Adams Resources & Energy, Inc. 10-Q/A 9-30-2005

SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-Q /A

Amendment No. 1


(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, 2005

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 an accelerated filer (as defined in Rule 12b-2 of the Act). YES o NO 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, 2005.

 
 
 


EXPLANATORY NOTE

This Amendment No. 1 to the Adams Resources & Energy, Inc. (“the Company”) Quarterly Report on Form 10-Q for the quarter ended September 30, 2005 (“Original Filing”), initially filed with the Securities and Exchange Commission (the “Commission”) on November 14, 2005, is being filed to reflect the restatement of the Company’s Unaudited Condensed Consolidated Statements of Operations for the three and nine month periods ended September 30, 2005. For a more detailed description of this matter, see Note 9 to the accompanying Notes to Unaudited Condensed Consolidated Financial Statements included in this Form 10-Q/A. 

For purposes of this Form 10-Q/A, and in accordance with Rule 12b-15 under the Securities Exchange Act of 1934, as amended, each item of the Form 10-Q that was affected by the restatement has been amended to the extent affected and restated in its entirety. NO ATTEMPT HAS BEEN MADE IN THIS FORM 10-Q/A TO UPDATE OTHER DISCLOSURES AS PRESENTED IN THE FORM 10-Q EXCEPT AS REQUIRED TO REFLECT THE EFFECTS OF THE RESTATEMENT. IN ADDITION, THIS FORM 10-Q/A INCLUDES UPDATED CERTIFICATIONS FROM THE COMPANY’S CEO AND CFO AS EXHIBITS 31.1, 31.2, 32.1 AND 32.2.

 
 
 

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,
  
   
2005
  
2004
  
2005
  
2004
  
   
(RESTATED
      
(RESTATED
      
   
SEE NOTE 9)
      
SEE NOTE 9)
      
REVENUES:
                          
Marketing (includes $532,402, $525,936,
                          
$193,149, and $203,112, respectively, of
                         
proceeds from buy/sell arrangements)
  
$
1,654,585
  
$
1,464,167
  
$
618,395
  
$
534,875
  
Transportation 
    
41,765
    
34,696
    
13,867
    
12,546
  
Oil and gas 
    
10,495
    
8,078
    
4,745
    
2,972
  
     
1,706,845
    
1,506,941
    
637,007
    
550,393
  
COSTS AND EXPENSES:
                          
Marketing (includes $532,402, $525,936,
                          
$193,149, and $203,112, respectively,
                         
of costs from buy/sell arrangements) 
    
1,641,614
    
1,453,563
    
612,170
    
528,508
  
Transportation 
    
35,401
    
29,301
    
11,814
    
10,392
  
Oil and gas 
    
3,882
    
4,325
    
2,272
    
1,377
  
General and administrative 
    
6,494
    
5,574
    
1,959
    
2,120
  
Depreciation, depletion and amortization
    
5,113
    
4,138
    
1,723
    
1,416
  
     
1,692,504
    
1,496,901
    
629,938
    
543,813
  
                           
Operating earnings 
    
14,341
    
10,040
    
7,069
    
6,580
  
Other income (expense):
                          
Interest income 
    
116
    
39
    
57
    
12
  
Interest expense 
    
(80
)
  
(78
)
  
(28
)
  
(17
)
Earnings from continuing operations
                          
before income taxes  
    
14,377
    
10,001
    
7,098
    
6,575
  
                           
Income tax provision 
    
4,622
    
3,443
    
2,102
    
2,274
  
                           
Earnings from continuing operations 
    
9,755
    
6,558
    
4,996
    
4,301
  
Income (loss) from discontinued operations,
                         
net of tax provision (benefit) of $143, 
                          
($130), $155 and $26, respectively 
    
279
    
(150
)
  
301
    
51
  
                           
Net earnings 
  
$
10,034
  
$
6,408
  
$
5,297
  
$
4,352
  
                           
EARNINGS (LOSS) PER SHARE:
                          
From continuing operations
  
$
2.31
  
$
1.56
  
$
1.19
  
$
1.02
  
From discontinued operations 
    
.07
    
(.04
)
  
.07
    
.01
  
Basic and diluted net earnings
                          
per common share 
  
$
2.38
  
$
1.52
  
$
1.26
  
$
1.03
  
                           
DIVIDENDS PER COMMON SHARE 
  
$
-
  
$
-
  
$
-
  
$
-
  
The accompanying notes are an integral part of these financial statements.

