UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
 Washington,
D.C. 20549
 
 FORM
10-K
 (Mark
One)
 X
    ANNUAL
      REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
      1934
 For
      the Fiscal Year ended December 31, 2004
 OR
 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
    (I.R.S.
      Employer Identification No.)Incorporation
      or organization)**4400
      Post Oak Parkway Ste. 2700****Houston,
      Texas**
    **77027**(Address
      of Principal executive offices)
    (Zip
      Code)
 
 Registrant's
telephone number, including area code: **(713) 881-3600**
 
 **Securities
registered pursuant to Section 12(b) of the Act: None**
 
 Title
      of each class
    Name
      of each exchange on which registered**Common
      Stock, $.10 Par Value**
    **American
      Stock Exchange**
 
 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 the filing requirements for
the past 90 days. YES X NO
_____
 
 Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
 
 Indicate
by check mark whether the registrant is an accelerated filer as defined in Rule
126-b of the Act. YES____NO X
 
 The
aggregate market value of the voting stock held by nonaffiliates as of June 30,
2004 was $30,630,932. A total of 4,217,596 shares of Common Stock were
outstanding at March 10, 2005.
 
 
 **DOCUMENTS
INCORPORATED BY REFERENCE**
 
 Portions
of the Proxy Statement for Annual Meeting of Stockholders to be held May 18,
2005 are incorporated by reference in Part III.
 
  
  PART I
 
 
 Items 1
and 2. BUSINESS AND PROPERTIES
 
 Adams
Resources & Energy, Inc. and its subsidiaries (the "Company") are 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. Adams Resources & Energy, Inc. is a Delaware corporation
organized in 1973. The Company’s website is www.adamsresources.com . The
Company makes its reports, including Forms 10-K, Forms 10-Q, Forms 8-K and all
amendments thereto, available on its website as soon as reasonably practicable
after filing with the Securities and Exchange Commission. The revenues,
operating results and identifiable assets of each industry segment for the three
years ended December 31, 2004 are set forth in Note (10) of Notes to
Consolidated Financial Statements included elsewhere herein.
 
 Crude
Oil, Natural Gas and Refined Products Marketing
 
 The
Company’s subsidiary, Gulfmark Energy, Inc. (“Gulfmark”), purchases crude oil
and arranges sales and deliveries to refiners and other customers. Activity is
concentrated primarily onshore in Texas and Louisiana with additional operations
in Michigan. During 2004, Gulfmark purchased approximately 76,000 barrels per
day of crude oil at the wellhead or lease level. Gulfmark also operates 74
tractor-trailer rigs and maintains over 50 pipeline inventory locations or
injection stations. Gulfmark has the ability to barge oil from nine oil storage
facilities along the intercoastal waterway of Texas and Louisiana and maintains
200,000 barrels of storage capacity at certain of the dock facilities in order
to access waterborne markets for its products. Gulfmark arranges transportation
for sales to customers or enters into exchange transactions with third parties
when the cost of the exchange is less than the alternate cost incurred in
transporting or storing the crude oil. In addition, the Company owns and
operates a 7.5-mile long, six-inch diameter crude oil gathering pipeline in the
Louisiana offshore, Ship Shoal area.
 
 The
Company’s subsidiary, Adams Resources Marketing, Ltd. (“ARM”), operates as a
wholesale purchaser, distributor and marketer of natural gas. ARM’s focus is on
the purchase of natural gas at the producer level. ARM purchases approximately
294,000 mmbtu of natural gas per day at the wellhead and pipeline pooling
points. Business is concentrated among approximately 60 independent producers
with the primary production areas being the Louisiana and Texas Gulf Coast and
the offshore Gulf of Mexico region. ARM provides value added services to its
customers by providing access to common carrier pipelines and handling daily
volume balancing requirements as well as risk management services.
 
 Generally,
as the Company purchases crude oil and natural gas, it establishes a margin by
selling the product for physical delivery to third party users, such as
independent refiners, utilities and or major energy companies and other
industrial concerns. Through these transactions, the Company seeks to maintain a
position that is substantially balanced between commodity purchase volumes
versus sales or future delivery obligations. Crude oil and natural gas are
generally purchased at indexed prices that fluctuate with market conditions. The
product is transported and either sold outright at the field level, or buy-sell
arrangements (trades) are made in order to minimize transportation costs or
maximize the sales price. Except where matching fixed price arrangements are in
place, the contracted sales price is also tied to an index that fluctuates with
market conditions. This reduces the Company's loss exposure from sudden changes
in commodity prices. A key element of profitability is the differential between
market prices at the field level and at the various sales points. Such price
differentials vary with local supply and demand conditions. Unforeseen
fluctuations can impact financial results either favorably or unfavorably. While
the Company's policies are designed to minimize market risk, some degree of
exposure to unforeseen fluctuations in market conditions remains.
 
 Operating
results are sensitive to a number of factors. Such factors include commodity
location, grades of product, individual customer demand for grades or location
of product, localized market price structures, availability of transportation
facilities, actual delivery volumes that vary from expected quantities and
timing and costs to deliver the commodity to the customer. The term “basis risk”
is used to describe the inherent market price risk created when a commodity of a
certain location or grade is purchased, sold or exchanged versus a purchase,
sale or exchange of a like commodity of varying location or grade. The Company
attempts to reduce its exposure to basis risk by grouping its purchase and sale
activities by geographical region in order to stay balanced within such
designated region. However, there can be no assurance that all basis risk is or
will be eliminated.
 
 The
Company’s subsidiary, Ada Resources, Inc. (“Ada”), markets branded and unbranded
refined petroleum products, such as motor fuels and lubricants. Ada makes
purchases based on the supplier’s established distributor prices, with such
prices generally being lower than the Company’s sales price to its customers.
Motor fuel sales include automotive gasoline, aviation gasoline, distillates and
jet fuel. Lubricants consist of passenger car motor oils as well as a full
complement of industrial oils and greases. Ada is also involved in the railroad
servicing industry, including fueling and lubricating locomotives as well as
performing routine maintenance on the power units. Further, the United States
Coast Guard has certified Ada as a direct-to-vessel approved marine fuel and
lube vendor. Ada’s marketing area primarily includes the Texas Gulf Coast and
southern Louisiana. The primary product distribution and warehousing facility is
located on 5.5 Company-owned acres in Houston, Texas. The property includes a
60,000 square foot warehouse, 11,000 square feet of office space and bulk
storage for 280,000 gallons of lubricating oil.
 
 Tank
Truck Transportation
 
 The
Company’s subsidiary, Service Transport Company (“STC”), transports liquid
chemicals on a "for hire" basis throughout the continental United States and
Canada. Transportation service is provided to over 400 customers under contracts
and on a call and demand basis. Pursuant to regulatory requirements, STC holds a
Hazardous Materials Certificate of Registration issued by the U.S. Department of
Transportation. Presently, STC operates 275 truck tractors and 360 tank trailers
and maintains truck terminals in Houston, Corpus Christi, and Nederland, Texas
as well as Baton Rouge (St. Gabriel), Louisiana, Mobile (Saraland), Alabama and
Atlanta (Winder), Georgia. Transportation operations are headquartered at a
Houston terminal facility situated on 22 owned acres and includes maintenance
facilities, an office building, tank wash rack facilities and a water treatment
system. The St. Gabriel, Louisiana terminal is situated on 11.5 owned acres and
includes an office building, maintenance bays and tank cleaning
facilities.
 
 STC has
maintained its registration to the ISO 9001:2000 Standard. The scope of this
Quality System Certificate, registered in both the United States and Europe,
covers the carriage of bulk liquids throughout the Company’s area of operations
as well as the tank trailer cleaning facilities and equipment maintenance. STC’s
quality management process is one of its major assets. The practice of using
statistical process control covering safety, on-time performance and customer
satisfaction aids continuous improvement in all areas of quality service. In
addition to its ISO 9001:2000 certification, the American Chemistry Council
recognizes STC as a Responsible Care Ó Partner.
Responsible Care Ó Partners
are those companies that serve the chemical industry and implement and monitor
the seven Codes of Management Practices. The seven codes address compliance and
continuing improvement in (1) Community Awareness and Emergency Response, (2)
Pollution Prevention, (3) Process Safety, (4) Distribution, (5) Employee Health
and Safety, (6) Product Stewardship and (7) Security.
 
 Oil and
Gas Exploration and Production
 
 The
Company’s subsidiary, Adams Resources Exploration Corporation, is actively
engaged in the exploration and development of domestic oil and gas properties
primarily along the Louisiana and Texas Gulf Coast. Exploration offices are
maintained at the Company's headquarters in Houston and the Company holds an
interest in 344 wells, of which 44 are Company-operated.
 
 Producing
Wells --The
following table sets forth the Company's gross and net productive wells at
December 31, 2004. Gross wells are the total number of wells in which the
Company has an interest, while net wells are the sum of the fractional interests
owned.
 
 Oil
      Wells
    
    Gas
      Wells
    
    Total
      WellsGross
    
    Net
    
    Gross
    
    Net
    
    Gross
    
    NetTexas
    
    
    66
    
    
    14.25
    
    
    72
    
    
    7.91
    
    
    138
    
    
    22.16Louisiana
    
    
    44
    
    
    1.52
    
    
    31
    
    
    3.64
    
    
    75
    
    
    5.16Other
    
    
    89
    
    
    1.81
    
    
    42
    
    
    6.46
    
    
    131
    
    
    8.27199
    
    
    17.58
    
    
    145
    
    
    18.01
    
    
    344
    
    
    35.59
 
  1
  Acreage --The
following table sets forth the Company's gross and net developed and undeveloped
acreage as of December 31, 2004. Gross acreage represents the Company’s direct
ownership and net acreage represents the sum of the fractional interests
owned.
 
 Developed
      Acreage
    
    Undeveloped
      AcreageGross
    
    Net
    
    Gross
    
    NetTexas
    
    
    62,489
    
    
    11,316
    
    
    74,640
    
    
    8,624Louisiana
    
    
    6,633
    
    
    652
    
    
    7,923
    
    
    356Other
    
    
    3,862
    
    
    707
    
    
    3,703
    
    
    1,74972,984
    
    
    12,675
    
    
    86,266
    
    
    10,729
 
 Drilling
Activity --The
following table sets forth the Company's drilling activity for each of the three
years ended December 31, 2004. All drilling activity was onshore in Texas and
Louisiana.
 
 2004
    
    2003
    
    2002Gross
    
    Net
    
    Gross
    
    Net
    
    Gross
    
    NetExploratory
      wells drilled-
      Productive
    
    
    12
    
    
    .59
    
    
    7
    
    
    .49
    
    
    1
    
    
    .10-
      Dry
    
    
    6
    
    
    .44
    
    
    11
    
    
    1.03
    
    
    4
    
    
    1.08Development
      wells drilled-
      Productive
    
    
    8
    
    
    .42
    
    
    16
    
    
    1.42
    
    
    12
    
    
    .99-
      Dry
    
    
    1
    
    
    .01
    
    
    1
    
    
    .20
    
    
    4
    
    
    .22
 
 In
addition to the above wells drilled and completed, at year-end 2004, the Company
had six wells in process, which were successfully completed in
2005.
 
 Production
and Reserve Information --The
Company's estimated net quantities of proved oil and gas reserves, the estimated
future net cash flows and present value of future net cash flows from oil and
gas reserves before income taxes, calculated at a 10% discount rate for the
three years ended December 31, 2004, are presented in the table below (in
thousands).
 
 December
      31,2004
    
    2003
    
    2002Crude
      oil (barrels)
    
    
    436
    
    
    438
    
    
    579Natural
      gas (mcf)
    
    
    10,950
    
    
    8,971
    
    
    7,480Future
      net cash flows before income taxes
    
    $
    62,312
    
    $
    46,186
    
    $
    31,385Present
      value of future net cash flows beforeincome
      taxes
    
    $
    34,541
    
    $
    27,835
    
    $
    16,728
 
 Approximately
ninety-five percent of the value of estimated oil and gas reserves and future
net revenues from oil and gas reserves were made by the Company's independent
petroleum engineers. The remaining reserve values were determined by the
Company’s in-house licensed engineers. The reserve value estimates provided at
December 31, 2004, 2003 and 2002 are based on year-end market prices of $40.50,
$30.15 and $27.94 per barrel for crude oil and $6.06, $5.71 and $4.20 per mcf
for natural gas, respectively.
 
