-	$	3,000
Operating leases		1,035		4,060		3,861		1,539		548		290		11,332
Lease residual values		-		-		304		1,475		217		469		2,465
Commodity purchases		30,570		-		-		-		-		-		30,570
Letters of credit		45,857		-		-		-		-		-		45,857
	$	77,462	$	4,435	$	5,665	$	4,139	$	765	$	759	$	93,225

Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Results of Operations

Marketing

Marketing segment revenues, operating earnings and depreciation are presented as follows (in thousands):

	Nine Months Ended				Three Months Ended
	September 30,				September 30,
	2006		2005		2006		2005
Revenues	$	1,647,062	$	1,654,585	$	604,977	$	618,395

Operating earnings	$	9,233	$	12,019	$	1,890	$	5,914

Depreciation	$	990	$	952	$	330	$	311

Marketing segment revenues result from sales of crude oil, natural gas and refined products such as gasoline and diesel. Required reporting for certain sales transactions is on a gross revenue basis as title passes to the customer, while other sales transactions are reported on a net revenue basis (i.e. the commodity acquisition cost is netted against gross sales value). Components of marketing segment revenues are as follows (in thousands):

	Nine Months Ended				Three Months Ended
	September 30,				September 30,
	2006		2005		2006		2005

Crude oil sales, net of proceeds from buy/sell arrangements	$	1,498,007	$	999,944	$	550,879	$	376,187
Crude oil sales proceeds from buy/sell arrangements		-		532,402		-		193,149
Natural gas sales		9,632		6,527		4,087		3,278
Refined product sales		139,423		115,712		50,011		45,781

Total Reported Marketing Revenues	$	1,647,062	$	1,654,585	$	604,977	$	618,395

Prior to January 1, 2006, proceeds from transactions involving crude oil buy/sell arrangements were reported on a gross revenue basis. Beginning this year, such buy/sell transactions are reported on a net revenue basis. The table above shows comparative revenues. This 2006 required accounting change for the presentation of revenue transactions has no impact on net earnings or reported earnings from operations.

Crude oil sales, net of proceeds from buy/sell arrangements, increased by 50 percent to $1,503,658,000 for the comparative current nine month period. The revenue increase was due, in part to a 23 percent increase in average crude oil prices as shown in the table below. Also contributing to the revenue increase was an increase in crude oil sale volumes at major trade locations in order to support the Company’s wellhead level crude oil business. During 2006, future month crude oil prices have tended to exceed current or “spot” month prices. In order to retain its supplier base, the Company has increasingly offered to purchase wellhead volumes based on future month’s crude oil pricing scenarios. This pricing strategy has necessitated increasing crude oil volumes at trade locations in order to profitably respond to this marketing need. Crude oil variations for the three month periods are consistent with this trend.

For natural gas transactions, sales are presented on a net revenue basis. The current period revenue increase to $9,632,000 reflects improved gross margins, consistent with the analysis for operating earnings presented below. The refined product sales increase to $139,423,000 for the current period reflects higher commodity prices consistent with the trend for crude oil.

Supplemental volume and price information is as follows:

	Nine Months Ended				Three Months Ended
	September 30,				September 30,
	2006		2005		2006		2005
Field Level Purchase Volumes - Per day ⁽¹⁾
Crude oil - barrels		62,950		67,600		57,621		63,000
Natural gas - mmbtu’s		342,400		299,000		356,100		269,000

Average Purchase Price
Crude oil - per barrel	$	64.52	$	52.21	$	66.77	$	59.72
Natural Gas - per mmbtu’s	$	6.70	$	7.01	$	6.14	$	8.53

_____________________________

⁽¹⁾ Reflects the volume purchased from third parties at the oil and gas field level.

The components of marketing segment operating earnings (loss) are as follows (in thousands):

	Nine Months Ended				Three Months Ended
	September 30,				September 30,
	2006		2005		2006			2005

Crude Oil	$	3,568	$	8,543	$	(475	)	$	3,555
Natural Gas		4,340		3,352		1,918			2,238
Refined Products		1,325		124		447			121
	$	9,233	$	12,019	$	1,890		$	5,914