 
1
 

ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands)
   
September 30,
  
December 31,
  
   
2005
  
2004
  
ASSETS
              
               
Current assets:
              
Cash and cash equivalents 
  
$
24,610
  
$
19,942
  
Accounts receivable, net of allowance for doubtful
              
accounts of $638 and $384, respectively 
    
205,737
    
161,885
  
Inventories 
    
13,407
    
11,372
  
Risk management receivables 
    
29,067
    
7,795
  
Prepayments 
    
3,567
    
8,345
  
               
Total current assets 
    
276,388
    
209,339
  
               
Property and equipment 
    
90,010
    
88,681
  
Less - accumulated depreciation,
             
depletion and amortization 
    
(58,595
)
  
(59,605
)
     
31,415
    
29,076
  
Other assets:
              
Risk management assets 
    
1,102
    
-
  
Other assets 
    
1,377
    
439
  
   
$
310,282
  
$
238,854
  
               
LIABILITIES AND SHAREHOLDERS’ EQUITY
              
               
Current liabilities:
              
Accounts payable 
  
$
199,717
  
$
160,387
  
Risk management payables 
    
28,642
    
7,165
  
Accrued and other liabilities 
    
5,020
    
5,904
  
Current deferred income taxes 
    
439
    
94
  
Total current liabilities 
    
233,818
    
173,550
  
               
Long-term debt 
    
11,475
    
11,475
  
               
Other liabilities:
              
Asset retirement obligations 
    
706
    
723
  
Deferred income taxes and other 
    
3,603
    
3,531
  
Risk management liabilities 
    
1,071
    
-
  
     
250,673
    
189,279
  
Commitments and contingencies (Note 7)
              
               
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  
    
47,494
    
37,460
  
Total shareholders’ equity  
    
59,609
    
49,575
  
   
$
310,282
  
$
238,854
  
The accompanying notes are an integral part of these financial statements.

 
2
 
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
   
Nine Months Ended
  
   
September 30,
  
   
2005
  
2004
  
CASH PROVIDED BY OPERATING ACTIVITIES:
              
Earnings from continuing operations 
  
$
9,755
  
$
6,558
  
Adjustments to reconcile earnings from continuing
             
operations to net cash provided by (used in)
operating activities -  
              
Depreciation, depletion and amortization 
    
5,113
    
4,138
  
Gains on property sales 
    
(1,044
)
  
(411
)
Impairment on non-producing oil and gas properties 
    
313
    
487
  
Other, net 
    
(151
)
  
92
  
Changes in operating assets and liabilities -
             
Decrease (increase) in accounts receivable, net  
    
(43,852
)
  
(18,859
)
Decrease (increase) in inventories  
    
(2,127
)
  
(5,209
)
Risk management activities 
    
174
    
(28
)
Decrease (increase) in tax receivable 
    
-
    
1,065
  
Decrease (increase) in prepayments 
    
4,778
    
(2,462
)
Increase (decrease) in accounts payable 
    
39,474
    
5,104
  
Increase (decrease) in accrued and other liabilities 
    
(539
)
  
4,203
  
Deferred income taxes 
    
85
    
-
  
               
Net cash provided by (used in) continuing operations 
    
11,979
    
(5,322
)
Net cash provided by discontinued operations 
    
180
    
4,084
  
               
Net cash provided by (used in) operating activities  
    
12,159
   
(1,238
)
               
INVESTING ACTIVITIES:
              
Property and equipment additions  
    
(8,415
)
  
(6,261
)
Insurance deposits 
    
(817
)
  
-
  
Proceeds from property sales 
    
1,191
    
891
  
               
Net cash (used in) continuing operations 
    
(8,041
)
  
(5,370
)
Proceeds from sale of discontinued property 
    
550
    
-
  
               
Net cash (used in) investing activities 
    
(7,491
)
  
(5,370
)
               
FINANCING ACTIVITIES:
              
Net borrowings under credit agreements 
    
-
    
-
  
               
Net cash used in financing activities 
    
-
    
-
  
               
Increase (decrease) in cash and cash equivalents 
    
4,668
    
(6,608
)
               
Cash and cash equivalents at beginning of period 
    
19,942
    
28,342
  
               
Cash and cash equivalents at end of period 
  
$
24,610
  
$
21,734
  
               
Supplemental disclosure of cash flow information:
             
Interest paid during the period  
  
$
64
  
$
78
  
Income taxes paid during the period 
  
$
4,031
  
$
2,062
  
The accompanying notes are an integral part of these financial statements
 
3
 

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, 2005 and December 31, 2004, its results of operations for the nine months ended September 30, 2005 and 2004 and its cash flows for the nine months ended September 30, 2005 and 2004. 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 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. The interim statements of operations are 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 500-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. Included in the cash balance at September 30, 2005 and December 31, 2004 is a deposit of $2 million to collateralize the Company's month-to-month crude oil letter of credit facility. Commencing in June 2005, the Company maintains certain cash deposits to support its participation in a captive liability insurance program. Such deposits totaled $817,000 as of September 30, 2005 and are included in other assets on the accompanying balance sheet.

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.