 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, the current prices being received and reservoir engineering
data, 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 is made
available through drilling, testing, reservoir studies and acquiring historical
pressure and production data. In addition, the discounted present value of
estimated future net revenues should not be construed as the fair market value
of oil and gas producing properties. Such estimates do not necessarily portray a
realistic assessment of current value or future performance of such properties.
Such revenue calculations are based on estimates 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 have been
made with respect to pricing. The 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's oil and gas production for the three years ended December 31, 2004 was
as follows:
 
 Years
      Ended
    
    Crude
      Oil
    
    NaturalDecember
      31,
    
    (barrels)
    
    Gas
      (mcf)2004
    
    
    71,300
    
    
    1,309,0002003
    
    
    61,900
    
    
    1,239,0002002
    
    
    55,000
    
    
    1,047,000
 
 Certain
financial information relating to the Company's oil and gas activities is
summarized as follows:
 
 
 Years
      Ended December 31,2004
    
    2003
    
    2002Average
      oil and condensateSales
      price per barrel
    
    $
    39.48
    
    $
    30.67
    
    $
    26.10Average
      natural gasSales
      price per mcf
    
    $
    6.09
    
    $
    5.23
    
    $
    3.17Average
      production cost, per equivalentBarrel,
      charged to expense
    
    $
    10.30
    
    $
    8.48
    
    $
    9.10
 
 For
comparative purposes, prices received by the Company’s oil and gas division at
varying points in time during 2004 were as follows:
 
 Crude
      Oil
    
    Natural
      GasAverage
      Annual Price for 2004
    
    $
    39.48
    
    $
    6.09Average
      Price for December 2004
    
    $
    41.65
    
    $
    6.80Price
      at December 31, 2004
    
    $
    40.50
    
    $
    6.06
 
 The
Company has had no reports to federal authorities or agencies of estimated oil
and gas reserves except for a required report on the Department of Energy’s
“Annual Survey of Domestic Oil and Gas Reserves.” The Company is not obligated
to provide any fixed and determinable quantities of oil or gas in the future
under existing contracts or agreements associated with its oil and gas
exploration and production segment.
 
 North
Sea Exploration Licenses —In the
Central UK and Southern UK sectors of the North Sea, the Company holds an
undivided 25% working interest in Block 21-1b and a 33-1/3% working interest in
Block 48/16c, respectively. Together with its joint interest partners, the
Company obtained its interests through the United Kingdom’s “Promote License”
program. The Block 21-1b license was awarded in October 2003 while the Block
48/16c license was officially awarded in February 2005. A Promote License
affords the opportunity to analyze and assess the licensed acreage for an
initial two-year period without the stringent financial requirements of the more
traditional Exploration License. The two-year licensing period also provides
sufficient time to promote the actual drilling of a well to potential third
party investors. For each block, the Company and its joint interest partners
expect to confirm the existence of an exploration prospect that will be promoted
to other investors prior to drilling. The 21-1b Block is located approximately
200 miles east of Aberdeen, Scotland not far from the Forties and Buchan Fields.
The 48/16c Block covers in excess of 20,000 acres and is located approximately
40 miles east of Theddlethorpe, England in approximately 80 feet of water. None
of the Company’s joint interest partners are affiliates of the
Company.
 
 Reference
is made to Note (13) of the Notes to Consolidated Financial Statements for
additional disclosures relating to oil and gas exploration and production
activities.
 2
  
 The
Company is subject to an extensive variety of evolving United States federal,
state and local laws, rules and regulations governing the storage,
transportation, manufacture, use, discharge, release and disposal of product and
contaminants into the environment, or otherwise relating to the protection of
the environment. Presented below is a non-exclusive listing of the environmental
laws that potentially impact the Company’s activities. Also presented is
additional discussion about the regulatory environment of the Company.
 
 -
    The
      Solid Waste Disposal Act, as amended by the Resource Conservation and
      Recovery Act of 1976, as amended.
 -
    Comprehensive
      Environmental Response, Compensation and Liability Act of 1980 ("CERCLA"
      or "Superfund"), as amended.
 -
    The
      Clean Water Act of 1972, as amended.
 -
    Federal
      Oil Pollution Act of 1990, as amended.
 -
    The
      Clean Air Act of 1970, as amended.
 -
    The
      Toxic Substances Control Act of 1976, as
amended.
 -
    The
      Emergency Planning and Community Right-to-Know
Act.
 -
    The
      Occupational Safety and Health Act of 1970, as
amended.
 -
    Texas
      Clean Air Act.
 -
    Texas
      Solid Waste Disposal Act.
 -
    Texas
      Water Code.
 -
    Texas
      Oil Spill Prevention and Response Act of 1991, as amended.
 
 Railroad
Commission of Texas (“RRC”) --The RRC
regulates, among other things, the drilling and operation of oil and gas wells,
the operation of oil and gas pipelines, the disposal of oil and gas production
wastes and certain storage of unrefined oil and gas. RRC regulations govern the
generation, management and disposal of waste from such oil and gas operations
and provide for the clean up of contamination from oil and gas operations. The
RRC has promulgated regulations that provide for civil and/or criminal penalties
and/or injunctive relief for violations of the RRC regulations.
 
 Louisiana
Office of Conservation (“LOC”) --has
primary statutory responsibility for regulation and conservation of oil, gas,
and other natural resources. The Conservation’s objectives are to regulate the
exploration and production of oil, gas and other hydrocarbons; to control and
allocate energy supplies and distribution; and to protect public safety and the
State’s environment from oilfield waste, including regulation of underground
injection and disposal practices.
 
 State
and Local Government Regulation --Many
states are authorized by the Environmental Protection Agency (“EPA”) to enforce
regulations promulgated under various federal statutes. In addition, there are
numerous other state and local authorities that regulate the environment, some
of which impose more stringent environmental standards than federal laws and
regulations. The penalties for violations of state law vary, but typically
include injunctive relief, recovery of damages for injury to air, water or
property and fines for non-compliance.
 
 Oil
and Gas Operations --The
Company's oil and gas drilling and production activities are subject to laws and
regulations relating to environmental quality and pollution control. One aspect
of the Company's oil and gas operation is the disposal of used drilling fluids,
saltwater, and crude oil sediments. In addition, low-level naturally occurring
radiation may, at times, occur with the production of crude oil and natural gas.
The Company's policy is to comply with environmental regulations and industry
standards. Environmental compliance has become more stringent and the Company,
from time to time, may be required to remediate past practices. Management
believes that such required remediations in the future, if any, will not have a
material adverse impact on the Company's financial position or results of
operations.
 
 All
states in which the Company owns producing oil and gas properties have statutory
provisions regulating the production and sale of crude oil and natural gas.
Regulations typically require permits for the drilling of wells and regulate the
spacing of wells, the prevention of waste, protection of correlative rights, the
rate of production, prevention and clean-up of pollution and other matters.
 
 Marketing
Operations --The
Company's marketing facilities are subject to a number of state and federal
environmental statutes and regulations, including the regulation of underground
fuel storage tanks. While as of December 31, 2004, the Company does not own or
operate underground tanks, historically, the Company has been an owner and
operator of underground full storage tanks. The EPA's Office of Underground
Tanks and applicable state laws establish regulations requiring owners or
operators of underground fuel tanks to demonstrate evidence of financial
responsibility for the costs of corrective action and the compensation of third
parties for bodily injury and property damage caused by sudden and non-sudden
accidental releases arising from operating underground tanks. In addition, the
EPA requires the installation of leak detection devices and stringent monitoring
of the ongoing condition of underground tanks. Should leakage develop in an
underground tank, the operator is obligated for clean up costs. During the
period when the Company was an operator of underground tanks, it secured
insurance covering both third party liability and clean up costs.
 
 Transportation
Operations --The
Company's tank truck operations are conducted pursuant to authority of the
United States Department of Transportation (“DOT”) and various state regulatory
authorities. The Company's transportation operations must also be conducted in
accordance with various laws relating to pollution and environmental control.
Interstate motor carrier operations are subject to safety requirements
prescribed by the DOT. Such matters as weight and dimension of equipment are
also subject to federal and state regulations. DOT regulations also require
mandatory drug testing of drivers and require certain tests for alcohol levels
in drivers and other safety personnel. The trucking industry is subject to
possible regulatory and legislative changes such as increasingly stringent
environmental regulations or limits on vehicle weight and size. Regulatory
change may affect the economics of the industry by requiring changes in
operating practices or by changing the demand for common or contract carrier
services or the cost of providing truckload services. In addition, the Company’s
tank wash facilities are subject to increasingly more stringent local, state and
federal environmental regulations.
 
 The
Company has implemented security procedures for drivers and terminal facilities.
Satellite tracking transponders installed in the power units are used to
communicate “all is well” messages back to the driver’s home terminal. The
dispatcher notifies local law enforcement agencies. The “Track and Trace”
feature of the Company’s website is able to advise a customer of the status and
location of their loads, and show that customer a picture of the driver that is
delivering the load. Remote cameras and better lighting coverage in the staging
and parking areas have augmented terminal security.
 
 Regulatory
Status and Potential Environmental Liability --The
operations and facilities of the Company are subject to numerous federal, state
and local environmental laws and regulations including those described above, as
well as associated permitting and licensing requirements. The Company regards
compliance with applicable environmental regulations as a critical component of
its overall operation, and devotes significant attention to providing quality
service and products to its customers, protecting the health and safety of its
employees, and protecting the Company’s facilities from damage. Management
believes the Company has obtained or applied for all permits and approvals
required under existing environmental laws and regulations to operate its
current business. Management has reported that the Company is not subject to any
pending or threatened environmental litigation or enforcement action(s), which
could materially and adversely affect the Company's business. While the Company
has, where appropriate, implemented operating procedures at each of its
facilities designed to assure compliance with environmental laws and regulation,
the Company, given the nature of its business, is subject to environmental risks
and the possibility remains that the Company's ownership of its facilities and
its operations and activities could result in civil or criminal enforcement and
public as well as private action(s) against the Company, which may necessitate
or generate mandatory clean up activities, revocation of required permits or
licenses, denial of application for future permits, or significant fines,
penalties or damages, any and all of which could have a material adverse effect
on the Company. At December 31, 2004, the Company is unaware of any unresolved
environmental issues for which additional accounting accruals are
necessary.
 
 Employees
 
 At
December 31, 2004 the Company employed 672 persons, 14 of whom were employed in
the exploration and production of oil and gas, 233 in the marketing of crude
oil, natural gas and petroleum products, 414 in transportation operations, and
11 in administrative capacities. None of the Company's employees are represented
by a union. Management believes its employee relations are
satisfactory.
 
 Federal
and State Taxation
 
 The
Company is subject to the provisions of the Internal Revenue Code of 1986, as
amended (the “Code”). In accordance with the Code, the Company computes its
income tax provision based on a 34 percent tax rate. The Company's operations
are, in large part, conducted within the State of Texas. As such, the Company is
subject to a 4.5 percent state tax on corporate net taxable income as computed
for federal income tax purposes. Oil and gas activities are also subject to
state and local income, severance, property and other taxes. Management believes
the Company is currently in compliance with all federal and state tax
regulations.
 
 Forward-Looking
Statements—Safe Harbor Provisions
 
 This
annual report for the year ended December 31, 2004 contains certain
forward-looking statements 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) Production and Reserve
Information, (b) Regulatory Status and Potential Environmental Liability, (c)
Management’s Discussion and Analysis of Financial Condition and Results of
Operations, (d) Critical Accounting Policies and Use of Estimates, (e)
Quantitative and Qualitative Disclosures about Market Risk, (f) Income Taxes,
(g) Concentration of Credit Risk, (h) Price Risk Management Activities, and (i)
Commitments and Contingencies, among others, contain forward-looking statements.
Where the Company expresses an expectation or belief regarding 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.
 