Reduced crude oil operating earnings for 2006 resulted from a change in the trend line for crude oil prices. During the first nine months of 2005, crude oil prices generally increased from the $43 per barrel range in January 2005 to the $62 per barrel range in September 2005. This trend enabled the Company to liquidate relatively lower priced inventories into a higher priced market generating $3.7 million in gains for the first nine months of 2005, including a $1.4 million gain during the third quarter of 2005. Crude oil prices which had trended up during most of 2006 fell back in September and October to the $58 per barrel range. As a result, during the third quarter of 2006, the Company experienced a $1.5 million inventory liquidation and valuation loss with a full nine month net inventory valuation loss of $125,000. Included in the third quarter of 2006 inventory valuation loss was approximately $575,000 attributable to a lower of cost or market write-down as the market price for crude oil fell below the Company’s cost basis. As of September 30, 2006, the Company held crude oil inventories totaling 116,297 barrels at an average price of $58.17 per barrel. Also contributing to the comparative earnings reduction was a $1,080,000 reduction in reported costs during 2005 attributable to cash collected on certain previously disputed and fully reserved items. Such items did not recur in 2006.

The Company has reinitiated its prior practice of speculative trading of forward crude oil positions. From 1998 through 2001, the Company had previously engaged in the trading of forward crude oil contracts as a complement to its overall crude oil acquisition business. Financial constraints beginning in 2002 caused the Company to cease its speculative trading activity at that time. However, current market conditions are favorable toward such efforts and the Company re-hired its former personnel to perform this function. The Company has a written statement of policies and procedures to govern these activities. During the first nine months and third quarter of 2006, such speculative crude oil trading activity produced an operating margin of approximately $997,000 and an operating loss of $1,000 which is included in crude oil sales and costs, respectively.

Operating earnings from natural gas improved for the first nine months of 2006 but declined for the comparative third quarter of 2006. The earnings variation is attributable to fluctuating unit margins offered by the marketplace during the respective periods. Operating earnings from motor fuels and other refined product sales consistently improved in 2006 as a result of improved per unit margins.

Transportation

Transportation segment revenues, earnings and depreciation are as follows (in thousands):

	Nine Months Ended							Three Months Ended
	September 30,							September 30,
	2006		2005		Increase			2006		2005		Increase

Revenues	$	48,277	$	41,765		16	%	$	16,180	$	13,867		17	%

Operating earnings	$	4,472	$	4,225		6	%	$	1,327	$	1,231		8	%

Depreciation	$	3,367	$	2,139		57	%	$	1,134	$	822		38	%

Transportation segment revenues improved by 16 percent to $48,277,000 for the first nine months of 2006 due to improved customer demand and higher freight rates. Operating earnings did not keep pace however, due to disproportionate increases in operating costs associated with an expanded fleet, and escalating driver wages and fuel costs. By comparison, fuel costs increased by 26 percent for the comparative first nine months to $9,057,000, while depreciation increased by 57 percent to $3,367,000. Comparative quarterly results were consistent with the nine-month variations.

Oil and Gas

Oil and gas segment revenues and operating earnings are primarily a function of crude oil and natural gas prices and volumes. Comparative amounts for revenues, operating earnings and depreciation and depletion are as follows (in thousands):

	Nine Months Ended							Three Months Ended
	September 30,							September 30,				Increase
	2006		2005		Increase			2006		2005		(Decrease)
Revenues	$	12,687	$	10,495		21	%	$	3,841	$	4,745		(19	%)

Operating earnings	$	6,106	$	4,591		33	%	$	1,161	$	1,883		(38	%)

Depreciation and depletion	$	2,820	$	2,022		39	%	$	1,277	$	590		116	%

Oil and gas segment revenues and operating earnings improved for the nine months ended September 30, 2006 as a result of improved volumes and prices as shown in the table below coupled with reduced exploration expense during 2006. Exploration expense totaled $1,099,000 and $2,247,000 for the first nine months of 2006 and 2005, respectively. Partially offsetting the higher exploration expense in 2005 was a first quarter 2005 gain on the sale of certain oil and gas properties totaling $601,000 that was reported as a net reduction in costs. Such gain did not recur in 2006.

For the comparative third quarter of 2006, operating earnings were reduced due to normal production declines and because of reduced natural gas prices as shown in the table below. Exploration expenses totaled $453,000 for the third quarter of 2006 compared to $1,431,000 for the third quarter of 2005. This cost reduction was partially offset by a third quarter 2006 impairment provision totaling $352,000 on producing oil and gas properties as a result of the decline in natural gas prices.