 
4
 


Components of inventory are as follows (in thousands):

   
September 30,
  
December 31,
  
   
2005
  
2004
  
           
Crude oil 
  
$
11,778
  
$
9,663
  
Petroleum products 
    
1,629
    
1,709
  
               
   
$
13,407
  
$
11,372
  

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, 2005, 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 $313,000 and a $487,000 impairment provision on non-producing properties was recorded in the nine-month period ended September 30, 2005 and 2004, respectively.

 
5
 

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”) 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities”. In contrast, substantially all purchases and sales of crude oil qualify, and have been designated as, normal purchases and sales. Therefore, crude oil purchases and sales are recorded on a gross revenue basis in the accompanying financial statements. The Company’s natural gas and crude oil marketing customers are invoiced based on contractually agreed upon terms on a monthly basis. Revenue is recognized in the month in which the physical product is delivered to the customer. Where required, the Company also 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.

Customers of the Company’s petroleum products marketing subsidiary are invoiced and revenue is recognized in the period when the customer physically takes possession and title to the product upon delivery at their facility. 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 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. The gross proceeds included in revenues and the gross costs included in marketing costs and expenses typically constitute approximately 35 percent of marketing revenues and costs. The Company believes its accounting treatment is consistent with the normal purchase and sale presentation under SFAS No. 133 as amended by SFAS No. 137 and No. 138. See discussion under “Price Risk Management Activities” below. In September 2005, the Emerging Issues Task Force (“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 entered into after March 31, 2006. If this requirement had been effective for the three and nine months ended September 30, 2005 and 2004, reported crude oil gathering and marketing revenues from unrelated parties and reported crude oil costs from unrelated parties would be reduced by the amounts shown on parenthetical notations on the consolidated statements of operations. Management does not expect that the adoption of Issue 04-13 will have a material effect on the Company’s financial position, results of operations or cash flows.

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 and three-month periods ended September 30, 2005 and 2004. There were no potentially dilutive securities during the same period in 2005 and 2004.

 
6
 

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, income taxes, contingencies and price risk management activities.


Price Risk Management Activities

SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, 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 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, 2005 is $456,000, all of which will be received during the remainder of 2005 through July 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 periods ended September 30, 2005 and 2004 (in thousands):

 
7
 


   
2005
  
2004
  
Net fair value on January 1, 
  
$
630
  
$
692
  
Activity during the period
              
-Cash paid (received) from settled contracts  
    
(890
)
  
(720
)
-Net realized gain from prior years’ contracts 
    
308
    
126
  
-Net unrealized (loss) from prior years’ contracts 
    
-
    
(30
)
-Net unrealized gain from prior years’ contracts 
    
5
    
-
  
-Net unrealized gain from current year contracts 
    
403
    
652
  
Net fair value on September 30, 
  
$
456
  
$
720
  

Asset Retirement Obligations

On January 1, 2003, the Company adopted SFAS No. 143 “Accounting for Asset Retirement Obligations.” The objective of SFAS No. 143 is to establish 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):

   
2005
  
2004
  
           
Balance on January 1, 
  
$
723
  
$
706
  
-Liabilities incurred 
    
23
    
19
  
-Accretion of discount 
    
57
    
38
  
-Liabilities settled 
    
(97
)
  
-
  
-Revisions to estimates 
    
-
    
-
  
Balance on September 30, 
  
$
706
  
$
763
  

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.

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, 2005, the Company had no stock-based employee compensation plans, nor any other share-based payment arrangements.

On November 30, 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). This statement 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 is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The adoption of this statement is not expected to have any material effect on the Company’s financial position, results of operations or cash flows.

 
8
 

In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets an amendment of APB Opinion No. 29”. This Statement amends Opinion 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. The Statement specifies that a nonmonetary exchange have commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. This Statement is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The Company adopted SFAS No. 153 effective July 1, 2005. The adoption of SFAS No. 153 did not have a material impact on the Company’s 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 pipeline was sold for $550,000 in cash, plus assumption of future abandonment obligations. The Company recognized a $451,000 pre-tax gain from the sale. The operating results for the pipeline have been reflected in the accompanying Unaudited Condensed Consolidated Statements of Operations as Income from Discontinued Operations. As of September 30, 2005, the Company has no assets or liabilities associated with this former operation.

Activities associated with the pipeline were previously included in marketing segment results. In the accompanying Unaudited Condensed Consolidated Statements of Operations, certain prior year balances were reclassified to conform to the current year presentation of discontinued operations. Assets and liabilities attributed to the pipeline were not reclassified to net assets from discontinued operations because such amounts were not significant.  

During 2003, management decided to withdraw from its New England region retail natural gas marketing business, which was included in the marketing segment. This business had negative operating margins of $279,000 and after tax losses totaling $253,000 for the three months ended March 31, 2004. Because of the losses sustained during 2002 and 2003, and the desire to reduce working capital requirements, management decided to exit this region and type of account. As of March 31, 2004, the Company had completed its exit from this business.