 With the
uncertainties of forward looking statements in mind, the reader should consider
the risks discussed elsewhere in this report and other documents filed with the
Commission from time to time and the following important factors that could
cause actual results to differ materially from those expressed in any
forward-looking statement made by or on behalf of the Company.
 
 *Fluctuations
in oil and gas prices could have an effect on the Company* .
 
 The
company’s future financial condition, revenues, results of operations and future
rate of growth are materially affected by oil and gas prices. Oil and gas prices
historically have been volatile and are likely to continue to be volatile in the
future. Moreover, oil and gas prices depend on factors outside the control of
the Company. These factors include
 
 ·
    supply
      and demand for oil and gas and expectations regarding supply and
      demand;
 ·
    political
      conditions in other oil-producing countries, including the possibility of
      insurgency or war in such areas;
 ·
    economic
      conditions in the United States and worldwide;
 ·
    governmental
      regulations;
 ·
    the
      price and availability of alternative fuel
sources;
 ·
    weather
      conditions;
 ·
    market
      uncertainty; and
 ·
    worldwide
      economic conditions.
 
 *Revenues
are generated under contracts that must be periodically
renegotiated.*
 
 Substantially
all of the Company’s revenues are generated under contracts which expire
periodically or which must be frequently renegotiated, extended or replaced.
Whether these contracts are renegotiated, extended or replaced is often times
subject to factors beyond the Company’s control. Such factors include sudden
fluctuations in oil and gas prices, counterparty ability to pay for or accept
the contracted volumes and most importantly, an extremely competitive
marketplace for the services offered by the Company. There is no assurance that
the costs and pricing of the Company’s services can remain competitive in the
marketplace.
 
 *Anticipated or scheduled volumes
will differ from actual or delivered volumes.*
 
 The
Company’s crude oil and natural gas marketing operation purchases initial
production of crude oil and natural gas at the wellhead under contracts
requiring the Company to accept the actual volume produced. The resale of such
production is generally under contracts requiring a fixed volume to be
delivered. The Company estimates anticipated supply and matches such supply
estimate for both volume and pricing formulas with committed sales volumes.
Since actual wellhead volumes produced will never equal anticipated supply, the
Company’s marketing margins may be adversely impacted. In many instances, any
losses resulting from the difference between actual supply volumes compared to
committed sales volumes must be absorbed by the Company.
 
 *Environmental
liabilities and environmental regulations may have an effect on the
Company.*
 
 The
Company’s business is subject to environmental hazards such as spills, leaks or
any discharges of petroleum products and hazardous substances. These
environmental hazards could expose the Company to material liabilities for
property damage, personal injuries and/or environmental harms, including the
costs of investigating and rectifying contaminated properties.
 
 Environmental
laws and regulations govern several aspects of the Company’s business, such as
drilling and exploration, production, transportation and waste management.
Compliance with environmental laws and regulations can require significant costs
or may require a decrease in production. Moreover, noncompliance with these laws
and regulations could subject the Company to significant administrative, civil
or criminal fines or penalties.
 
 *Counterparty
credit default could have an effect on the Company.*
 
 The
Company’s revenues are generated under contracts with various counterparties.
Results of operations would be adversely affected as a result of non-performance
by any of these counterparties of their contractual obligations under the
various contracts. A counterparty’s default or non-performance could be caused
by factors beyond our control. A default could occur as a result of
circumstances relating directly to the counterparty, or due to circumstances
caused by other market participants which have a direct or indirect relationship
with such counterparty. We seek to mitigate the risk of default by evaluating
the financial strength of potential counterparties, however, despite our
mitigation efforts, defaults by counterparties may occur from time to
time.
 
 *The
Company’s business is dependent on the ability to obtain credit* .
 
 The
Company’s future development and growth depends in part on its ability to
successfully enter into credit arrangements with banks, suppliers and other
parties. Credit agreements are relied upon as a significant source of liquidity
for capital requirements not satisfied by operating cash flow. If the Company is
unable to obtain credit on reasonable and competitive terms, its ability to
continue exploration, pursue improvements, make acquisitions and continue future
growth will be limited.
 
 *Operations
could result in liabilities that may not be fully covered by
insurance* .
 
 The oil
and gas business involves certain operating hazards such as well blowouts,
explosions, fires and pollution. Any of these operating hazards could cause
serious injuries, fatalities or property damage, which could expose the Company
to liability. The payment of any of these liabilities could reduce, or even
eliminate, the funds available for exploration, development, and acquisition, or
could result in a loss of our properties and may even threaten survival of the
enterprise.
 
 Consistent
with the industry standard, the Company’s insurance policies provide limited
coverage for losses or liabilities relating to pollution, with broader coverage
for sudden and accidental occurrences. Insurance might be inadequate to cover
all liabilities. Moreover, obtaining insurance for the Company’s line of
business has become increasingly difficult and costly over the past several
years. The cost of insurance has increased substantially. Insurance costs are
expected to continue increasing over the next few years and as a result coverage
may decrease and more risk may be retained to offset future cost increases. If
substantial liability is incurred and the damages are not covered by insurance
or exceed policy limits, then the Company’s operation could be materially
adversely affected.
 
 *Changes
in tax laws or regulations could adversely effect the Company* .
 
 The
Internal Revenue Service, the United States Treasury Department and Congress
frequently review federal income tax legislation. The Company cannot predict
whether, when or to what extent new federal tax laws, regulations,
interpretations or rulings will be adopted. Any such legislative action may
prospectively or retroactively modify tax treatment and, therefore, may
adversely affect taxation of the Company.
 
 *The
Company’s business is subject to changing government
regulations* .
 
 Federal,
state or local government agencies may impose environmental, tax, labor or other
regulations that increase costs and/or terminate or suspend operations. The
Company’s business is subject to federal, state and local laws and regulations.
These regulations relate to, among other things, the exploration, development,
production and transportation of oil and gas. Existing laws and regulations
could be changed, and any changes could increase costs of compliance and costs
of operations.
 
 *Estimating
reserves, production and future net cash flow is difficult* .
 
 Estimating
oil and gas reserves is a complex process that involves significant
interpretations and assumptions. It requires interpretation of technical data
and assumptions relating to economic factors, such as future commodity prices,
production costs, severance and excise taxes, capital expenditures and remedial
costs, and the assumed effect of governmental regulation. As a result, actual
results may differ from our estimates. Also, the use of a 10 percent discount
factor for reporting purposes, as prescribed by the SEC, may not necessarily
represent the most appropriate discount factor, given actual interest rates and
risks to which our business is subject. Any significant variations from our
estimates could cause the estimated quantities and net present value of our
reserves to differ materially.
 
 The
reserve data included in this report is only an estimate. The reader should not
assume that the present values referred to in this report represent the current
market value of our estimated oil and gas reserves. The timing of the production
and the expenses from development and production of oil and gas properties will
affect both the timing of actual future net cash flows from our proved reserves
and their present value.
 
 *The
Company’s business is dependent on the ability to replace
reserves* .
 
 Future
success depends in part on the Company’s ability to find, develop and acquire
additional oil and gas reserves. Without successful acquisition or exploration
activities, reserves and revenues will decline as a result of current reserves
being depleted by production. The successful acquisition, development or
exploration of oil and gas properties requires an assessment of recoverable
reserves, future oil and gas prices and operating costs, potential environmental
and other liabilities, and other factors. These assessments are necessarily
inexact. As a result, the Company may not recover the purchase price of a
property from the sale of production from the property, or may not recognize an
acceptable return from properties acquired. In addition, exploration and
development operations may not result in any increases in reserves. Exploration
or development may be delayed or canceled as a result of inadequate capital,
compliance with governmental regulations or price controls or mechanical
difficulties. In the future, the cost to find or acquire additional reserves may
become unacceptable.
 
 *Fluctuations
in commodity prices could have an effect on the Company.*
 
 Revenues
depend on volumes and rates, both of which can be affected by the prices of oil
and gas. Decreased prices could result in a reduction of the volumes purchased
or transported by our customers. The success of our operations is subject to
continued development of additional oil and gas reserves. A decline in energy
prices could precipitate a decrease in these development activities and could
cause a decrease in the volume of reserves available for processing and
transmission. Fluctuations in energy prices are caused by a number of factors,
including:
 
 ·
    regional,
      domestic and international supply and
demand;
 ·
    availability
      and adequacy of transportation facilities;
 ·
    energy
      legislation;
 ·
    federal
      and state taxes, if any, on the sale or transportation of natural gas;
 ·
    abundance
      of supplies of alternative energy sources;
 ·
    political
      unrest among oil producing countries;
 ·
    and
      opposition to energy development in environmentally sensitive
      areas.
 
 *Revenues
are dependent on the ability to successfully complete drilling
activity* .
 
 Drilling
and exploration are one of the main methods of replacing reserves. However,
drilling and exploration operations may not result in any increases in reserves
for various reasons. Drilling and exploration may be curtailed, delayed or
cancelled as a result of:
 
 ·
    lack
      of acceptable prospective acreage;
 ·
    inadequate
      capital resources;
 ·
    weather;
 ·
    title
      problems;
 ·
    compliance
      with governmental regulations; and
 ·
    mechanical
      difficulties.
 
 Moreover,
the costs of drilling and exploration may greatly exceed initial estimates. In
such a case, the Company would be required to make additional expenditures to
develop our drilling projects. Such additional and unanticipated expenditures
could adversely affect our financial condition and results of
operations.
 
 *Current
and future litigation could have an effect on the Company.*
 
 The
Company is currently involved in several administrative and civil legal
proceedings. Moreover, as incident to operations, the Company sometimes becomes
involved in various lawsuits and/or disputes. Lawsuits and other legal
proceedings can involve substantial costs, including the cost associated with
investigation, litigation and possible settlement, judgment, penalty or fine.
Although insurance is maintained to mitigate these costs, there can be no
assurance that costs associated with lawsuits or other legal proceedings will
not exceed the limits of insurance policies. The Company’s results of operations
could be adversely affected if a judgment, penalty or fine is not fully covered
by insurance.
 
 Item 3.
LEGAL PROCEEDINGS
 
 In April
2003, Gulfmark Energy Marketing, Inc a wholly owned subsidiary of the company
previously involved in a crude oil marketing joint venture, received a demand
for arbitration seeking monetary damages of $11.6 million and a re-audit of the
joint venture activity for the period of its existence from May 2000 through
October 2001. This claim is further described in Note (11) of Notes to
Consolidated Financial Statements. This matter was resolved in July 2004 by the
Company assuming 100 percent of any future obligations of the joint venture plus
a cash payment of $350,000 to the joint venture claimant in exchange for an
assignment of all accounts receivable from the joint venture and relief from the
Company’s cash obligations otherwise due to the joint venture.
 
 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 is a party to motor vehicle accidents, worker compensation
claims and 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 4.
SUBMISSION OF MATTER TO A VOTE OF SECURITY HOLDERS
 
 None.
 
 
 EXECUTIVE
OFFICERS OF THE REGISTRANT
 
 The
following persons are currently serving as executive officers of the
Company:
 
 Name
    Age
    Positions
      with the CompanyK.
      S. Adams, Jr.
    82
    Chairman
      and Chief Executive OfficerF.
      T. Webster
    56
    President
      and Chief Operating OfficerVincent
      H. Buckley
    82
    Executive
      Vice President and General CounselRichard
      B. Abshire
    52
    Vice
      President and Chief Financial Officer
 
 Each
officer has served in his present position for at least five years except Mr.
Webster and Mr. Buckley. Mr. Webster joined the Company in May 2004. For at
least the two previous years, he was President and Chief Executive Officer and
managing director of Duke Capital Partners, LLC. Prior to joining Duke Capital,
Mr. Webster was a partner and managing director of Andersen, LLP. For the five
years prior to joining the Company, in September 2002, Mr. Buckley was Of
Counsel to the law firm of Locke Liddell & Sapp LLP.
  3
  
 PART
II
 
 Item
5.  MARKET
FOR THE REGISTRANT'S COMMON STOCK, RELATED SECURITY HOLDER MATTERS AND ISSUER
REPURCHASE OF EQUITY SECURITIES
 
 The
Company's common stock is traded on the American Stock Exchange. The following
table sets forth the high and low sales prices of the common stock as published
in *The
Wall Street Journal* for
issues listed on the American Stock Exchange for each calendar quarter since
January 1, 2003.
 