Production volumes and price information is as follows:

	Nine Months Ended				Three Months Ended
	September 30,				September 30,
	2006		2005		2006		2005
Crude Oil
Volume - barrels		56,650		51,300		17,080		19,700
Average price per barrel	$	66.01	$	53.09	$	69.45	$	59.99

Natural gas
Volume - mcf		1,175,300		1,048,000		379,750		432,000
Average price per mcf	$	7.61		7.41	$	6.99	$	8.23

During the first nine months of 2006, the Company participated in the drilling of twenty six wells. Eighteen of the wells were successful, four wells are completing, with two development dry holes and two wells currently in process. In addition, five of the six wells that were in process at year-end 2005 have been brought on production in 2006 with the remaining well testing as productive but awaiting facilities hook up. Participation in the drilling of approximately 12 wells is planned for the remainder of 2006 on the Company’s prospect acreage in Alabama, Louisiana and Texas.

In the Southern UK North Sea a prospect package has been offered to prospective partners. Regrettably, the potential prospect reserve were regarded as too small and the Company was unsuccessful in finding a partner. The Block will be relinquished effective December 4, 2006. No additional expenses will be incurred as a result of relinquishing this prospect acreage.

- Income tax

The provision for income taxes is based on Federal and State tax rates and variations are consistent with taxable income in the respective accounting periods. During the second quarter of 2006, the State of Texas changed its regulations governing corporate income tax. As a result of this change, the Company revised its estimate of the future impact of the reversal of certain items for state taxation. As a result, during the second quarter of 2006, the Company’s income tax provision was reduced by $118,000 relative to taxes as would otherwise have been provided.

- Discontinued operations

- Outlook

The Company has recently experienced two areas of concern. The first is declining commodity prices for crude oil and natural gas, although natural gas has experienced some recent recovery. The second trend is some reduced demand for the Company’s chemical based trucking services, reflective of a slowing United States economy. Because of these factors, fourth quarter 2006 results are expected to more align with the third quarter rather than with results for the first half of 2006.

Liquidity and Capital Resources

During the first nine months of 2006, net cash provided by operating activities totaled $23,774,000 versus $12,159,000 provided by operations during the first nine months of 2005. Management generally balances the cash flow requirements of the Company’s investment activity with available cash generated from operations. Over time, cash utilized for property and equipment additions, tracks with earnings from continuing operations plus the non-cash provision for depreciation, depletion and amortization. Presently, management intends to restrict investment decisions to available cash flow. Significant, if any, additions to debt are not anticipated. A summary of this relationship follows (in thousands):

	Nine Months Ended
	September 30,
	2006			2005
Earnings from continuing operations	$	9,359		$	9,755
Depreciation, depletion and amortization		7,177			5,113
Property and equipment additions		(11,334	)		(8,415	)
Repayments under credit agreements		(8,475	)		-

Cash available for (sourced from) other activities	$	(3,273	)	$	6,453

Capital expenditures during the first nine months of 2006 included $2,650,000 for marketing equipment additions, $1,186,000 for primarily trailer purchases within the transportation segment and $7,498,000 in property additions associated with oil and gas exploration and production activities. For the remainder of 2006, the Company anticipates expending approximately $3 million on oil and gas exploration and development projects to be funded from operating cash flow and available working capital. Included in projected expenditures for oil and gas projects is approximately $500,000 to be incurred and expensed for geological and seismic study.

- Banking Relationships

The Company’s primary bank loan agreement with Bank of America provides for two separate lines of credit with interest at the bank’s prime rate minus ¼ of 1 percent. The working capital loan provides for borrowings up to $10 million based on 80 percent of eligible accounts receivable and 50 percent of eligible inventories. Available capacity under the line is calculated monthly and as of September 30, 2006 was established at $10 million with $3 million of such amount outstanding at September 30, 2006. The oil and gas production loan provides for flexible borrowings subject to a borrowing base established semi-annually by the bank. The borrowing base is established at $10 million as of September 30, 2006 with no amounts outstanding at September 30, 2006. The line of credit loans are scheduled to expire on October 31, 2007, with the then present balance outstanding converting to a term loan payable in eight equal quarterly installments.