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):

 
9
 


       
Segment
  
Depreciation
  
Property and
  
       
Operating
  
Depletion and
  
Equipment
  
   
Revenues
  
Earnings
  
Amortization
  
Additions
  
For the nine months ended
                          
September 30, 2005
                          
Marketing 
  
$
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
  
For the nine months ended
                          
September 30, 2004
                          
Marketing 
  
$
1,464,167
  
$
9,729
  
$
875
  
$
260
  
Transportation 
    
34,696
    
3,716
    
1,679
    
2,444
  
Oil and gas 
    
8,078
    
2,169
    
1,584
    
3,557
  
   
$
1,506,941
  
$
15,614
  
$
4,138
  
$
6,261
  
For the three months ended
                          
September 30, 2005
                          
Marketing 
  
$
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
  
For the three months ended
                          
September 30, 2004
                          
Marketing 
  
$
534,875
  
$
6,070
  
$
297
  
$
79
  
Transportation
    
12,546
    
1,609
    
545
    
441
  
Oil and gas 
    
2,972
    
1,021
    
574
    
2,000
  
   
$
550,393
  
$
8,700
  
$
1,416
  
$
2,520
  

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

   
September 30,
  
December 31,
  
   
2005
  
2004
  
Marketing 
  
$
242,614
  
$
178,691
  
Transportation 
    
22,718
    
22,308
  
Oil and gas 
    
16,819
    
15,354
  
Other 
    
28,131
    
22,501
  
   
$
310,282
  
$
238,854
  

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):

 
10
 


   
Nine months ended
  
Three months ended
  
   
September 30,
  
September 30,
  
   
2005
  
2004
  
2005
  
2004
  
Segment operating earnings 
  
$
20,835
  
$
15,614
  
$
9,028
  
$
8,700
  
- General and administrative
    
(6,494
)
  
(5,574
)
  
(1,959
)
  
(2,120
)
Operating earnings 
    
14,341
    
10,040
    
7,069
    
6,580
  
- Interest income 
    
116
    
39
    
57
    
12
  
- Interest expense 
    
(80
)
  
(78
)
  
(28
)
  
(17
)
Earnings from continuing operations
                          
before income taxes 
  
$
14,377
  
$
10,001
  
$
7,098
  
$
6,575
  


Note 5 - Marketing Joint Venture

Commencing in May 2000, the Company entered into a joint venture arrangement with a third party for the purpose of purchasing, distributing and marketing crude oil in the offshore Gulf of Mexico region. The intent behind the joint venture was to combine the Company’s marketing expertise with stronger financial and credit support from the co-venture participant. The venture operated as Williams-Gulfmark Energy Company pursuant to the terms of a joint venture agreement. The Company held a 50 percent interest in the operations of the venture and accounted for its interest under the equity method of accounting.

Effective November 1, 2001, the joint venture participants agreed to dissolve the venture pursuant to the terms of a joint venture dissolution agreement. Subsequently, in April 2003, the Company received a demand for arbitration seeking monetary damages and a re-audit of the joint venture activity for the period of its existence from May 2000 through October 2001. In July 2004, the Company and the joint venture co-participant settled all matters arising from this dispute. As a condition of the settlement, the Company assumed full responsibility for the final wind-down and settlement of open trade account items arising from the joint venture’s former activities. As a further term of settlement, the Company was relieved from any cash obligations otherwise due to the joint venture. In connection with the resolution of the dispute, the Company recorded $1,476,000 of operating income as a reduction of marketing costs and expenses during the third quarter of 2004.

The Company continues to implement the final wind-down and settlement of open trade account items. As the venture either collects or funds cash proceeds in settlement of such accounts, the Company will receive or pay the entire balance of such cash proceeds or requirements.

Note 6 - 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 tend to result after the Company has first identified oil and gas prospects of interest. Due to capital budgeting constraints, 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. Such related party transactions are individually reviewed and approved by a committee of independent directors on the Company’s Board of Directors. As of September 30, 2005, the Company owed a combined net total of $364,874 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 $122,000 during the first nine months of 2005.

 
11
 

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 7 - 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 8 - 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, 2005 are as follows (in thousands):

   
2005
  
2006
  
2007
  
2008
  
2009
  
Thereafter
  
Total
  
Lease residual values
  
$
-
  
$
150
  
$
-
  
$
304
  
$
1,475
  
$
704
  
$
2,633
  

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, 2005, the maximum amount of such potential obligation is approximately $644,000. Management of the Company believes its customers will adhere to their branding obligations and no such refunds will result.

 
12
 

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 Interpretation No. 45.