 American
      Stock ExchangeYear
    
    
    
    High
    
    Low2003First
      Quarter
    
    
    
    
    $
    6.50
    
    $
    5.35Second
      Quarter
    
    
    
    
    
    10.45
    
    
    5.57Third
      Quarter
    
    
    
    
    
    10.82
    
    
    8.65Fourth
      Quarter
    
    
    
    
    
    13.96
    
    
    10.062004First
      Quarter
    
    
    
    
    $
    13.95
    
    $
    11.90Second
      Quarter
    
    
    
    
    
    15.20
    
    
    12.60Third
      Quarter
    
    
    
    
    
    15.74
    
    
    12.50Fourth
      Quarter
    
    
    
    
    
    18.95
    
    
    13.30
 
 At March
1, 2005 there were 291 holders of record of the Company's common stock and the
closing stock price was $23.00 per share. The Company has no securities
authorized for issuance under equity compensation plans. The Company made no
repurchases of its stock during 2003 and 2004.
 
 On
December 15, 2004 the Company paid an annual cash dividend of $.30 per common
share to common stockholders of record on December 2, 2004. On December 15, 2003
the Company paid an annual cash dividend of $.23 per common share to common
stock holders of record on December 3, 2003. On December 17, 2002 the Company
paid an annual cash dividend of $.13 per common share to common stock holders of
record on December 2, 2002. Such dividends totaled $1,265,278, $970,047 and
$548,000 for each of 2004, 2003 and 2002, respectively.
 
 The terms
of the Company's bank loan agreement require the Company to maintain
consolidated net worth in excess of $37,938,000. 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.
 4
 6.
SELECTED FINANCIAL DATA
 
 **FIVE
YEAR REVIEW OF SELECTED FINANCIAL DATA**
 
 Years Ended December 31,2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000Revenues:
    
    (In
      thousands, except per share data)Marketing
    
    $
    2,011,669
    
    $
    1,677,728
    
    $
    1,726,194
    
    $
    3,444,050
    
    $
    5,743,500Transportation
    
    
    47,323
    
    
    35,806
    
    
    36,406
    
    
    33,149
    
    
    35,824Oil
      and gas
    
    
    10,796
    
    
    8,395
    
    
    4,750
    
    
    6,111
    
    
    6,059$
    2,069,788
    
    $
    1,721,929
    
    $
    1,767,350
    
    $
    3,483,310
    
    $
    5,785,383Operating
      Earnings:Marketing
    
    $
    13,783
    
    $
    12,244
    
    $
    10,872
    
    $
    (8,846
    )
    $
    16,362Transportation
    
    
    5,687
    
    
    973
    
    
    2,142
    
    
    1,053
    
    
    2,311Oil
      and gas
    
    
    2,362
    
    
    2,310
    
    
    (633
    )
    
    693
    
    
    1,624General
      and administrative
    
    
    (7,867
    )
    
    (6,299
    )
    
    (7,259
    )
    
    (7,165
    )
    
    (6,221
    )13,965
    
    
    9,228
    
    
    5,122
    
    
    (14,265
    )
    
    14,076Other
      income (expense):Interest
      income
    
    
    62
    
    
    362
    
    
    115
    
    
    456
    
    
    1,233Interest
      expense
    
    
    (107
    )
    
    (108
    )
    
    (117
    )
    
    (128
    )
    
    (172
    )Earnings
      (loss) from continuingoperations
      before income taxesand
      cumulative effect ofaccounting
      change
    
    
    13,920
    
    
    9,482
    
    
    5,120
    
    
    (13,937
    )
    
    15,137Income
      tax provision (benefit)
    
    
    5,059
    
    
    3,056
    
    
    1,751
    
    
    (4,776
    )
    
    5,495Earnings
      (loss) from continuingoperations
    
    
    8,861
    
    
    6,426
    
    
    3,369
    
    
    (9,161
    )
    
    9,642Earnings
      (loss) from discontinuedoperations,
      net of taxes
    
    
    (253
    )
    
    (3,232
    )
    
    (1,917
    )
    
    4,537
    
    
    (802
    )Earnings
      (loss) before cumulativeeffect
      of accounting change
    
    
    8,608
    
    
    3,194
    
    
    1,452
    
    
    (4,624
    )
    
    8,840Cumulative
      effect of accountingChange,
      net of taxes
    
    
    -
    
    
    (92
    )
    
    -
    
    
    55
    
    
    -Net
      earnings (loss)
    
    $
    8,608
    
    $
    3,102
    
    $
    1,452
    
    $
    (4,569
    )
    $
    8,840**Earnings
      (Loss) Per Share**From
      continuing operations
    
    $
    2.10
    
    $
    1.53
    
    $
    .79
    
    $
    (2.17
    )
    $
    2.29From
      discontinued operations
    
    
    (.06
    )
    
    (.77
    )
    
    (.45
    )
    
    1.08
    
    
    (.19
    )Cumulative
      effect ofaccounting
      change
    
    
    -
    
    
    (.02
    )
    
    -
    
    
    .01
    
    
    -Basic
      earnings (loss) per share
    
    $
    2.04
    
    $
    .74
    
    $
    .34
    
    $
    (1.08
    )
    $
    2.10Dividends
      per common share
    
    $
    .30
    
    $
    .23
    
    $
    .13
    
    $
    .13
    
    $
    .13**Financial
      Position**Working
      capital
    
    $
    35,789
    
    $
    32,758
    
    $
    30,628
    
    $
    29,651
    
    $
    18,641Total
      assets
    
    
    238,854
    
    
    210,607
    
    
    202,120
    
    
    227,027
    
    
    448,044Long-term
      debt, net ofcurrent
      maturities
    
    
    11,475
    
    
    11,475
    
    
    11,475
    
    
    12,475
    
    
    11,900Shareholders’
      equity
    
    
    49,575
    
    
    42,232
    
    
    40,100
    
    
    39,196
    
    
    44,313Dividends
      on common shares
    
    
    1,265
    
    
    970
    
    
    548
    
    
    548
    
    
    548
 
 ________________________________
 Notes:
 -
    In
      2002, oil and gas operating earnings sustained a loss of $633,000. This
      loss includes $1.7 million in dry hole costs and property valuation
      write-down.
 -
    In
      2001 marketing, operating earnings sustained a loss of $8,846,000. This
      loss includes $8 million in charges related to inventory price declines
      and a $1.5 million bad debt provision in connection with the Enron
      bankruptcy.
  5
  Item 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
 
 
 **Results
of Operations**
 
 - *Marketing*
 
 Marketing
segment revenues and operating earnings were as follows (in
thousands):
 
 2004
    
    
    2003
    
    
    2002Revenues
    
    $
    2,011,669
    
    $
    1,677,728
    
    $
    1,726,194Operating
      Earnings
    
    $
    13,783
    
    $
    12,244
    
    $
    10,872Depreciation
    
    $
    1,498
    
    $
    1,397
    
    $
    1,611
 
 Marketing
segment operating statistics were as follows:
 
 2004
    
    2003
    
    2002Wellhead
      Purchases per day(1)-
      Crude Oil
    
    
    76,000
      bbls
    
    
    85,000
      bbls
    
    
    101,000
      bbls-
      Natural Gas
    
    
    294,000
      mmbtu
    
    
    317,000
      mmbtu
    
    
    482,000
      mmbtuAverage
      Purchase Price-
      Crude Oil
    
    $
    39.88/bbl
    
    $
    29.80/bbl
    
    $
    24.18/bbl-
      Natural Gas
    
    $
    5.75/mmbtu
    
    $
    5.28/mmbtu
    
    $
    3.10/mmbtu
 
 ___________________
 (1)  Reflects
the volume purchased from third parties by the Company at the lease level and
pipeline pooling points.
 
 Commodity
purchases and sales associated with the Company’s natural gas marketing
activities qualify as derivative instruments under Statement of Financial
Accounting Standards No. 133. Therefore, natural gas purchases and sales are
recorded on a net revenue basis in the accompanying financial statements. 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. Included in 2004, 2003 and 2002
crude oil revenues is $735,476,000, $534,464,000 and $610,601,000, respectively,
of gross proceeds 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 affect the transportation of the
commodity, to minimize credit exposure, and to meet the competitive demands of
customers. Financial reporting standards continue to evolve in this area, and in
the future, the reporting for such buy/sell arrangements may be required to be
on a net basis similar to the Company’s practice for natural gas operations. See
Note (1) of Notes to Consolidated Financial Statements.
 
 Marketing
revenues increased by 20 percent to over $2 billion for 2004 compared to 2003,
while operating earnings in the current year increased by 13 percent to
$13,783,000. The revenue increase resulted from crude oil price increases
partially offset by wellhead purchase volume declines. Escalating crude oil
prices from the $32 range at the end of 2003 to the $43 range by year-end 2004
enhanced current operating results as the Company liquidated lower price
inventory into a higher price market. This event contributed approximately
$1,400,000 to 2004 operating earnings. As of December 31, 2004, the Company held
224,900 barrels of crude oil inventory at an average price of $42.97 per barrel.
Partially offsetting the earnings effect of crude oil price increases was
$950,000 of losses sustained within the Company’s gasoline and diesel fuel
wholesale business. Such losses occurred when refined product supply and
distribution costs increased faster than the price to the Company’s end market
customers. Also included in 2004 results was $1,476,000 of income resulting from
settlement of a dispute associated with the Company’s previous marketing joint
venture. See Note 11 of Notes to Consolidated Financial Statements. In addition,
during 2004 the Company collected and recognized as income $1,068,000 of cash on
previous disputed and fully reserved items. Further during 2004, the Company
recognized a $470,000 gain from the sale of its claim against the bankrupt
estate of Enron Corp. and a $310,000 charge to write-down certain slow moving
refined product inventory items. These generally favorable 2004 events compare
to the Company experiencing $1.6 million in reduced marketing expenses during
2003 caused by the reversal of certain previously recorded accrual items
resulting from the final true-ups of the accounting for such items.
 
 Gross
revenues for the marketing operation were essentially flat for 2003 compared to
2002 as crude oil price increases were offset by reductions in crude oil
purchase volumes. By comparison, operating earnings increased by $1.4 million or
13 percent for 2003 relative to 2002. The earnings improvement resulted, in
part, from improved per unit margins for both crude oil and natural gas. Most
notably in the first half of 2003, the war in Iraq caused elevated demand for
near term or prompt month crude oil prices. This presented premium value
opportunities for resale of the crude oil being acquired by the Company. In
addition, per unit margins for natural gas also improved during 2003 as a result
of reduced competition in this sector of the marketplace. Also during 2003, the
Company reduced marketing operating expenses by $1.6 million from the reversal
of previously recorded accrual items. However, such accrual reversal in 2003 was
offset by fee income totaling $2,433,000 during the first six months of 2002.
This fee originated pursuant to the terms of an agreement to dissolve the
Company’s Williams-Gulfmark joint venture. Previously, the Company earned fees
approximating $400,000 per month based on the quantity of crude oil being
purchased by the former co-venture participant in the offshore Gulf of Mexico
region. With July 2002 business, credit constraints caused the former venture
participant to substantially curtail and ultimately cease its purchases of the
crude oil in the region. As a result, the Company’s opportunity for fee income
ceased during 2002.
 