The Bank of America revolving loan agreement, among other things, places certain restrictions with respect to additional borrowings and the purchase or sale of assets, as well as requiring the Company to comply with certain financial covenants, including maintaining a 1.0 to 1.0 ratio of consolidated current assets to consolidated current liabilities, maintaining a 3.0 to 1.0 ratio of pre-tax net income to interest expense, and consolidated net worth in excess of $51,439,000. Should the Company’s net worth fall below this threshold, the Company may be restricted from payment of additional cash dividends on the Company’s common stock. The Company was in compliance with these restrictions as of September 30, 2006.

The Company’s Gulfmark Energy, Inc. subsidiary maintains a separate banking relationship with BNP Paribas in order to support its crude oil purchasing activities. In addition to providing up to approximately $40 million in letters of credit, the facility also finances up to $6 million of crude oil inventory and certain accounts receivable associated with crude oil sales. Such financing is provided on a demand note basis with interest at the bank’s prime rate plus one percent. As of September 30, 2006, the Company had $6 million of eligible borrowing capacity under this facility and no working capital advances outstanding. Letters of credit outstanding under this facility totaled approximately $40.7 million as of September 30, 2006. BNP Paribas has the right to discontinue the issuance of letters of credit under this facility without prior notification to the Company.

The Company’s Adams Resources Marketing subsidiary also maintains a separate banking relationship with BNP Paribas in order to support its natural gas purchasing activities. In addition to providing up to $25 million in letters of credit, the facility finances up to $4 million of general working capital needs on a demand note basis. Such financing is provided on a demand note basis with interest at the bank’s prime rate plus one percent. No working capital advances were outstanding under this facility as of September 30, 2006. Letters of credit outstanding under this facility totaled $5 million as of September 30, 2006. Under this facility, BNP Paribas has the right to discontinue the issuance of letters of credit under this facility without prior notification to the Company.

Critical Accounting Policies and Use of Estimates

- Fair Value Accounting

As an integral part of its marketing operation, the Company enters into certain forward commodity contracts that are required to be recorded at fair value in accordance with Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” and related accounting pronouncements. Management believes this required accounting, known as mark-to-market accounting, creates variations in reported earnings and the reported earnings trend. Under mark-to-market accounting, significant levels of earnings are recognized in the period of contract initiation rather than the period when the service is provided and title passes from supplier to customer. As it affects the Company’s operation, management believes mark-to-market accounting impacts reported earnings and the presentation of financial condition in three important ways:

Gross margins, derived from certain aspects of the Company’s ongoing business, are front-ended into the period in which contracts are executed. Meanwhile, personnel and other costs associated with servicing accounts as well as substantially all risks associated with the execution of contracts are expensed as incurred during the period of physical product flow and title passage.

Mark-to-market earnings are calculated based on stated contract volumes. A significant risk associated with the Company’s business is the conversion of stated contract or planned volumes into actual physical commodity movement volumes without a loss of margin. Again the planned profit from such commodity contracts is bunched and front-ended into one period while the risk of loss associated with the difference between actual versus planned production or usage volumes falls in a subsequent period.

3.	Cash flows, by their nature, match physical movements and passage of title. Mark-to-market accounting, on the other hand, creates a divergence between reported earnings and cash flows. Management believes this complicates the picture of stated financial conditions and liquidity.

The Company attempts to mitigate the identified risks by only entering into contracts where current market quotes in actively traded, liquid markets are available to determine the fair value of contracts. In addition, substantially all of the Company’s forward contracts are less than 18 months in duration. However, the reader is cautioned to develop a full understanding of how fair value or mark-to-market accounting creates differing reported results relative to those otherwise presented under conventional accrual accounting.

- Trade Accounts

Accounts receivable and accounts payable typically represent the single most significant assets and liabilities of the Company. Particularly within the Company’s energy marketing and oil and gas exploration and production operations, there is a high degree of interdependence with and reliance upon third parties (including transaction counterparties) to provide adequate information for the proper recording of amounts receivable or payable. Substantially all such third parties are larger firms providing the Company with the source documents for recording trade activity. It is commonplace for these entities to retroactively adjust or correct such documents. This typically requires the Company to either, absorb, benefit from, or pass along such corrections to another third party.

Due to the volume and the complexity of transactions and the high degree of interdependence with third parties, this is a difficult area to control and manage. The Company manages this process by participating in a monthly settlement process with each of its counterparties. Ongoing account balances are monitored monthly and the Company attempts to gain the cooperation of such counterparties to reconcile outstanding balances. The Company also places great emphasis on collecting cash balances due and paying only bonafide properly supported claims. In addition, the Company maintains and monitors its bad debt allowance. Nevertheless a degree of risk always remains due to the customs and practices of the industry.