Adams Resources & Energy, Inc. frequently issues parent guarantees of commitments resulting from the ongoing activities of its subsidiary companies. The guarantees generally result as incident to 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, all such underlying obligations are recorded on the books of the subsidiary companies and are included in the consolidated financial statements included herein. Therefore, no such obligation is recorded again on the books of the parent. The parent would only be called upon to perform under the guarantee in the event of a payment default by the applicable subsidiary company. In satisfying such obligations, the parent would first look to the assets of the defaulting subsidiary company. As of September 30, 2005, the amount of parental guaranteed obligations are as follows (in thousands):


   
2005
  
2006
  
2007
  
2008
  
2009
  
Thereafter
  
Total
  
Bank debt 
  
$
-
  
$
1,434
  
$
5,738
  
$
4,303
  
$
-
  
$
-
  
$
11,475
  
Operating leases 
    
1,113
    
4,046
    
3,748
    
3,549
    
1,226
    
448
    
14,130
  
Lease residual values 
    
-
    
150
    
-
    
304
    
1,475
    
704
    
2,633
  
Commodity purchases 
    
44,797
    
-
    
-
    
-
    
-
    
-
    
44,797
  
Letters of credit 
    
36,171
    
-
    
-
    
-
    
-
    
-
    
36,171
  
   
$
82,081
  
$
5,630
  
$
9,486
  
$
8,156
  
$
2,701
  
$
1,152
  
$
109,206
  

Note 9 - Restatement

Subsequent to the issuance of its unaudited condensed consolidated financial statements for the three and nine month periods ended September 30, 2005, the Company determined that, due to a clerical error, total revenues and total costs and expenses within the Company’s Marketing segment for the three and nine month periods ended September 30, 2005 were both overstated by approximately $157,610,000. The sales and costs items involved were attributable to physical crude oil movements involving third parties. Under the requirements of SFAS No. 133 as amended by SFAS No. 137 and No. 138, the Company is required to report on a net basis, those sales and purchases of crude oil that do not qualify as “normal purchases and sales” under the accounting standards. As a result, the accompanying unaudited financial statements have been restated from the amounts previously reported to reflect the correct amount of revenue netted against costs. The restatement had no effect on the Company’s previously reported operating income, net income, earnings per share, retained earnings or cash flows for the quarter ended September 30, 2005.

A summary of the effects of the restatement is as follows (in thousands):


   
Nine Months Ended
  
Three Months Ended
  
   
September 30, 2005
  
September 30, 2005
  
   
As Previously
      
As Previously
      
   
Reported
  
As Restated
  
Reported
  
As Restated
  
Revenues:
                          
Marketing
  
$
1,812,195
  
$
1,654,585
  
$
776,005
  
$
618,395
  
Costs and expenses:
                          
Marketing
  
$
1,799,224
  
$
1,641,614
  
$
769,780
  
$
612,170
  
                           
                           

 
13
 

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

The following management discussion and analysis gives effect to the restatement discussed in Note (9) of Notes to the Unaudited Consolidated Financial Statements

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,
  
   
2005
  
2004
  
2005
  
2004
  
       
Revenues 
  
$
1,654,585
  
$
1,464,167
  
$
618,395
  
$
534,875
  
                           
Operating earnings 
  
$
12,019
  
$
9,729
  
$
5,914
  
$
6,070
  
                           
Depreciation 
  
$
952
  
$
875
  
$
311
  
$
297
  
                           
 

Supplemental volume and price information is as follows:

   
Nine Months Ended
  
Three Months Ended
  
   
September 30,
  
September 30,
  
   
2005
  
2004
  
2005
  
2004
  
                   
Wellhead Purchases - Per day (1)
                          
                           
Crude oil - barrels 
    
67,600
    
75,900
    
63,000
    
75,700
  
                           
Natural gas - mmbtu’s  
    
299,000
    
300,000
    
269,000
    
274,000
  
                           
Average Purchase Price
                          
                           
Crude Oil - per barrel 
  
$
52.21
  
$
37.62
  
$
59.72
  
$
42.06
  
                           
Natural Gas - per mmbtu 
  
$
7.01
  
$
5.57
  
$
8.53
  
$
5.44
  

_____________________________

(1) Reflects the volume purchased from third parties at the wellhead level.

 
14
 

Commodity purchases and sales associated with the Company’s natural gas marketing activities qualify as derivative instruments under 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”) 02-3 “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities”. In contrast, substantially all purchases and sales of crude oil qualify, and have been designated as, normal purchases and sales. Therefore, crude oil purchases and sales are recorded on a gross revenue basis in the accompanying financial statements. As a result, variations in gross revenues are primarily a function of crude oil volumes and prices while operating earnings fluctuate with both crude oil and natural gas margins and volumes.