 
 -
    *Transportation*
 
 The
transportation segment experienced a strong resurgence in demand beginning in
the Spring of 2004 and continuing into 2005. Revenues and operating earnings
were as follows (in thousands):
 
 2004
    2003
    2002Amount
    
    
    Change(1
    )
    
    Amount
    
    
    Change(1
    )
    
    Amount
    
    
    Change(1
    )Revenues
    
    $
    47,323
    
    
    32
    %
    $
    35,806
    
    
    (2)
    %
    $
    36,406
    
    
    10
    %Operating
      earnings
    
    $
    5,687
    
    
    484
    %
    $
    973
    
    
    (55)
    %
    $
    2,142
    
    
    103
    %Depreciation
    
    $
    2,125
    
    
    2
    %
    $
    2,093
    
    
    14
    %
    $
    1,838
    
    
    11
    %
 
 ______________
 (1)  Represents
the percentage increase (decrease) from the prior year.
 
 T ransportation
segment results are closely tied to trends for the United States economy in
general and more specifically, to the domestic petrochemical industry. As a
common carrier transporter of bulk liquid chemicals, demand for the Company’s
services is closely tied to the economic activity of domestic manufacturers of
petrochemicals. The Company enjoyed strong demand for its trucking services
during 2004, which caused a 32 percent increase in revenues to $47,323,000. The
demand improvement was consistent with an improving U. S. economy and a weaker
dollar exchange rate stimulating export demand for petrochemicals.
 
 Based on the current level of
infrastructures, the Company’s transportation segment is designed to maximize
efficiency at revenues approaching $42 million per year. Because of the fixed
cost component of operating expenses, operating earnings when expressed as a
percentage change will increase or decrease relatively faster than the rate of
increase or decrease existing for revenues. With the market conditions that
existed in 2004, the Company was able to both maximize efficiency and increase
freight rates. In addition, during 2004 the Company sold certain used
truck-tractors for a gain on sales of $801,000 as compared to a $351,000 gain on
equipment sales in 2003. This combination of factors provided a 484 percent
increase in operating earnings to $5,687,000.
 
 Demand
for the Company’s trucking service has remained strong and is spurred by an
improving United States and world economy. Other important factors include
reduced levels of competition as the industry experienced a general “shake-out”
in recent years coupled with service delays by the railroad industry. Presently,
the Company’s transportation business continues to run at or near full capacity.
 
 
 -  *Oil
and Gas*
 
 Oil and
gas segment revenues and operating earnings are primarily derived from crude oil
and natural gas production volumes and prices. Comparative amounts are as
follows (in thousands):
 
 2004
    
    
    2003
    
    
    2002Revenues
    
    $
    10,796
    
    $
    8,395
    
    $
    4,750Operating
      earnings (loss)
    
    $
    2,362
    
    $
    2,310
    
    $
    (633
    )Depreciation
      and depletion
    
    $
    2,949
    
    $
    2,175
    
    $
    2,116
 
 
 2004
    
    2003
    
    2002Production
      Volumes-
      Crude Oil
    
    
    71,300
      bbls
    
    
    61,900
      bbls
    
    
    55,000
      bbls-
      Natural Gas
    
    
    1,309,000
      mcf
    
    
    1,239,000
      mcf
    
    
    1,047,000
      mcfAverage
      Price-
      Crude Oil
    
    $
    39.48/bbl
    
    $
    30.67/bbl
    
    $
    26.10/bbl-
      Natural Gas
    
    $
    6.09/mcf
    
    $
    5.23/mcf
    
    $
    3.17/mcf
 
 As shown
above, oil and gas division revenues and operating earnings improved in 2004
relative to 2003 and in 2003 relative to 2002 due to increased crude oil and
natural gas production volumes as well as higher prices. Recent results from
exploration efforts caused the production volume increases. During 2004, the
Company participated in the drilling of thirty-three wells. Twenty wells were
successfully completed with seven dry holes and six wells in process at
year-end. In addition to the completions of wells spud in 2004, the Company also
successfully brought on production one well that was drilling at year-end 2003.
All of the wells in process at December 31, 2004 were subsequently determined in
the first quarter of 2005 to be productive.
 
 Although
oil and gas revenues increased by 28 percent during 2004, operating earnings
were relatively unchanged at $2,362,000 for the year. Improvement in operating
earnings did not correlate with improved revenues because $2,504,000 of
exploration expense was incurred during 2004 compared to $1,638,000 of
exploration expenses occurring during 2003. Exploration expense in 2004 included
a $616,000 impairment provision on non-producing properties plus $1,888,000 of
dry hole and geological and geophysical costs. Comparative operating earnings
for 2004 were also adversely affected by a 36 percent increase in the provision
for depreciation and depletion. The depreciation and depletion provision in 2004
included a $309,000 impairment provision on certain producing properties where
actual drilling costs incurred exceed the estimated fair value of the property.
 
 The
results of 2004 exploration efforts yielded estimated reserve additions totaling
121,000 barrels of oil and 3,166,000 mcf of gas. With the Company’s production
for 2004 being 71,300 barrels of oil and 1,309,000 mcf of gas, the estimated
reserve additions for 2004 represent a 224 percent replacement of current
production on an oil equivalent barrel basis. Estimated future undiscounted net
cash flow before income taxes from oil and gas properties was increased from
$46,186,000 at year-end 2003 to $62,312,000 at year-end 2004.
 
 Presently,
the Company’s drilling and exploration efforts are primarily focused as
follows:
 
 Ft. Bend,
Wharton and Colorado Counties, Texas
 
 The
Company initiated the drilling of nine wells in 2004 in this area of Texas, with
seven proving to be productive and two dry holes. One of the dry holes was lost
due to mechanical reasons and the replacement well was successful. The success
in 2004 results from interpretation of work done on a 3-D seismic data
acquisitions made in 1999. The Company and one of its joint interest partners
expanded exploration in this area in 2004 by acquiring additional seismic data
and applying the same seismic reprocessing techniques that led to the initial
drilling successes in the area. The first two wells on this newly acquired
seismic data were drilled in the first quarter 2005 and are productive. A number
of additional prospects will be drilled in the area during 2005.
 
 Calcasieu
Parish, Louisiana
 
 During
2004, the Company drilled nine wells with one dry hole in the Calcasieu area. At
the end of 2004, three of the successful wells were waiting on the installation
of surface production facilities and are scheduled to be producing beginning in
the first quarter 2005. Supported by a 3-D seismic survey conducted in 2003, the
Company and its joint interest partners have a continuing drilling program with
additional prospects identified for drilling in 2005.
 
 Southern
Alabama
 
 In
Southern Alabama, processing and evaluation of a large proprietary 3-D seismic
survey was completed in 2004 and resulted in numerous prospects to be drilled in
2005. Two of these wells were drilled in the first quarter 2005 as dry holes.
Additional drilling will proceed during 2005 taking into consideration the
knowledge gained from these wells.
 
 Lafayette
Parish, Louisiana
 
 Due to
the relative risk associated with an available prospect in Lafayette Parish, the
Company took less than one percent interest in the drilling of an initial well
that proved to be successful in 2005. Significantly, the Company’s interest in
the offset acreage is approximately five percent, and the offset well will be
drilled in the second quarter of 2005.
 
 U. K.
North Sea
 
 Seismic
reprocessing and evaluation to confirm a drillable prospect has continued on the
Company’s interest in Block 21-1b of the Central UK North Sea. Beginning in the
second quarter of 2005 presentations will be made to prospective joint interest
partners in an attempt to promote the drilling of an exploratory well, hopefully
before year-end. Additionally, in the UK North Sea, the Company’s bid for a
promote license in the 22 nd licensing round held last summer was accepted. The Company will have a 33 1/3%
equity interest in Block 48-16c, located in the Southern Sector of the North
Sea. The license was officially granted in February 2005. The Company with its
joint interest partners will have two years to acquire existing 3-D and 2-D
seismic data and reprocess it to confirm an exploration prospect identified on
the Block. The terms of the license do not include a well commitment. If a Block
48-16c prospect is confirmed by the seismic data, the Company and its joint
interest partners will seek an additional partner to drill a well on a promoted
basis, thus limiting capital exposure on the drilling of the initial exploratory
well.
 
  6
  
 *-*
    *General
      and administrative*
 
 General
and administrative expenses increased $1,568,000, or 25 percent, in 2004 as a
result of increased personnel related expenses as both the number and average
wage of administrative personnel increased during the year. An additional
minimum 15 percent or $1.2 million increase is expected for 2005 as the Company
continues to expand its corporate governance and Sarbanes-Oxley compliance
efforts.
 
 
 -
    *Discontinued
      operations*
 
 During
2003, the Company’s 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 early withdrawal from the region was instituted
in 2003 and the exit from this business was completed in 2004. See Note (3) of
Notes to Consolidated Financial Statements.
 
 
 - *Outlook*
 
 Looking
ahead for the marketing operation, management does not foresee a substantial
change in 2005 for this business. Overall, a sound profitable operation should
continue. For transportation, the strengthened level of demand is expected to
remain. For oil and gas exploration, a strong price environment continues and
drilling activity is expected to increase. In addition, the Company is pursuing
other exploration opportunities for development in 2006 and beyond.
 
 The
Company has the following major objectives for 2005:
 
 -
    Maintain
      marketing operating earnings at the $13 million
level.
 
 -
    Increase
      transportation operating earnings by 5 percent to the $6 million
      level.
 
 -
    Improve
      oil and gas operating earnings to $3 million while growing the oil and gas
      reserve base by 10 percent.
 
 
 **Liquidity
and Capital Resources**
 
 Management’s
practice is to generally balance the cash flow requirements of the Company’s
investment activities with available cash generated from operations. As a
result, over time, cash utilized for property and equipment additions, tends to
track with the non-cash provision for depreciation, depletion and amortization.
However, during 2004, the Company diverged from its normal practice. A summary
analysis of cash flows follows (in thousands):
 
 
 Years Ended December 31,2004
    
    
    2003
    
    
    2002
    
    
    TotalDepreciation,
      depletion andamortization
    
    $
    6,572
    
    $
    5,665
    
    $
    5,565
    
    $
    17,802Property
      and equipmentadditions
    
    
    (12,161
    )
    
    (7,761
    )
    
    (4,619
    )
    
    (24,541
    )Other
      (sources) uses of cash
    
    $
    (5,589
    )
    $
    (2,096
    )
    $
    946
    
    $
    (6,739
    )
 
 Several
factors led to increased property and equipment expenditures. One factor was the
December 31, 2004 expiration of certain federal tax provisions that afforded
accelerated depreciation rates on new equipment purchases. The Company availed
itself of this opportunity through the cash purchase of $4.5 million of
truck-tractors and trailers for its transportation fleet. Ordinarily, such
equipment is obtained through operating lease financing. Additionally, 2004 was
a growth year for the Company’s transportation and oil and gas segments and
available cash balances were utilized for such expenditures. Presently,
management intends to restrict investment decisions to available cash flow.
Significant, if any, additions to debt are not anticipated.
 
 
 *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 1⁄4 of one
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
December 31, 2004 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 was established at $10,000,000 as
of March 15, 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 December 31, 2004, 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
$37,938,000. The Company was in compliance with these covenants at December 31,
2004.
 
 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 one percent.
As of December 31, 2004, the Company had $5.8 million of eligible borrowing
capacity under this facility. No working capital advances were outstanding as of
December 31, 2004. Letters of credit outstanding under this facility totaled
approximately $19.1 million as of December 31, 2004. The letter of credit and
demand note facilities are secured by substantially all of Gulfmark’s and ARM’s
assets. Under this facility, BNP Paribas has the right to discontinue the
issuance of letters of credit 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. 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 December 31, 2004. Letters of credit outstanding under this
facility totaled approximately $4.8 million as of December 31, 2004. The letter
of credit and demand note facilities are secured by substantially all of
Gulfmark’s and ARM’s assets. Under this facility, BNP Paribas has the right to
discontinue the issuance of letters of credit without prior notification to the
Company.
 
