Edgar Filing: ADAMS RESOURCES & ENERGY, INC.

body_10q.htm

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, 2007

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 12b-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 1, 2007.

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,
	2007			2006			2007			2006
REVENUES:
Marketing	$	1,697,574		$	1,647,062		$	680,085		$	604,977
Transportation		48,854			48,277			17,208			16,180
Oil and gas		9,981			12,687			3,002			3,841
		1,756,409			1,708,026			700,295			624,998
COSTS, EXPENSES AND OTHER:
Marketing		1,683,122			1,636,839			674,661			602,757
Transportation		40,893			40,438			14,645			13,719
Oil and gas operations		7,708			3,761			2,597			1,403
Oil and gas property sale		(12,078	)		-			-			-
General and administrative		7,491			6,230			2,307			2,110
Depreciation, depletion and amortization		7,038			7,177			2,272			2,741
		1,734,174			1,694,445			696,482			622,730

Operating earnings		22,235			13,581			3,813			2,268
Other income (expense):
Interest income		1,266			487			443			238
Interest expense		(75	)		(112	)		(12	)		(40	)
Earnings before income taxes		23,426			13,956			4,244			2,466

Income tax provision		8,373			4,597			1,389			789

Net earnings	$	15,053		$	9,359		$	2,855		$	1,677

EARNINGS PER SHARE:
Basic and diluted net earnings
per common share	$	3.57		$	2.22		$	.68		$	.40

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,
	2007			2006
ASSETS

Current assets:
Cash and cash equivalents	$	25,076		$	20,668
Accounts receivable, net of allowance for doubtful
accounts of $336 and $225, respectively		205,746			194,097
Inventories		13,531			7,950
Risk management receivables		5,808			13,140
Income tax receivables		492			1,396
Prepayments		6,921			4,539

Total current assets		257,574			241,790

Property and equipment		110,290			107,221
Less – accumulated depreciation,
depletion and amortization		(67,969	)		(63,905	)
		42,321			43,316
Other assets:
Risk management receivables		1,047			644
Cash deposits and other		3,755			3,537
	$	304,697		$	289,287

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	200,098		$	185,589
Accounts payable – related party		98			146
Risk management payables		4,664			11,897
Accrued and other liabilities		3,253			7,897
Current deferred income taxes		1,126			1,053
Total current liabilities		209,239			206,582

Long-term debt		-			3,000

Other liabilities:
Asset retirement obligations		1,188			1,152
Deferred income taxes and other		4,128			3,762
Risk management payables		721			423
		215,276			214,919
Commitments and contingencies (Note 5)

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		77,306			62,253
Total shareholders’ equity		89,421			74,368
	$	304,697		$	289,287

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,
	2007			2006
CASH PROVIDED BY OPERATIONS:
Net earnings	$	15,053		$	9,359
Adjustments to reconcile net earnings to net cash
from operating activities -
Depreciation, depletion and amortization		7,038			7,177
Gains on property sales		(12,034	)		(46	)
Dry hole costs incurred		2,847			21
Impairment on oil and gas properties		633			420
Other, net		301			(116	)
Decrease (increase) in accounts receivable		(11,649	)		33,242
Decrease (increase) in inventories		(5,581	)		2,829
Risk management activities		(6	)		355
Decrease (increase) in tax receivable		904			(989	)
Decrease (increase) in prepayments		(2,382	)		3,974
Increase (decrease) in accounts payable		13,757			(35,150	)
Increase (decrease) in accrued liabilities		(4,644	)		1,969
Deferred income taxes		380			750

Net cash provided by (used in) operating activities		4,617			23,795

INVESTING ACTIVITIES:
Property and equipment additions		(12,104	)		(11,355	)
Insurance deposits		(424	)		(530	)
Proceeds from property sales		15,319			60
Redemption of short-term investments		15,000			-
Investment in short-term investments		(15,000	)		-