Marketing revenues increased by $190,418,000 to $1,654,585,000 for the comparative first nine months of 2005. As reflected in the table above, this increase was directly attributable to crude oil price increases partially offset by a reduced volume of activity. During the current nine-month period, marketing operating earnings increased by $2,290,000 to $12,019,000. The current operating earnings increase resulted from a number of factors including the Company liquidating relatively lower priced crude oil inventory into a higher priced market. This action produced a $3,700,000 gain during the first nine months of 2005 as average crude oil prices rose from the $43 per barrel range in December 2004 to the $62 per barrel range in September 2005. A similar, but less dramatic, pricing situation occurred during last year when the Company gained $2,300,000 from inventory liquidations. As of September 30, 2005, the Company held 188,000 barrels of crude oil inventory valued at $62.37 per barrel.

Other factors affecting nine-month comparison included the impact of typically non-recurring items. During the first nine months of 2005, the Company has recognized $1,080,000 of cash collected on previously disputed and fully reserved items and the Company has also realized a $415,000 gain on the sale of used equipment. In comparison, during the first nine months of 2004, the Company recognized as income $1,476,000 from settlement of a dispute associated with the Company’s previous joint venture, plus $430,000 of cash on previously disputed and fully reserved items in addition to a $157,000 gain on sale of used equipment. Aside from these factors and the inventory gains during 2005, the Company has generally seen improved margins as crude oil and natural gas have been in short supply. Most notably, the Company’s natural gas marketing efforts have generated improved operating margins by $1,115,000 for the comparative current nine-month period.

For the comparative third quarter of 2005, marketing revenues increased by 45 percent to $618,395,000 as a result of crude oil price increases. In contrast, operating earnings were consistent for the periods at $5.9 million and $6.1 million for the third quarter of 2005 and 2004, respectively. Excluding the impact on inventory liquidation gains, increased crude oil prices had little effect on comparative third quarter results. Inventory gains totaled $1,400,000 during the third quarter of 2005 as compared to $1,573,000 in last year’s third quarter.

 
-
Transportation

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

   
Nine Months Ended
      
Three Months Ended
      
   
September 30,
      
September 30,
  
Increase
  
   
2005
  
2004
  
Increase
  
2005
  
2004
  
(Decrease)
  
                                       
Revenues 
  
$
41,765
  
$
34,696
    
20
%
$
13,867
  
$
12,546
    
11
%
                                       
Operating earnings 
  
$
4,225
  
$
3,716
    
14
%
$
1,231
  
$
1,609
    
(23)
%
                                       
Depreciation 
  
$
2,139
  
$
1,679
    
27
%
$
822
  
$
545
    
51
%


 
15
 

Beginning in April 2004, the Company experienced increased demand for its petrochemical trucking services. This demand surge continued during the remainder of 2004 and has generally remained strong during 2005. The demand increase boosted comparative nine-month 2005 revenues by 20 percent to $41,765,000. Increased revenues improved operating earnings by 14 percent to $4,225,000 for the first nine months of 2005. The rate of increase in operating earnings did not keep pace with the rate of increase for revenues. This situation resulted because of increased operating expenses during the current period including an increased provision for doubtful accounts, increased depreciation expenses and increased fuel charges. A $218,000 provision was added to the allowance for doubtful accounts to accommodate certain older items of collection that remain outstanding. As a result of equipment additions during 2005 and late 2004, depreciation expense increased by $460,000 or 27 percent in the current period. For fuel costs, the current increase was 52 percent or $2,444,000 relative to the same period last year. The fuel escalation resulted from a combination of higher prices and increased mileage. Management cannot predict whether such fuel cost trends will continue.

For the current quarterly comparison, although third quarter 2005 revenues increased 11 percent to $13,867,000, the items of cost increase, noted above, offset such improvement. In addition, during the third quarter of 2004, the transportation segment recognized a $254,000 gain from the sale of used trucks. Such gains did not occur in the same period in 2005.

 
- 
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,
  
   
2005
  
2004
  
Increase
  
2005
  
2004
  
Increase
  
Revenues 
  
$
10,495
  
$
8,078
    
30
%
$
4,745
  
$
2,972
    
60
%
                                       
Operating earnings 
  
$
4,591
  
$
2,169
    
112
%
$
1,883
  
$
1,021
    
84
%
                                       
Depreciation and depletion 
  
$
2,022
  
$
1,584
    
28
%
$
590
  
$
574
    
3
%

For the comparative nine-month period ended September 30, 2005, oil and gas revenues and operating earnings improved by 30 percent and 112 percent to $10,495,000 and $4,591,000, respectively. Such improvement resulted primarily from increased commodity prices for both crude oil and natural gas as shown in the table below.
The revenue increase served to boost the first nine months of 2005 operating earnings. Additionally, 2005 operating earnings benefited from a $601,000 gain from the sale of certain oil and gas properties when, during the first quarter of 2005, the Company sold its interest in twelve onshore wells located in Calcasieu Parish, Louisiana. This sale was completed at attractive pricing and to eliminate the liability for plugging and abandonment costs on twenty-five currently non-producing wells on the property. The Company held a less than three percent working interest in each of such wells. The Company retained its interest in certain other Calcasieu Parish producing properties. Results for the first nine months of 2005 also included $2,240,000 of exploration expense as compared to $2,029,000 incurred exploration expense in the nine-month 2004 period. Exploration expense in 2005 included $1,157,000 of dry hole cost, $485,000 for geological and geophysical costs and a $313,000 impairment provision on non-producing properties. The provision for depreciation and depletion was increased during the first nine months of 2005 due to the unexpected cessation of production on three separate properties. As a result, during the second quarter of 2005, the provision was increased to fully amortize the remaining carrying cost on such properties.