 
 *Off-balance
      Sheet Arrangements*
 
 The
Company maintains certain operating lease arrangements to provide tractor and
trailer equipment for the Company’s truck fleet. All such operating lease
commitments qualify for off-balance sheet treatment as provided by Statement of
Financial Accounting Standards No. 13, “Accounting for Leases”. The Company has
operating lease arrangements for tractors, trailers, office space, and other
equipment and facilities. Rental expense for the years ended December 31, 2004,
2003, and 2002 was $6,650,000, $5,831,000, and $5,944,000 respectively. At
December 31, 2004, commitments under long-term noncancelable operating leases
for the next five years and thereafter are payable as follows: 2005 -
$4,604,000; 2006 - $3,841,000; 2007 - $3,530,000; 2008 - $3,329,000; 2009 -
$1,199,000 and thereafter - $233,000.
 
 *Contractual
Cash Obligations*
 
 In
addition to its banking relationships and obligations, the Company enters into
certain operating leasing arrangements for tractors, trailers, office space and
other equipment and facilities. The Company has no capital lease obligations. A
summary of the payment periods for contractual debt and lease obligations is as
follows (in thousands):
 
 
 2005
    
    
    2006
    
    
    2007
    
    
    2008
    
    
    2009
    
    
    Thereafter
    
    
    TotalLong-term
      debt
    
    $
    -
    
    $
    1,434
    
    $
    5,738
    
    $
    4,303
    
    $
    -
    
    $
    -
    
    $
    11,475Operating
      leases
    
    
    4,604
    
    
    3,841
    
    
    3,530
    
    
    3,329
    
    
    1,199
    
    
    233
    
    
    16,736Total
    
    $
    4,604
    
    $
    5,275
    
    $
    9,268
    
    $
    7,632
    
    $
    1,199
    
    $
    233
    
    $
    28,211
 
 In
addition to its bank debt and lease financing obligations, the Company is also
committed to purchase certain quantities of crude oil and natural gas in
connection with its marketing activities. Such commodity purchase obligations
are the basis for commodity sales, which generate the cash flow necessary to
meet such purchase obligations. See also Note (8) of the Notes to Consolidated
Financial Statements. Approximate commodity purchase obligations as of December
31, 2004 are as follows (in thousands):
 
 
 January
    
    
    Remaining2005
    
    
    2005
    
    
    2006
    
    
    2007
    
    
    Thereafter
    
    
    TotalCrude
      Oil
    
    $
    80,995
    
    $
    1,692
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    82,687Natural
      Gas
    
    
    50,401
    
    
    6,954
    
    
    -
    
    
    -
    
    
    -
    
    
    57,355Refined
      Products
    
    
    901
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    901$
    132,297
    
    $
    8,646
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    140,943
 
 
 *Investment
Activities*
 
 During
2004, the Company invested approximately $4,147,000 in oil and gas projects,
$6,736,000 for replacement equipment for its petrochemical trucking fleet and
$1,278,000 in equipment for the Company’s marketing operations. Oil and gas
exploration and development efforts continue, and the Company plans to invest
approximately $10 million toward such projects in 2005 including $1,500,000 of
seismic costs to be expensed during the year. An additional approximate $1.6
million is projected in 2005 for the purchase of transportation equipment as
present lease financing arrangements mature.
 
 *Insurance*
 
 The
marketplace for all forms of insurance has entered a period of severe cost
increases. In the past, during such cyclical periods, the Company has seen cost
increases to the point where desired levels of insurance were either unavailable
or unaffordable. The Company’s primary insurance needs are in the area of
automobile and umbrella coverage for its trucking fleet and medical insurance
for employees. During 2003, the Company’s insurance costs increased 27 percent
to total $9.9 million. During 2004, insurance cost stabilized and totaled $9.6
million. Overall insurance cost may experience renewed rate increases during
2005. Since the Company is generally unable to pass on such cost increases, any
increase will need to be absorbed by existing operations.
 
 *Competition*
 
 In all
phases of its operations, the Company encounters strong competition from a
number of entities. Many of these competitors possess financial resources
substantially in excess of those of the Company. The Company faces competition
principally in establishing trade credit, pricing of available materials and
quality of service. In its oil and gas operation, the Company also competes for
the acquisition of mineral properties. The Company's marketing division competes
with major oil companies and other large industrial concerns that own or control
significant refining and marketing facilities. These major oil companies may
offer their products to others on more favorable terms than those available to
the Company. From time to time in recent years, there have been supply
imbalances for crude oil and natural gas in the marketplace. This in turn has
led to significant fluctuations in prices for crude oil and natural gas. As a
result, there is a high degree of uncertainty regarding both the future market
price for crude oil and natural gas and the available margin spread between
wholesale acquisition costs and sales realization.
 
 
 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, commonly called
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 the substantially all risks associated with the execution of
      contracts are 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, any 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 reported results that differ from
those presented under conventional accrual accounting.
 
 
 *Trade
Accounts*
 
 Accounts
receivable and accounts payable typically represent the most significant assets
and liabilities of the Company. Particularly within the Company’s energy
marketing, 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. A degree of risk remains, however, due to the custom and
practices of the industry.
 
 *Oil
and Gas Reserve Estimate*
 
 The value
of capitalized cost 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 is a party to motor vehicle accidents, worker
compensation claims or other items of general liability as are 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 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.
 
 *Revenue
Recognition*
 
 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 in Note (1)
of Notes to Consolidated Financial Statements.
 
 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.
  7
  
 *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 December 31,
2004 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 effect on our financial position, results of operations or cash
flows.
 
 In
December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets an
amendment of APB 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 has
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. Earlier application is permitted for nonmonetary asset exchanges
occurring in fiscal periods beginning after the date this Statement is issued.
Retroactive application is not permitted. Management is analyzing the
requirements of this new Statement and believes that its adoption will not have
any significant impact on the Company’s financial position, results of
operations or cash flows.
 
 
 
 ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
 The
Company’s exposure to market risk includes potential adverse changes in interest
rates and commodity prices.
 
 *Interest
Rate Risk*
 
 Total
long-term debt at December 31, 2004 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 December 31,
2004. 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 fiscal
year ended December 31, 2004.
 
 *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 two years in duration. The
Company monitors all commitments and positions and endeavors to maintain a
balanced portfolio.
  8
  
 Certain
forward contracts are recorded at fair value, depending on management’s
assessments of numerous accounting standards and positions that comply with
generally accepted accounting principles. The undiscounted fair value of such
contracts is reflected on the Company’s balance sheet as risk management assets
and liabilities. The revaluation of such contracts is recognized on a net basis
in the Company’s results of operations. Current market price quotes from
actively traded liquid markets are used in all cases to determine the contracts’
undiscounted fair value. Regarding net risk management assets, 100 percent of
presented values as of December 31, 2004 and 2003 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 $630,000 all to be
received in 2005. 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 year ended December
31, 2004 (in thousands).
 
 2004Net
      fair value on January 1,
    
    $
    692Activity
      during 2004-
      Cash received from settled contracts
    
    
    (1,061
    )-
      Net realized gain from prior years’ contracts
    
    
    369-
      Net unrealized gain from current year contracts
    
    
    630Net
      fair value on December 31,
    
    $
    630
 
 Historically,
prices received for oil and gas production have been volatile and unpredictable.
Price volatility is expected to continue. From January 1, 2003 through December
31, 2004 natural gas price realizations ranged from a monthly low of $3.68 mmbtu
to a monthly high of $17.00 per mmbtu. Oil prices ranged from a low of $28.61
per barrel to a high of $53.32 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
$2,045,000 and $1,250,000, respectively, for the comparative years ended
December 31, 2004 and 2003.
 
  9
  
 ITEM 8.
FINANCIAL STATEMENTS
 
 
 
 **ADAMS
RESOURCES & ENERGY, INC. AND SUBSIDIARIES**
 
 **INDEX
TO FINANCIAL STATEMENTS**
 
 PageREPORT
      OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
    
    
    11FINANCIAL
      STATEMENTS:Consolidated
      Balance Sheet as of December 31, 2004 and 2003
    
    
    12Consolidated
      Statement of Operations for the Years Ended
    
    
    13December
      31, 2004, 2003 and 2002Consolidated
      Statement of Shareholders Equity for the Years Ended
    
    
    14December
      31, 2004, 2003 and 2002Consolidated
      Statement of Cash Flows for the Years Ended
    
    
    15December
      31, 2004, 2003 and 2002Notes
      to Consolidated Financial Statements
    
    
    16
 
  10
  
 
 **REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**
 
 
 
 To the
Shareholders of Adams Resources & Energy, Inc.:
 
 We have
audited the accompanying consolidated balance sheets of Adams Resources and
Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2004 and 2003,
and the related consolidated statements of operations, stockholders’ equity and
cash flows for each of the three years in the period ended December 31, 2004.
These financial statements are the responsibility of the Company’s management.
Our responsibility is to express an opinion on the financial statements based on
our audits.
 
 We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. The Company is not required to
have, nor were we engaged to perform, an audit of its internal control over
financial reporting. Our audit included consideration of internal control over
financial reporting as a basis for designing audit procedures that are
appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Company’s internal control over financial
reporting. Accordingly, we express no such opinion. An audit includes examining,
on a test basis, evidences supporting the amounts and disclosures in the
financial statements, assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
 
 In our
opinion, consolidated financial statements present fairly, in all material
respects, the financial position of the Company as of December 31, 2004 and
2003, and the results of its operations and its cash flows for the each of the
three years in the period ended December 31, 2004, in conformity with accounting
principles generally accepted in the United States of America.
 
 As
discussed in Note 1 to the consolidated financial statements, effective January
1, 2003, the Company changed its method of accounting for asset retirement
obligations.
 
 
 DELOITTE
& TOUCHE LLP
 Houston,
Texas
 March 15,
2005
  11
  **ADAMS
RESOURCES & ENERGY, INC. AND SUBSIDIARIES**
 **CONSOLIDATED
BALANCE SHEET**
 **(In
thousands)**
 
 December
      31,ASSETS
    
    2004
    
    2003CURRENT
      ASSETS:Cash
      and cash equivalents
    
    $
    19,942
    
    $
    28,342Accounts
      receivable, net of allowance for doubtful accounts of$384
      and $1,935, respectively
    
    
    161,885
    
    
    135,306Inventories
    
    
    11,372
    
    
    6,300Risk
      management receivables
    
    
    7,795
    
    
    3,809Income
      tax receivable
    
    
    -
    
    
    1,310Prepayments
    
    
    8,345
    
    
    4,870Current
      deferred taxes
    
    
    -
    
    
    346Current
      assets of discontinued operation
    
    
    -
    
    
    5,140Total
      current assets
    
    
    209,339
    
    
    185,423PROPERTY
      AND EQUIPMENT:Marketing
    
    
    20,659
    
    
    20,771Transportation
    
    
    22,533
    
    
    18,652Oil
      and gas (successful efforts method)
    
    
    45,390
    
    
    41,666Other
    
    
    99
    
    
    9988,681
    
    
    81,188Less
      - Accumulated depreciation, depletion and amortization
    
    
    (59,605
    )
    
    (56,342
    )29,076
    
    
    24,846OTHER
      ASSETS:Other
      assets
    
    
    439
    
    
    338$
    238,854
    
    $
    210,607LIABILITIES
      AND SHAREHOLDERS’ EQUITYCURRENT
      LIABILITIES:Accounts
      payable
    
    $
    160,387
    
    $
    145,047Risk
      management payables
    
    
    7,165
    
    
    3,117Accrued
      and other liabilities
    
    
    5,904
    
    
    3,364Current
      deferred taxes
    
    
    94
    
    
    -Current
      liabilities of discontinued operation
    
    
    -
    
    
    1,137Total
      current liabilities
    
    
    173,550
    
    
    152,665LONG-TERM
      DEBT
    
    
    11,475
    
    
    11,475OTHER
      LIABILITIES:Asset
      retirement obligations
    
    
    723
    
    
    706Deferred
      taxes and other
    
    
    3,531
    
    
    3,529189,279
    
    
    168,375COMMITMENTS
      AND CONTINGENCIES (NOTE 8)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
      issued and outstanding
    