Net cash provided by (used in) investing activities		2,791			(11,825	)

FINANCING ACTIVITIES:
Net repayments under credit agreements		(3,000	)		(8,475	)

Net cash used in financing activities		(3,000	)		(8,475	)

Increase in cash and cash equivalents		4,408			3,495

Cash at beginning of period		20,668			18,817

Cash at end of period	$	25,076		$	22,312

Supplemental disclosure of cash flow information:
Interest paid during the period	$	79		$	112
Income taxes paid during the period	$	7,449		$	4,842
Increase (decrease) in liabilities associated
with property additions	$	(704	)	$	239

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, 2007 and December 31, 2006, its results of operations for the three and nine month periods ended September 30, 2007 and 2006, and its cash flows for the nine-month periods ended September 30, 2007 and 2006. 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 annual report on Form 10-K for the year ended December 31, 2006. 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, Cash Equivalents and Auction Rate Investments

Cash and cash equivalents include any treasury bill, commercial paper, money market fund or federal funds with maturity of 30 days or less. Depending on cash availability, auction rate investments in municipal bonds and bond mutual funds are also made from time to time. The Company invests in tax-free municipal securities in order to enhance the after-tax rate of return from short-term investments of cash. The Company had no auction rate investments as of September 30, 2007 and December 31, 2006.

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. Petroleum products and crude oil inventory is valued at average cost. Components of inventory are as follows (in thousands):

	September 30,		December 31,
	2007		2006

Crude oil	$	11,447	$	5,983
Petroleum products		2,084		1,967

	$	13,531	$	7,950

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, 2007, 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 fifteen years for marketing, three to fifteen years for transportation and ten to twenty years for all others.

The Company periodically reviews 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. During the first nine months of 2007 and 2006, an impairment provision on producing oil and gas properties totaling $11,000 and $520,000, respectively, was recorded due to higher costs having been incurred on certain properties relative to their oil and gas reserve valuations. In addition, management evaluates the carrying value of non-producing properties and unevaluated properties and may deem them impaired for lack of drilling activity. Such evaluations are made on a quarterly basis. Accordingly, a $633,000 and a $420,000 impairment provision on non-producing properties were recorded in the nine-month periods ended September 30, 2007 and 2006, respectively.

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 $2,699,000 and $2,275,000 as of September 30, 2007 and December 31, 2006, respectively. In addition, the Company maintains certain deposits to support the collection and remittance of state crude oil severance taxes. Such deposits totaled $545,000 and $795,000 as of September 30, 2007 and December 31, 2006, respectively.

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. 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, crude oil purchases and sales are primarily recorded on a gross revenue basis in the accompanying 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 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 revenues and costs are 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 requires 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 entered into after March 31, 2006. However, the Company adopted Issue 04-13 effective January 1, 2006 so reported revenues and costs are consistent between the periods presented herein.

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 each of the three-month and nine-month periods ended September 30, 2007 and 2006. There were no potentially dilutive securities during those periods in 2007 and 2006.

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 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

Derivative financial instruments (including certain derivative instruments embedded in other contracts) are 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.

Crude oil, natural gas and refined products energy trading contracts that do not qualify as “normal purchase and sales” 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 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 to estimate 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, 2007 is $1,470,000, all of which will be received during the remainder of 2007 through 2009. 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, 2007 and 2006 (in thousands):

	2007			2006
Net fair value on January 1,	$	1,464		$	1,781
Activity during the period
-Cash paid (received) from settled contracts		(948	)		(1,979	)
-Net realized gain from prior years’ contracts		-			360
-Net realized (loss) from prior years’ contracts		(207	)		-
-Net unrealized (loss) from prior years’ contracts		(159	)		(83	)
-Net unrealized gain from current year contracts		1,320			1,347
Net fair value on September 30,	$	1,470		$	1,426

Asset Retirement Obligations

The Company has recorded 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 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):

	2007			2006

Balance on January 1,	$	1,152		$	1,058
-Liabilities incurred		90			22
-Accretion of discount		41			46
-Liabilities settled		(95	)		(14	)
-Revisions to estimates		-			-
Balance on September 30,	$	1,188		$	1,112

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 balance sheet.