 
16
 

Oil and gas revenues and operating earnings increased 60 percent and 84 percent to $4,745,000 and $1,883,000, respectively for the comparative third quarter of 2005. Such improvements were primarily attributed to increased prices and production sales volumes for natural gas. Average natural gas prices rose 22 percent to $8.23 per mcf while natural gas volumes rose 32 percent to 432,000 mcf for the 2005 third quarter. See table below.

Production volumes and price information is as follows:

   
Nine Months Ended
  
Three Months Ended
  
   
September 30,
  
September 30,
  
   
2005
  
2004
  
2005
  
2004
  
Crude Oil
                          
                           
Volume - barrels 
    
51,300
    
54,400
    
19,700
    
19,200
  
                           
Average price per barrel 
  
$
53.09
  
$
37.48
  
$
59.99
  
$
40.71
  
                           
Natural gas
                          
                           
Volume - mcf 
    
1,048,000
    
997,000
    
432,000
    
327,000
  
                           
Average price per mcf 
  
$
7.41
  
$
6.06
  
$
8.23
  
$
6.71
  

During the first nine months of 2005, the Company participated in the drilling of twenty-four wells. Fifteen of the wells were successful with seven dry holes and two wells spud in September 2005 are currently in process. In addition, six wells that were in process at year-end 2004 were successfully brought on production in the first quarter of 2005. Participation in the drilling of approximately 10 wells is planned for the remainder of 2005 on the Company’s prospect acreage in Alabama, Louisiana and Texas.

Of note, based on log analysis, one well in Alabama was successfully drilled to the Smackover formation during the third quarter of 2005. Testing of this well is currently in process and the well is expected to be brought on production in November 2005. A second well on this prospect was spud in the fourth quarter of 2005 and is currently drilling. If this second well is also successful, a number of additional wells will be drilled on the Alabama acreage in 2006.

In the Southern and Central UK North Sea, the Company and its joint interest partners continue to evaluate and reprocess purchased seismic data. The reprocessing on our Central North Sea Block was completed but a partner could not be found prior to the two-year license expiration period. Although the block was relinquished, the Company continues to pursue a partner in hopes of being awarded the block a second time in a future licensing round. Seismic interpretation work continues on the Southern North Sea Block and the Company anticipates the completion of a prospect package by early 2006. Both acreage positions are “Promote Blocks” that do not require a commitment to drill a well. The Company plans to seek a partner to drill the initial wells on a promoted basis. The Company holds a 40 percent interest in the Southern sector block.

 
17
 

-General and administrative and income tax

General and administrative expenses increased in the first nine months of 2005 due to accounting compliance costs totaling $888,000, of which $248,000 was incurred during the third quarter of 2005. The cost increase results from the use of consultants to assist in the implementation of accounting procedure documentation as required by The Sarbanes-Oxley Act of 2002. Based on the Company’s current market capitalization, the Company is required to be fully Sarbanes compliant as of December 31, 2007. The Company has undertaken to complete the procedures documentation phase of such project during 2005. Administrative expenses also increased as a result of increased employee salary costs. 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.


- 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 pipeline was sold for $550,000 in cash, plus assignment of future abandonment obligations. The Company recognized a $451,000 pre-tax gain from the sale. The activities for this operation including the gain on sale are included with discontinued operations.

During 2003, management decided to withdraw from its New England region retail natural gas marketing business. Because of the losses sustained and the desire to reduce working capital requirements, management decided to exit this region and type of account. An orderly withdrawal from the region was instituted in 2003 and as of March 31, 2004, the Company had completed its exit from this business.

-Outlook

Within the marketing operation, a continuation of inventory liquidation gains is not expected. However, stable and profitable marketing activities are anticipated for the remainder for this year. Strong results from transportation also appear to be holding steady for 2005. For the oil and gas segment, prices have remained strong and the level of earnings generated by ongoing oil and gas production levels should continue.


Liquidity and Capital Resources 

During the first nine months of 2005, net cash provided by operating activities totaled $12,159,000 versus $1,238,000 of net cash used by operations during the first nine months of 2004. 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.