    
    422
    
    
    422Contributed
      capital
    
    
    11,693
    
    
    11,693Retained
      earnings
    
    
    37,460
    
    
    30,117Total
      shareholders’ equity
    
    
    49,575
    
    
    42,232$
    238,854
    
    $
    210,607
 
 
 The
accompanying notes are an integral part of these consolidated financial
statements.
  12
  
 **ADAMS
RESOURCES & ENERGY, INC. AND SUBSIDIARIES**
 **CONSOLIDATED
STATEMENT OF OPERATIONS**
 **(In
thousands, except per share data)**
 
 
 
 Years Ended December 31,2004
    
    
    2003
    
    
    2002REVENUES:Marketing
      (includes $735,476, $534,464 and $610,601,
      respectively,
      of proceeds from buy/sell arrangements)
    
    $
    2,011,669
    
    $
    1,677,728
    
    $
    1,726,194Transportation
    
    
    47,323
    
    
    35,806
    
    
    36,406Oil
      and gas
    
    
    10,796
    
    
    8,395
    
    
    4,7502,069,788
    
    
    1,721,929
    
    
    1,767,350COSTS
      AND EXPENSES:Marketing
      (includes $736,126, $551,848 and $611,144,
      respectively,
      of costs associated with buy/sell arrangements)
    
    
    1,996,388
    
    
    1,664,087
    
    
    1,713,711Transportation
    
    
    39,511
    
    
    32,740
    
    
    32,426Oil
      and gas
    
    
    5,485
    
    
    3,910
    
    
    3,267General
      and administrative
    
    
    7,867
    
    
    6,299
    
    
    7,259Depreciation,
      depletion and amortization
    
    
    6,572
    
    
    5,665
    
    
    5,5652,055,823
    
    
    1,712,701
    
    
    1,762,228Operating
      Earnings
    
    
    13,965
    
    
    9,228
    
    
    5,122Other
      Income (Expense):Interest
      income
    
    
    62
    
    
    362
    
    
    115Interest
      expense
    
    
    (107
    )
    
    (108
    )
    
    (117
    )Earnings
      from continuing operations before income taxand
      cumulative effect of accounting change
    
    
    13,920
    
    
    9,482
    
    
    5,120Income
      Tax Provision (Benefit):Current
    
    
    4,666
    
    
    2,346
    
    
    4,084Deferred
    
    
    393
    
    
    710
    
    
    (2,333
    )5,059
    
    
    3,056
    
    
    1,751Earnings
      from continuing operations
    
    
    8,861
    
    
    6,426
    
    
    3,369Loss
      from discontinued operations, net of taxbenefit
      of $130, $1,664 and $987, respectively
    
    
    (253
    )
    
    (3,232
    )
    
    (1,917
    )Earnings
      before cumulative effect of accounting change
    
    
    8,608
    
    
    3,194
    
    
    1,452Cumulative
      effect of accounting change, net of tax benefitof
      zero, $57 and zero, respectively
    
    
    -
    
    
    (92
    )
    
    -Net
      Earnings
    
    $
    8,608
    
    $
    3,102
    
    $
    1,452EARNINGS
      (LOSS) PER SHARE:From
      continuing operations
    
    $
    2.10
    
    $
    1.53
    
    $
    .79From
      discontinued operation
    
    
    (.06
    )
    
    (.77
    )
    
    (.45
    )Cumulative
      effect of accounting change
    
    
    -
    
    
    (.02
    )
    
    -Basic
      and diluted net earnings per share
    
    $
    2.04
    
    $
    .74
    
    $
    .34DIVIDENDS
      PER COMMON SHARE
    
    $
    .30
    
    $
    .23
    
    $
    .13
 
 
 
 The
accompanying notes are an integral part of these consolidated financial
statements.
  13
  
 
 
 **ADAMS
RESOURCES & ENERGY, INC. AND SUBSIDIARIES**
 **CONSOLIDATED
STATEMENT OF SHAREHOLDERS' EQUITY**
 **(In
thousands)**
 
 ****
    
    
    **Total******
    
    
    **Common**
    
    
    **Contributed**
    
    
    **Retained**
    
    
    **Shareholders’******
    
    
    **Stock**
    
    
    **Capital**
    
    
    **Earnings**
    
    
    **Equity**BALANCE,
      January 1, 2002
    
    $
    422
    
    $
    11,693
    
    $
    27,081
    
    $
    39,196Net
      earnings
    
    
    -
    
    
    -
    
    
    1,452
    
    
    1,452Dividends
      paid on common stock
    
    
    -
    
    
    -
    
    
    (548
    )
    
    (548
    )BALANCE,
      December 31, 2002
    
    
    422
    
    
    11,693
    
    
    27,985
    
    
    40,100Net
      earnings
    
    
    -
    
    
    -
    
    
    3,102
    
    
    3,102Dividends
      paid on common stock
    
    
    -
    
    
    -
    
    
    (970
    )
    
    (970
    )BALANCE,
      December 31, 2003
    
    
    422
    
    
    11,693
    
    
    30,117
    
    
    42,232Net
      earnings
    
    
    -
    
    
    -
    
    
    8,608
    
    
    8,608Dividends
      paid on common stock
    
    
    -
    
    
    -
    
    
    (1,265
    )
    
    (1,265
    )BALANCE,
      December 31, 2004
    
    $
    422
    
    $
    11,693
    
    $
    37,460
    
    $
    49,575
 
 
 The
accompanying notes are an integral part of these consolidated financial
statements.
 
  14
  **ADAMS
RESOURCES & ENERGY, INC. AND SUBSIDIARIES**
 **CONSOLIDATED
STATEMENT OF CASH FLOWS**
 **(In
thousands)**
 
 
 Years Ended December 312004
    
    
    2003
    
    
    2002CASH
      PROVIDED BY OPERATIONS:Earnings
      from continuing operations
    
    $
    8,861
    
    $
    6,426
    
    $
    3,369Adjustments
      to reconcile net earnings to net cashprovided
      by (used in) operating activities-Depreciation,
      depletion and amortization
    
    
    6,572
    
    
    5,665
    
    
    5,565Gains
      on property sales
    
    
    (1,438
    )
    
    (448
    )
    
    (447
    )Impairment
      of non-producing oil and gas properties
    
    
    616
    
    
    461
    
    
    537Cumulative
      effect of accounting change
    
    
    -
    
    
    (149
    )
    
    -Other,
      net
    
    
    (188
    )
    
    330
    
    
    (276
    )Decrease
      (increase) in accounts receivable
    
    
    (26,579
    )
    
    (15,270
    )
    
    2,255Decrease
      (increase) in inventories
    
    
    (5,072
    )
    
    (1,319
    )
    
    3,515Risk
      management activities
    
    
    62
    
    
    (762
    )
    
    2,687Decrease
      (increase) in tax receivable
    
    
    1,310
    
    
    (928
    )
    
    3,548Decrease
      (increase) in prepayments
    
    
    (3,475
    )
    
    (1,723
    )
    
    4,492Increase
      (decrease) in accounts payable
    
    
    15,138
    
    
    7,947
    
    
    (14,356
    )Increase
      (decrease) in accrued liabilities
    
    
    2,540
    
    
    (586
    )
    
    294Deferred
      taxes
    
    
    393
    
    
    710
    
    
    (3,075
    )Net
      cash (used in) provided by continuing operations
    
    
    (1,260
    )
    
    354
    
    
    8,108Net
      cash provided by discontinued operation
    
    
    3,750
    
    
    8,729
    
    
    11,533Net
      cash provided by operating activities
    
    
    2,490
    
    
    9,083
    
    
    19,641INVESTING
      ACTIVITIES:Property
      and equipment additions
    
    
    (12,161
    )
    
    (7,761
    )
    
    (4,619
    )Proceeds
      from property sales
    
    
    2,536
    
    
    728
    
    
    561Net
      cash used in investing activities
    
    
    (9,625
    )
    
    (7,033
    )
    
    (4,058
    )FINANCING
      ACTIVITIES:Net
      borrowings under credit agreements
    
    
    -
    
    
    -
    
    
    (1,000
    )Dividend
      payments
    
    
    (1,265
    )
    
    (970
    )
    
    (548
    )Net
      cash used in financing activities
    
    
    (1,265
    )
    
    (970
    )
    
    (1,548
    )Increase
      (decrease) in cash and cash equivalents
    
    
    (8,400
    )
    
    1,080
    
    
    14,035Cash
      and cash equivalents at beginning of year
    
    
    28,342
    
    
    27,262
    
    
    13,227Cash
      and cash equivalents at end of year
    
    $
    19,942
    
    $
    28,342
    
    $
    27,262
 
 
 The
accompanying notes are an integral part of these consolidated financial
statements.
  15
 **(1)
Summary of Significant Accounting Policies**
 
 *Principles
of Consolidation*
 
 The
accompanying consolidated financial statements include the accounts of Adams
Resources & Energy, Inc., a Delaware corporation, and its wholly owned
subsidiaries (the "Company") after elimination of all significant intercompany
accounts and transactions. Certain reclassifications have been made to prior
year amounts in order to conform to current year presentation.
 
 *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 fund with a maturity of 30 days or less. Included in the cash balance
at December 31, 2004 and 2003 is a deposit of $2 million to collateralize the
Company's month-to-month crude oil letter of credit facility. See Note (2) of
Notes to Consolidated Financial Statements.
 
 *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 are valued at cost determined on the
first-in, first-out basis, while crude oil inventory is valued at average cost.
Components of inventory are as follows (in thousands):
 
 December
      31,2004
    
    2003Crude
      oil
    
    $
    9,663
    
    $
    4,108Petroleum
      products
    
    
    1,709
    
    
    2,192$
    11,372
    
    $
    6,300
 
 
 *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. 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.
 
 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. Accordingly, a $616,000 and a $461,000 impairment
provision on non-producing properties was recorded in 2004 and 2003,
respectively. Also for 2004, a $309,000 impairment provision on producing oil
and gas properties was recorded and included in DD&A as a result of
relatively high costs incurred on certain properties relative to their oil and
gas reserve additions.
 
 *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 No. 133. Therefore, natural gas purchases and sales are
recorded on a net revenue basis in the accompanying financial statements. 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. Presently, the EITF in Issue 04-13 is reviewing the
accounting presentation for buy/sell arrangements and may require that such
items be reported net on the Statement of Operations. In such circumstances,
marketing segment revenues presented herein would be reduced by $735,476,000,
$534,464,000 and $610,601,000 for 2004, 2003 and 2002, respectively. Net
earnings from operations would be unaffected by such change in
presentation.
  16
  *Statement
of Cash Flows*
 
 Interest
paid totaled $120,000, $96,000 and $121,000 during the years ended December 31,
2004, 2003 and 2002, respectively. Income taxes paid during these same periods
totaled $2,957,000, $1,659,000 and $465,000, respectively. Federal tax refunds
received totaled $306,000 and $2,779,000 during 2003 and 2002, respectively.
There were no significant non-cash investing or financing activities in any of
the periods reported.
 
 *Earnings
Per Share*
 
 The
Company computes and presents earnings per share in accordance with Statement of
Financial Accounting Standards (“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 common stock equivalents
outstanding during the period. The weighted average number of shares outstanding
averaged 4,217,596 for 2004, 2003 and 2002. There were no potentially dilutive
securities during 2004, 2003 and 2002.
 
 *Use
of Estimates*
 
 The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities at
the date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates. Examples of significant estimates used in the accompanying
consolidated financial statements include the 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) 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. For cash flow hedges, the effected
portion of the change in fair value will be deferred in other comprehensive
income until the related hedge item impacts earnings. The Company had no
contracts designated for hedge accounting under SFAS No. 133 during any current
reporting periods.
 
 The
Company’s trading and non-trading transactions give rise to market risk, which
represents the potential loss that may result from a change in the market value
of a particular commitment. The Company closely monitors and manages its
exposure to market risk to ensure compliance with the Company’s risk management
policies. Such policies are regularly assessed to ensure their appropriateness
given management’s objectives, strategies and current market
conditions.
 