New Accounting Pronouncements

In July 2006, the FASB issued Financial Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48). FIN 48 establishes standards for recognition and measurement, in the financial statements, of positions taken, or expected to be taken, by an entity in its income tax returns taking into consideration the uncertainty and judgment involved in the determination and filing of income taxes. 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 position will be examined by taxing authorities with full knowledge of all relevant information. FIN 48 also requires disclosures about positions taken by an entity in its tax returns that are not recognized in its financial statements, descriptions of open tax years by major jurisdiction and reasonably possible significant changes in the amount of unrecognized tax benefits that could occur in the next twelve months.

Unrecognized tax benefits represent those tax benefits related to tax positions that have been taken or are expected to be taken in tax returns, including refund claims, that are not recognized in the financial statements because, in accordance with FIN 48, management has either measured the tax benefit at an amount less than the benefit claimed, or expected to be claimed, or concluded that it is not more-likely-than-not that the tax position will be ultimately sustained. As of January 1, 2007, the Company had accrued approximately $230,000 including approximately $110,000 of potential interest and penalty applicable to certain open and unfiled state tax returns. The Company is currently working to file all open returns and expects to complete this process by year-end 2007. As the actual tax payments are made, the accrual will be reduced.

The Company adopted FIN 48 effective January 1, 2007. As discussed above, the Company has previously provided a liability accrual for open state tax returns and has no other unrecognized tax benefits. As such the adoption of FIN 48 did not impact on the Company’s results for the nine months ended September 30, 2007 and the above described tax accrual items did not impact the effective tax rate as presented herein. Interest and penalties associated with income tax liabilities are classified as income tax expense.

The earliest tax years remaining open from Federal and major states of operations are as follows:

	Earliest Open
	Tax Year

Federal	2004
Texas	2002
Louisiana	1999
Michigan	2002
Mississippi	2002
Alabama	2002
New Mexico	2002

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements”, which defines fair value, establishes a framework for measuring fair value and expands disclosures related to fair value measurements. SFAS No. 157 clarifies that fair value should be based on assumptions that market participants would use when pricing an asset or liability and establishes a fair value hierarchy of three levels that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data. SFAS No. 157 requires fair value measurements to be separately disclosed by level within the fair value hierarchy. The provisions of SFAS No. 157 become effective beginning January 1, 2008 and the Company is currently assessing the impact, if any, that the adoption of SFAS No. 157 will have on its financial statements.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities”. SFAS No. 159 provides an entity with the option, at specified election dates, to measure certain financial assets and liabilities and other items at fair value, with changes in fair value recognized in earnings as those changes occur. SFAS No. 159 also establishes presentation and disclosure requirements that include displaying the fair value of those assets and liabilities for which the entity elected the fair value option on the face of the balance sheet and providing management’s reasons for electing the fair value option for each eligible item. The provisions of SFAS No. 159 become effective beginning January 1, 2008 and management believes the adoption of SFAS No. 159 will not have a material impact on the Company’s consolidated financial statements.

Note 3 – 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):

			Segment		Depreciation		Property and
- Nine Month Comparison			Operating		Depletion and		Equipment
	Revenues		Earnings		Amortization		Additions
Period Ended September 30, 2007
Marketing
- Crude Oil	$	1,565,456	$	9,759	$	473	$	608
- Natural gas		9,051		3,020		120		105
- Refined products		123,067		755		325		411
Marketing Total		1,697,574		13,534		918		1,124
Transportation		48,854		4,695		3,266		255
Oil and gas		9,981		11,497		2,854		7,878
	$	1,756,409	$	29,726	$	7,038	$	9,257
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