- Oil and Gas Reserve Estimate

The value of capitalized costs of oil and gas exploration and production related assets are dependent on underlying oil and gas reserve estimates. Reserve estimates are based on many subjective factors. The accuracy of reserve estimates depends on the quantity and quality of geological data, production performance data and reservoir engineering data, changed prices, as well as the skill and judgment of petroleum engineers in interpreting such data. The process of estimating reserves requires frequent revision of estimates (usually on an annual basis) as additional information becomes available. Estimated future oil and gas revenue calculations are also based on estimates by petroleum engineers as to the timing of oil and gas production, and there is no assurance that the actual timing of production will conform to or approximate such estimates. Also, certain assumptions must be made with respect to pricing. The Company’s estimates assume prices will remain constant from the date of the engineer’s estimates, except for changes reflected under natural gas sales contracts. There can be no assurance that actual future prices will not vary as industry conditions, governmental regulation and other factors impact the market price for oil and gas.

The Company follows the successful efforts method of accounting, so only costs (including development dry hole costs) associated with producing oil and gas wells are capitalized. Estimated oil and gas reserve quantities are the basis for the rate of amortization under the Company’s units of production method for depreciating, depleting and amortizing of oil and gas properties. Estimated oil and gas reserve values also provide the standard for the Company’s periodic review of oil and gas properties for impairment.

- Contingencies

From time to time as incident to its operations, the Company becomes involved in various accidents, lawsuits and/or disputes. Primarily as an operator of an extensive trucking fleet, the Company may be a party to motor vehicle accidents, worker compensation claims or other items of general liability as would be typical for the industry. In addition, the Company has extensive operations that must comply with a wide variety of tax laws, environmental laws and labor laws, among others. Should an incident occur, management would evaluate the claim based on its nature, the facts and circumstances and the applicability of insurance coverage. To the extent management believes that such event may impact the financial condition of the Company, management will estimate the monetary value of the claim and make appropriate accruals or disclosure as provided in the guidelines of SFAS No. 5, “Accounting for Contingencies”.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

The Company is exposed to market risk, including adverse changes in interest rates and commodity prices.

Interest Rate Risk

Total long-term debt at September 30, 2006 included $3 million of floating rate debt. As a result, the Company’s annual interest costs fluctuate based on interest rate changes. Because the interest rate on the Company’s long-term debt is a floating rate, the fair value approximates carrying value as of September 30, 2006. A hypothetical 10 percent adverse change in the floating rate would not have had a material effect on the Company’s results of operations for the nine-month period ended September 30, 2006.

Commodity Price Risk

The Company’s major market risk exposure is in the pricing applicable to its marketing and production of crude oil and natural gas. Realized pricing is primarily driven by the prevailing spot prices applicable to oil and gas. Commodity price risk in the Company’s marketing operations represents the potential loss that may result from a change in the market value of an asset or a commitment. From time to time, the Company enters into forward contracts to minimize or hedge the impact of market fluctuations on its purchases of crude oil and natural gas. The Company may also enter into price support contracts with certain customers to secure a floor price on the purchase of certain supply. In each instance, the Company locks in a separate matching price support contract with a third party in order to minimize the risk of these financial instruments. Substantially all forward contracts fall within a nine-month to one-year term with no contracts extending longer than three years in duration. The Company monitors all commitments, positions and endeavors to maintain a balanced portfolio.

Certain forward contracts are recorded at fair value, depending on management’s assessments of numerous accounting standards and positions that comply with generally accepted accounting principles. The undiscounted fair value of such contracts is reflected on the Company’s balance sheet as risk management assets and liabilities. The revaluation of such contracts is recognized on a net basis in the Company’s results of operations. Current market price quotes from actively traded liquid markets are used in all cases to determine the contracts’ fair value. Regarding net risk management assets, all of the presented values as of September 30, 2006 and 2005 were based on readily available market quotations. Risk management assets and liabilities are classified as short-term or long-term depending on contract terms. The estimated future net cash inflow based on year-end market prices is $1,426,000, all of which will be received during the remainder of 2006 through December 2007. The estimated future cash inflow approximates the net fair value recorded in the Company’s risk management assets and liabilities.