 
18
 

A summary of this relationship follows (in thousands):
   
Nine Months Ended
  
   
September 30,
  
     
2005
    
2004
  
Earnings from continuing operations 
  
$
9,755
  
$
6,558
  
Depreciation, depletion and amortization 
    
5,113
    
4,138
  
Property and equipment additions 
    
(8,415
)
  
(6,261
)
               
Cash available for other uses  
  
$
6,453
  
$
4,435
  

Capital expenditures during the first nine months of 2005 included $244,000 for marketing equipment additions, $3,836,000 for tractor and trailer purchases within the transportation operation and $4,335,000 in property additions associated with oil and gas exploration and production activities. For the remainder of 2005, the Company anticipates spending approximately $3 million on oil and gas exploration projects to be funded from operating cash flow and available working capital. In addition, approximately $5 million will be expended toward the purchase of 65 truck-tractors of which 50 are replacements and 15 reflect additions to the fleet. Funding for the truck purchases will come from existing available cash or alternatively from lease financing.


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 $10,000,000 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, 2005 was established at $10,000,000. 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 $10,000,000 as of September 30, 2005. The line of credit loans are scheduled to expire on October 31, 2006, with the then present balance outstanding converting to a term loan payable in eight equal quarterly installments. As of September 30, 2005, bank debt outstanding under the Company’s two revolving credit facilities totaled $11,475,000.

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 $42,955,000. 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, 2005.

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 $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 1 percent. As of September 30, 2005, the Company had $6 million of eligible borrowing capacity under this facility. No working capital advances were outstanding as of September 30, 2005. Letters of credit outstanding under this facility totaled approximately $27.2 million as of September 30, 2005. BNP Paribas has the right to discontinue the issuance of letters of credit under this facility without prior notification to the Company.

 
19
 

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 1 percent. No working capital advances were outstanding under this facility as of September 30, 2005. Letters of credit outstanding under this facility totaled $9 million as of September 30, 2005. Under this facility, BNP Paribas has the right to discontinue the issuance of letters of credit 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.

1.  
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.

2.  
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 mismatch between reported earnings and cash flows. 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, 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.

 
20
 

- 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 (a) the volume of transactions, (b) the complexity of transactions and (c) 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 Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies”.

 
21
 

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, 2005 included $11,475,000 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, 2005. 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 six-month period ended June 30, 2005.

-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 6-month to 1-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 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, 2005 and 2004 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 $456,000, all of which will be received during the remainder of 2005 through July 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 six months ended September 30, 2005 and 2004 (in thousands):

   
2005
  
2004
  
Net fair value on January 1, 
  
$
630
  
$
692
  
Activity during the period
              
- Cash received from settled contracts 
    
(890
)
  
(720
)
- Net realized gain from prior years’ contracts 
    
308
    
126
  
- Net unrealized (loss) from prior years’contracts 
    
-
    
(30
)
- Net unrealized gain from prior years’ contracts  
    
5
    
-
  
- Net unrealized gain from current year contracts 
    
403
    
652
  
- Net fair value on September 30,  
  
$
456
  
$
720
  


 
22
 


Historically, prices received for oil and gas production have been volatile and unpredictable. Price volatility is expected to continue. From January 1, 2005 through September 30, 2005 natural gas price realizations ranged from a monthly low of $5.46 per mmbtu to a monthly high of $14.70 per mmbtu. Oil prices ranged from a low of $46.45 per barrel to a high of $64.40 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 $2,227,000 for the nine-month period ended September 30, 2005.

Forward-Looking Statements—Safe Harbor Provisions

This report for the period ended September 30, 2005 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, and (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, and (q) 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, 2004.

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.

In the course of preparing its financial statements for the year ended December 31, 2005, the Company’s accounting personnel detected, corrected and reported the error described in Note 9 of Notes to Unaudited Consolidated Financial Statements. Further, in accordance with Exchange Act Rules 13a-15 and 15d-15, the Company has re-evaluated, under the supervision and with the participation of management, including the Company’s Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of the Company’s disclosure controls and procedures as of the end of the period covered by this report. 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 are effective.

 
23
 

The Chief Executive Officer and Chief Financial Officer concluded that the clerical error resulting in the restatement was an isolated incident and did not result from poor design or a general breakdown in internal controls. In reaching this conclusion, management determined that the accounting error had no adverse effect on the Company’s previously reported operating income, net income, earnings per share, retained earnings or cash flows for the affected period which remained accurate as reported or on the Company’s conclusion that its disclosure controls and procedures were effective as reflected in the Company’s previously issued Form 10-Q for the quarter ended September 30, 2005. In any event, management concluded that the unaudited condensed consolidated financial statements for the quarter ended September 30, 2005 should be restated. Management does not believe that the amount of the restatement materially alters an informed understanding of the Company’s financial position or results of operations for the quarter ended September 30, 2005.

During the Company’s third fiscal quarter, there have not been any changes in the Company’s internal control 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.

 
24
 

PART II. OTHER INFORMATION
Item 1.

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.  

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
   


 
25
 


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: March 20, 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


 
26
 

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