			Segment			Depreciation		Property and
- Three Month Comparison			Operating			Depletion and		Equipment
	Revenues		Earnings			Amortization		Additions
Period Ended September 30, 2007
Marketing
- Crude Oil	$	632,729	$	4,098		$	166	$	181
- Natural gas		2,383		528			50		53
- Refined products		44,973		469			113		143
Marketing Total		680,085		5,095			329		377
Transportation		17,208		1,536			1,027		96
Oil and gas		3,002		(511	)		916		1,654
	$	700,295	$	6,120		$	2,272	$	2,127
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

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,
	2007			2006			2007			2006
Segment operating earnings	$	29,726		$	19,811		$	6,120		$	4,378
- General and administrative		(7,491	)		(6,230	)		(2,307	)		(2,110	)
Operating earnings		22,235			13,581			3,813			2,268
- Interest income		1,266			487			443			238
- Interest expense		(75	)		(112	)		(12	)		(40	)
Earnings before income taxes	$	23,426		$	13,956		$	4,244		$	2,466

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

	September 30,		December 31,
	2007		2006
Marketing
- Crude oil	$	150,572	$	116,917
- Natural gas		53,864		80,346
- Refined products		21,602		16,286
Marketing Total		226,038		213,549
Transportation		20,847		23,764
Oil and gas		26,982		25,918
Other		30,830		26,056
	$	304,697	$	289,287

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.

Note 4 - Transactions with Affiliates

Mr. K. S. Adams, Jr., Chairman and Chief Executive Officer, 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 participate on terms similar to 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 the Audit Committee comprised of the independent directors on the Company’s Board of Directors. For the first nine months of 2007, the Company’s investment commitments totaled approximately $5.9 million in those oil and gas projects where a related party was also participating in such investments. As of September 30, 2007 and December 31, 2006, the Company owed a combined net total of $98,387 and $146,338, 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 $93,629 and $88,737 in the nine-month periods ended September 30, 2007 and 2006, respectively.

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 including direct cost reimbursement for shared phone and secretarial services. For the nine-month period ended September 30, 2007, the affiliated entities charged the Company $74,023 of expense reimbursement and the Company charged the affiliates $56,154 for such expense reimbursements.

Note 5 - 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 6 – 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. The Company believes the likelihood of performance under these guarantees to be remote. Aggregate guaranteed residual values for tractors and trailers under operating leases as of September 30, 2007 are as follows (in thousands):

		2007				2008				2009				2010				2011				Thereafter				Total
Lease residual values		$	-			$	304			$	1,475			$	217			$	181			$	288			$	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, 2007, the maximum amount of such potential obligation is approximately $2,017,000. 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 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, 2007, the amount of parental guaranteed obligations are as follows (in thousands):

	2007		2008		2009		2010		2011		Thereafter		Total
Bank debt	$	-	$	-	$	-	$	-	$	-	$	-	$	-
Operating leases		989		3,846		1,523		547		186		104		7,195
Lease residual values		-		304		1,475		217		181		288		2,465
Commodity purchases		21,092		-		-		-		-		-		21,092
Letters of credit		48,505		-		-		-		-		-		48,505
	$	70,586	$	4,150	$	2,998	$	764	$	367	$	392	$	79,257

Note 7 – Subsequent Event

On November 13, 2007 the Company’s Board of Directors declared an annual cash dividend in the amount of $0.47 per common share, payable on December 17, 2007 to shareholders of record as of December 3, 2007.