The following table illustrates the factors that impacted the change in the net value of the Company’s risk management assets and liabilities for the nine months ended September 30, 2006 and 2005 (in thousands):

	2006			2005
Net fair value on January 1,	$	1,781		$	630
Activity during the period
- Cash received from settled contracts		(1,979	)		(890	)
- Net realized gain from prior years’ contracts		360			308
- Net unrealized gain from prior years’ contracts		-			5
- Net unrealized (loss) from prior years’ contracts		(83	)		-
- Net unrealized gain from current year contracts		1,347			403
- Net fair value on September 30,	$	1,426		$	456

Historically, prices received for oil and gas production have been volatile and unpredictable. Price volatility is expected to continue. From January 1, 2006 through September 30, 2006 natural gas price realizations ranged from a monthly low of $3.87 per mmbtu to a monthly high of $13.06 per mmbtu. Oil prices ranged from a low of $61.30 per barrel to a high of $73.64 per barrel during the same period. A hypothetical 10 percent adverse change in average natural gas and crude oil prices, assuming no changes in volume levels, would have reduced earnings by approximately $1,945,000 for the nine-month period ended September 30, 2006.

Forward-Looking Statements—Safe Harbor Provisions

This report for the period ended September 30, 2006 contains certain forward-looking statements intended to be covered by the safe harbors provided under Federal securities law and regulation. To the extent such statements are not recitations of historical fact, forward-looking statements involve risks and uncertainties. In particular, statements under the captions (a) Management’s Discussion and Analysis of Financial Condition and Results of Operations, (b) Liquidity and Capital Resources, (c) Critical Accounting Policies and Use of Estimates, (d) Quantitative and Qualitative Disclosures about Market Risk, among others, contain forward-looking statements. Where the Company expresses an expectation or belief to future results or events, such expression is made in good faith and believed to have a reasonable basis in fact. However, there can be no assurance that such expectation or belief will actually result or be achieved.

A number of factors could cause actual results or events to differ materially from those anticipated. Such factors include, among others, (a) general economic conditions, (b) fluctuations in hydrocarbon prices and margins, (c) variations between crude oil and natural gas contract volumes and actual delivery volumes, (d) unanticipated environmental liabilities or regulatory changes, (e) counterparty credit default, (f) inability to obtain bank and/or trade credit support, (g) availability and cost of insurance, (h) changes in tax laws, (i) the availability of capital, (j) changes in regulations, (k) results of current items of litigation, (l) uninsured items of litigation or losses, (m) uncertainty in reserve estimates and cash flows, (n) ability to replace oil and gas reserves, (o) security issues related to drivers and terminal facilities, (p) commodity price volatility, (q) demand for chemical based trucking operations, and (r) successful completion of drilling activity. For more information, see the discussion under Forward-Looking Statements in the annual report on Form 10-K for the year ended December 31, 2005.

Item 4. Disclosure Controls and Procedures

The Company maintains “disclosure controls and procedures” (as defined in Rule 13a-15(e) and 15d-15(e) under the Securities and Exchange Act of 1934, as amended (the “Exchange Act” ), that are designed to ensure that information required to be disclosed in the reports that the Company files or submits under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and is accumulated and communicated to management, including the Company’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely discussions regarding required disclosure. As of the end of the period covered by this quarterly report an evaluation was carried out under the supervision and with the participation of the Company's management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures. Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective.

During the Company’s third quarter, there have not been any changes in the Company’s internal controls over financial reporting (as defined in Rules 13a-13(f) and 15d-15(f) of the Exchange Act) that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1.

Item 1A. - There have been no material changes in the Company’s risk factors from those disclosed in the Company’s 2005 Form 10-K for the year ended December 31, 2005.

Item 2. - None

Item 3. - None

Item 4. - None

Item 5. - None

Item 6. Exhibits

31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2	Certification of Chief Financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley of 2002

32.2	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	ADAMS RESOURCES & ENERGY, INC
	(Registrant)



Date: November 14, 2006	By /s/K. S. Adams, Jr.
	K. S. Adams, Jr.
	Chief Executive Officer


	By /s/Frank T. Webster
	Frank T. Webster
	President & Chief Operating Officer


	By /s/Richard B. Abshire
	Richard B. Abshire
	Chief Financial Officer

EXHIBIT INDEX

Exhibit
Number	Description

31.1	Certificate of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2	Certificate of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1	Certificate of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2	Certificate of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002