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 were as follows (in thousands):

	Nine Months Ended				Three Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
Revenues
Crude oil	$	1,565,456	$	1,498,007	$	632,729	$	550,879
Natural gas		9,051		9,632		2,383		4,087
Refined products		123,067		139,423		44,973		50,011
Total	$	1,697,574	$	1,647,062	$	680,085	$	604,977

Operating Earnings
Crude oil	$	9,759	$	3,568	$	4,098	$	(475	)
Natural gas		3,020		4,340		528		1,918
Refined products		755		1,325		469		447
Total	$	13,534	$	9,233	$	5,095	$	1,890

Depreciation
Crude oil	$	473	$	656	$	166	$	217
Natural gas		120		44		50		15
Refined products		325		290		113		98
Total	$	918	$	990	$	329	$	330

Selected operational information was as follows:

	Nine Months Ended				Three Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
Field Level Purchase Volumes – Per day ⁽¹⁾
Crude oil – barrels		60,950		62,950		60,750		57,621
Natural gas – mmbtu’s		418,450		342,400		380,650		356,100

Average Purchase Price
Crude oil – per barrel	$	63.56	$	64.52	$	74.29	$	66.77
Natural Gas – per mmbtu’s	$	6.79	$	6.70	$	6.05	$	6.14

_____________________________

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

Revenues from crude oil sales were generally consistent during the first half of 2007 and 2006, while higher crude oil prices yielded a revenue increase for the third quarter of 2007. Such pricing trend is reflected above. Natural gas prices stayed in a consistent range during the periods presented.

Operating earnings from crude oil improved during 2007 as the Company was able to garner better pricing from its end-market customer base. The current year also benefited from crude oil inventory liquidation gains as crude oil prices generally rose during the comparative periods. On January 1, 2007 crude oil prices were in the $53 per barrel range rising to $80 per barrel by September 30, 2007. Such price increases resulted in inventory liquidation gains totaling $3.1 million and $1.5 million for the nine-month and three-month periods ended September 30, 2007, respectively. During 2006, crude oil prices fluctuated from periods of increasing prices to periods of decreasing prices. During the first half of 2006, such price swings resulted in $1.5 million of inventory liquidation gains while during the third quarter of 2006, such fluctuations produced a $1.5 million inventory valuation loss. As of September 30, 2007, the Company held 143,556 barrels of crude oil inventory at an average price of $79.74 per barrel.

Reported natural gas revenues reflect the gross margin on the Company’s natural gas purchase and resale business. Gross margins and operating earnings were reduced in both the comparative three-month and nine-month periods due to generally mild weather patterns and a lack of volatility in the 2007 marketplace.

Refined product revenues and operating earnings were reduced in 2007 due to a lack of available biodiesel supply. The Company’s suppliers of biodiesel fuel experienced difficulty meeting their contractual quantity commitments during the first half of 2007. During the third quarter of 2007, the normal level of biodiesel supply was restored and has continued to date.

- Transportation

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

	Nine Months Ended							Three Months Ended
	September 30,				Increase			September 30,				Increase
	2007		2006		(Decrease)			2007		2006		(Decrease)

Revenues	$	48,854	$	48,277		1.2	%	$	17,208	$	16,180		6.4	%

Operating earnings	$	4,695	$	4,472		4.9	%	$	1,536	$	1,327		15.7	%

Depreciation	$	3,266	$	3,367		(2.9	)%	$	1,027	$	1,134		(9.4	)%

Transportation segment revenues and operating expenses were generally consistent between the comparative periods with both 2007 and 2006 results benefiting from strong spring seasonal demand for fertilizer and agricultural chemical hauls. Third quarter 2007 experienced slightly improved demand and hence, results were slightly improved relative to the 2006 period. There was no significant reason for this result.

Oil and Gas

Oil and gas segment revenues and operating earnings are primarily a function of crude oil and natural gas prices and production volumes. During the third quarter of 2007, the oil and gas division experienced a $511,000 operating loss compared to a $1,161,000 operating income in the third quarter of 2006. The third quarter 2007 loss was a direct result of $1,930,000 of dry hole and other exploration expenses being incurred during the period. See table below. Comparative amounts for revenues, operating earnings and depreciation and depletion are as follows (in thousands):

	Nine Months Ended							Three Months Ended
	September 30,				Increase			September 30,					Increase
	2007		2006		(Decrease)			2007			2006		(Decrease)
Revenues	$	9,981	$	12,687		(21.3	)%	$	3,002		$	3,841		(21.8	)%

Operating earnings	$	11,497	$	6,106		88.3	%	$	(511	)	$	1,161		(144.0	)%

Depreciation and depletion	$	2,854	$	2,820		1.2	%	$	916		$	1,277		(28.2	)%

Production volumes and price information is as follows:

	Nine Months Ended				Three Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
Crude Oil
Volume – barrels		51,190		56,650		15,740		17,080
Average price per barrel	$	65.53	$	66.01	$	76.22	$	69.45

Natural gas
Volume – mcf		890,000		1,175,300		248,000		379,750
Average price per mcf	$	7.45	$	7.61	$	7.26	$	6.99

Reduced revenues during 2007 are primarily a result of normal production declines on the Company’s oil and gas properties. In May 2007, the Company sold its interest in certain Louisiana producing oil and gas properties. Sale proceeds totaled $15.3 million resulting in a pre-tax gain on sale of approximately $12.1 million. The favorable results from the gain were partially offset by $4,868,000 of exploration expense during the first nine months of 2007. Comparative exploration expenses were as follows (in thousands):

	Nine Months Ended				Three Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
Dry hole expense	$	2,847	$	21	$	1,471	$	5
Prospect abandonment		622		419		225		30
Seismic and geological		1,399		468		234		227

Total	$	4,868	$	908	$	1,930	$	262

During the first nine months of 2007, the Company participated in the drilling of 24 wells. Seventeen of the wells were successful with six dry holes and one well converted to salt water disposal service. Additionally, the Company has three wells in process on September 30, 2007 with evaluation anticipated prior to year end. Participation in the drilling of approximately 7 wells is planned for the remainder of 2007 on the Company’s prospect acreage in Alabama, Arkansas, Louisiana and Texas. In addition, the Company is participating in active 3-D seismic surveys in Arkansas and Louisiana that are expected to generate drilling opportunities for 2008 and 2009.

The Company and its partners are seeking a third party to drill the initial well on their prospect acreage in the UK North Sea. The Company holds a 30 percent interest in Blocks 21-1b, 21-2b and 21-3d in the central section through a “Promote License” that does not require a commitment to drill a well. In the southern sector of the UK North Sea the Company holds an 8.33 percent beneficial interest in Block 42-27b. Seismic evaluation work is underway on this Block which is also held by a “Promote License” that does not require a drilling commitment.

- 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. The Company’s effective tax rate for 2007 is elevated due to the $12.1 million gain on sale of certain producing oil and gas properties occurring in Louisiana and subject to an 8 percent state income tax rate.

- Outlook

Crude oil prices have trended up this year, reaching $96 per barrel in November 2007. In contrast, despite some recent seasonal strengthening, natural gas prices have not followed the pattern of oil. The preferred operating environment for the Company is strong natural gas prices with moderate crude oil prices, unlike the current trend. Higher crude oil prices tend to slow the U. S. economy and increase diesel fuel costs; factors adverse to the Company’s transportation business. Also, with two-thirds of oil and gas division sales derived from the production of natural gas, higher natural gas prices will usually enhance earnings. A further concern for this year is the Company is not achieving its targeted growth in oil and natural gas production volumes. Thus far in 2007, actual new well production quantities brought on line have fallen short of expectation. Given these factors, the outlook for the fourth quarter of 2007 is uncertain.

Liquidity and Capital Resources

During the first nine months of 2007, net cash provided by operating activities totaled $4,617,000 versus $23,795,000 provided during the first nine months of 2006. 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,
	2007			2006
Net earnings	$	15,053		$	9,359
Less net gain on sale		(12,034	)		(46	)
Depreciation, depletion and amortization		7,038			7,177
Property and equipment additions		(12,104	)		(11,355	)

Cash available for (used by) other activities	$	(2,047	)	$	5,135

Capital expenditures during the first nine months of 2007 included $1,379,000 for marketing and transportation equipment additions and $7,878,000 in property additions associated with oil and gas exploration and production activities. For the remainder of 2007, 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. In addition, approximately $1 million will be expended toward trucks and other equipment additions within the Company’s marketing and transportation businesses with funding from available cash flow.

- 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 $5,000,000 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, 2007 was established at $5,000,000. 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 $5,000,000 as of September 30, 2007. The line of credit loans are scheduled to expire on October 31, 2008, with the then present balance outstanding converting to a term loan payable in eight equal quarterly installments. As of September 30, 2007, there was no debt outstanding under the Company’s two revolving credit facilities.

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 $59,527,000. 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 is in compliance with these restrictions.

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 $60 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, 2007, the Company had $6 million of eligible borrowing capacity under this facility. No working capital advances were outstanding as of September 30, 2007. Letters of credit outstanding under this facility totaled approximately $40.5 million as of September 30, 2007. 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, 2007. Letters of credit outstanding under this facility totaled $8 million as of September 30, 2007. 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 SFAS 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 and confuses 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 and liquid markets are available to determine the fair value of contracts. In addition, the Company’s forward contracts are primarily less than 18 months in duration. 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, changing 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. Calculation of estimated future oil and gas revenues are also based on estimates as to the timing of oil and gas production. 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 assumes 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, political conditions, economic conditions, weather conditions, market uncertainty 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 evaluates 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 estimates the monetary value of the claim and makes 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

The Company had no debt outstanding as of September 30, 2007. Historically, the Company’s long-term debt constituted floating rate debt. As a result, the Company’s annual interest costs fluctuated based on interest rate changes. Because the interest rate on the Company’s long-term debt was at a floating rate, the fair value of the debt approximated the carrying value as of a given date.

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 six-month to one-year term with no contracts extending longer than three years in duration. The Company monitors all commitments and 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 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 to estimate the contracts’ fair value. Regarding net risk management assets, all of the presented values as of September 30, 2007 and 2006 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 period end market prices is $1,470,000 as of September 30, 2007, all of which will be received during the remainder of 2007 through 2009. 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, 2007 and 2006 (in thousands):

	2007			2006
Net fair value on January 1,	$	1,464		$	1,781
Activity during the period
- Cash received from settled contracts		(948	)		(1,979	)
- Net realized gain from prior years’ contracts		-			360
- Net realized loss from prior years’ contracts		(207	)		-
- Net unrealized loss from prior years’ contracts		(159	)		(83	)
- Net unrealized gain from current year contracts		1,320			1,347
- Net fair value on September 30,	$	1,470		$	1,426

Historically, prices received for oil and gas production have been volatile and unpredictable and price volatility is expected to continue. From January 1, 2007 through September 30, 2007 natural gas price realizations ranged from a monthly low of $5.87 per mmbtu to a monthly high of $7.56 per mmbtu. Oil prices ranged from a low of $53.40 per barrel to a high of $79.48 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 pre-tax earnings by approximately $2.1 million for the nine-month period ended September 30, 2007.

Forward-Looking Statements—Safe Harbor Provisions

This report for the period ended September 30, 2007 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, (e) Price Risk Management Activities and (f) Commitments and Contingencies 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 services, and (r) successful completion of drilling activity. For more information, see the discussion under Forward-Looking Statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2006.

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 third quarter the Company completed the implementation of certain new accounting applications within certain of its subsidiary units. As with any material change in internal control over financial reporting, the design of these applications, along with the design of the internal controls over all accounting processes, were evaluated for effectiveness. There have been no other 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 2006 From 10-K.

Item 2. -	None

Item 3. -	None

Item 4. -	Submission of Matters to a Vote of Security Holders.

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 13, 2007	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