 The
Company’s forward crude oil contracts are designated as normal purchases and
sales. Natural gas forward contracts and energy trading contracts on crude oil
and natural gas are recorded at fair value, depending on management’s
assessments of the numerous accounting standards and positions that comply with
generally accepted accounting principles. The undiscounted fair value of such
contracts is reflected on the Company’s balance sheet as risk management assets
and liabilities. The revaluation of such contracts is recognized in the
Company’s results of operations. Current market price quotes from actively
traded liquid markets are used in all cases to determine the contracts’
undiscounted 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 December 31, 2004 is $630,000, all of
which will be received in 2005. 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 year ended December
31, 2004 and 2003 (in thousands):
 
 2004
    
    
    2003Net
      fair value on January 1,
    
    $
    692
    
    $
    (70
    )Activity
      during 2004-
      Cash received from settled contracts
    
    
    (1,061
    )
    
    --
      Cash paid on settled contracts
    
    
    -
    
    
    21-
      Net realized gain from prior years’ contracts
    
    
    369
    
    
    --
      Net realized (loss) from prior years’ contracts
    
    
    -
    
    
    (32
    )-
      Net unrealized gain from prior years’ contracts
    
    
    -
    
    
    340-
      Net unrealized gain from current years’ contracts
    
    
    630
    
    
    433Net
      fair value on December 31,
    
    $
    630
    
    $
    692
 
 *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. The Company estimated the present value of
its future Asset Retirement Obligations at approximately $672,000 as of January
1, 2003. The cumulative effect of adoption of SFAS No. 143 and the change in
accounting principle resulted in a charge to net income during the first quarter
of 2003 of approximately $149,000 or $92,000 net of taxes. A summary of the
recording of the estimated fair value of the Company’s asset retirement
obligations is presented as follows (in thousands):
 
 2004
    
    
    2003Balance
      on January 1,
    
    $
    706
    
    $
    -Impact
      of accounting change
    
    
    -
    
    
    672Liabilities
      incurred
    
    
    14
    
    
    63Accretion
      of discount
    
    
    18
    
    
    -Liabilities
      settled
    
    
    (15
    )
    
    (29
    )Revisions
      to estimates
    
    
    -
    
    
    -Balance
      on December 31,
    
    $
    723
    
    $
    706
 
 In
addition to an accrual for asset retirement obligations, the Company maintains
$75,000 in escrow cash, which is legally restricted for the potential purpose of
settling asset retirement costs in accordance with certain state regulations.
Such cash deposits are included in other assets on the accompanying balance
sheet.
 **
 *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 December 31,
2004 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 effect on our financial position, results of operations or cash
flows.
 
 In
December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets an
amendment of APB 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 has
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. Earlier application is permitted for nonmonetary asset exchanges
occurring in fiscal periods beginning after the date this Statement is issued.
Retroactive application is not permitted. Management is analyzing the
requirements of this new Statement and believes that its adoption will not have
any significant impact on the Company’s financial position, results of
operations or cash flows.
 
 
 **(2)
Long-Term Debt**
 
 The
Company's revolving bank loan agreement with Bank of America provides for two
separate lines of credit with interest at the bank's prime rate minus 1⁄4 of 1
percent. The first line of credit or working capital loan provides for
borrowings up to $10,000,000 based on the total of 80 percent of eligible
accounts receivable and 50 percent of eligible inventories. Available borrowing
capacity under the working capital line is calculated monthly and as of December
31, 2004 was established at $10,000,000 with $7,500,000 of such amount
outstanding at December 31, 2004. The second line of credit or oil and gas
production loan provides for flexible borrowings, subject to a borrowing base
established semi-annually by the bank. The borrowing base was established at
$10,000,000 as of March 15, 2005 with the next scheduled borrowing base
re-determination date of September 1, 2005. As of December 31, 2004, $3,975,000
was outstanding under the oil and gas production loan facility. The working
capital loans also provide for the issuance of letters of credit. The amount of
each letter of credit obligation is deducted from the borrowing capacity. As of
December 31, 2004, letters of credit under this facility totaled $25,000. The
revolving 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.
  17
  Long-term
debt is summarized as follows (in thousands):
 December 31,2004
    
    
    2003Bank
      lines of credit, secured by substantially all ofthe
      Company’s assets (excluding Gulfmark andARM),
      due in eight quarterly installmentscommencing
      on October 31, 2006
    
    $
    11,475
    
    $
    11,475Less
      - current maturities
    
    
    -
    
    
    -Long-term
      debt
    
    $
    11,475
    
    $
    11,475
 
 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
$37,938,000.
 
 A
subsidiary of the Company, Gulfmark Energy, Inc. (“Gulfmark”), maintains a
separate banking relationship with BNP Paribas in order to provide up to $40
million in letters of credit and to provide financing for up to $6 million of
crude oil inventories and certain accounts receivable associated with sales of
crude oil. Such financing is provided on a demand note basis with interest at
the bank's prime rate plus 1 percent. The letter of credit and demand note
facilities are secured by substantially all of Gulfmark's and ARM’s assets. At
year-end 2004 and 2003, Gulfmark had no amounts outstanding under the
inventory-based line of credit. Gulfmark had approximately $19.1 million and $21
million in letters of credit outstanding as of December 31, 2004 and 2003,
respectively, in support of its crude oil purchasing activities. As of December
31, 2004, the Company had $5.8 million of eligible borrowing capacity under the
Gulfmark facility. Under this facility, BNP Paribas has the right to discontinue
the issuance of letters of credit without prior notification to the
Company.
 
 The
Company’s Adams Resources Marketing, Ltd. subsidiary (“ARM”) maintains a
separate banking relationship with BNP Paribas in order to support its natural
gas purchasing business. In addition to providing up to $25 million in letters
of credit, the facility finances up to $4 million of general working capital
needs. Such financing is provided on a demand note basis with interest at the
bank’s prime rate plus 1 percent. The letter of credit and demand note
facilities are secured by substantially all of ARM’s and Gulfmark’s assets. At
year-end 2004 and 2003, ARM had no working capital advances outstanding. ARM had
approximately $4.8 million and $9.2 million in letters of credit outstanding at
December 31, 2004 and 2003, respectively. Under this facility, BNP Paribas has
the right to discontinue the issuance of letters of credit without prior
notification to the Company.
 
 The
Company's weighted average effective interest rate for 2004, 2003 and 2002 was
4.8%, 3.1%, and 3.7%, respectively. No interest was capitalized during 2004,
2003 or 2002. At December 31, 2004, the scheduled aggregate principal maturities
of the Company's long-term debt are: 2006 - $1,434,375; 2007 - $5,737,500; and
2008 - $4,303,125.
 
 **(3)
Discontinued Operations**
 
 During
2003, Company 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, $4,896,000 and
$2,904,000 and after tax losses totaling $253,000, $3,232,000 and $1,817,000
during 2004, 2003 and 2002, respectively. Because of the losses sustained and
the desire to reduce working capital requirements, management decided to exit
this region and type of account. The New England operation had no fixed assets
or capitalized costs associated with intangibles. Therefore, an impairment
assessment of long-lived assets was not necessary. Further, all contracts
associated with this operation were initially recorded at fair value pursuant to
SFAS No. 133. As a result, a separate fair value analysis was not needed in
connection with the decision to discontinue New England business. The Company
completed its exit from this business during 2004. At year-end 2003, the Company
had current assets from this discontinued operation totaling $5,140,000,
consisting primarily of accounts receivable and risk management assets, and
current liabilities totaling $1,137,000, consisting primarily of accounts
payable and risk management liabilities. Such assets and liabilities were
liquidated in connection with the Company’s orderly exit from the business.
 
 **(4)
Income Taxes**
 
 The
following table shows the components of the Company's income tax provision
(benefit) (in thousands):
 Years ended December 31,2004
    
    
    2003
    
    
    2002Current:Federal
    
    $
    4,076
    
    $
    515
    
    $
    2,796State
    
    
    460
    
    
    110
    
    
    3014,536
    
    
    625
    
    
    3,097Deferred:Federal
    
    
    214
    
    
    674
    
    
    (2,087
    )State
    
    
    179
    
    
    36
    
    
    (246
    )$
    4,929
    
    $
    1,335
    
    $
    764
 
 The
following table summarizes the components of the income tax provision (benefit)
(in thousands):
 
 Years ended December 31,2004
    
    
    2003
    
    
    2002From
      continuing operations
    
    $
    5,059
    
    $
    3,056
    
    $
    1,751From
      discontinued operations
    
    
    (130
    )
    
    (1,664
    )
    
    (987
    )Cumulative
      effect of accounting change
    
    
    -
    
    
    (57
    )
    
    -$
    4,929
    
    $
    1,335
    
    $
    764
 
 Taxes
computed at the corporate federal income tax rate reconcile to the reported
income tax provision as follows (in thousands):
 
 Years
      ended December 31,2004
    
    
    2003
    
    
    2002Statutory
      federal income taxprovision
      at 34%
    
    $
    4,603
    
    $
    1,509
    
    $
    735State
      income tax provision,(net
      of federal benefit)
    
    
    321
    
    
    96
    
    
    55Federal
      statutory depletion
    
    
    (306
    )
    
    (304
    )
    
    (100
    )Book/tax
      basis adjustment
    
    
    120
    
    
    -
    
    
    -State
      net operating lossValuated
      allowance
    
    
    152
    
    
    -
    
    
    -Other
    
    
    39
    
    
    34
    
    
    74$
    4,929
    
    $
    1,335
    
    $
    764
 
 Deferred
income taxes primarily reflect the net difference between the financial
statement carrying amount in excess of the underlying tax basis of property and
equipment. The components of the federal deferred tax liability are as follows
(in thousands):
 
 Years
      Ended December 31,2004
    
    
    2003Current
      deferred taxesBad
      debts
    
    $
    146
    
    $
    663Mark-to-Market
      contracts
    
    
    (240
    )
    
    (317
    )Net
      current deferred taxasset
      (liability)
    
    
    (94
    )
    
    346Long-term
      deferred taxesGoodwill
    
    
    55
    
    
    94State
      net operating losses
    
    
    229
    
    
    236--Less
      valuation allowance
    
    
    (152
    )
    
    -Basis
      difference in foreign investments
    
    
    120
    
    
    -Property
    
    
    (3,612
    )
    
    (3,552
    )Other
    
    
    -
    
    
    (184
    )Net
      long-term deferred tax (liability)
    
    
    (3,360
    )
    
    (3,406
    )Net
      deferred tax (liability)
    
    $
    (3,454
    )
    $
    (3,060
    )
 
 The
Company recognizes the amount of taxes payable or refundable for the current
year and recognizes deferred tax liabilities and assets for the expected future
tax consequences of events and transactions that have been recognized in the
Company’s financial statements or tax returns. Deferred tax assets are reduced
by a valuation allowance when, in the opinion of management, it is more likely
than not that some or all of its deferred tax assets will not be realized.
Realization of the deferred income tax assets is dependent on generating
sufficient taxable income in future years. Management believes that it is more
likely than not that not all of the deferred income tax assts related to state
net operating losses will be realized and thus, a valuation allowance was
provided for as of December 31, 2004.
 
 **(5)
Fair Value of Financial Instruments and Concentration of Credit
Risk**
 
 *Fair
Value of Financial Instruments*
 
 The
carrying amount of cash equivalents are believed to approximate their fair
values because of the short maturities of these instruments. Substantially all
of the Company’s long and short-term debt obligations bear interest at floating
rates. As such, carrying amounts approximate fair values. For a discussion of
the fair value of commodity financial instruments see “Price Risk Management
Activities” in Note (1) of Notes to Consolidated Financial
Statements.
 
 *Concentration
of Credit Risk*
 
 Credit
risk represents the amount of loss the Company would absorb if its customers
failed to perform pursuant to contractual terms. Management of credit risk
involves a number of considerations, such as the financial profile of the
customer, the value of collateral held, if any, specific terms and duration of
the contractual agreement, and the customer's sensitivity to economic
developments. The Company has established various procedures to manage credit
exposure, including initial credit approval, credit limits, and rights of
offset. Letters of credit and guarantees are also utilized to limit credit risk.
 
 The
Company's largest customers consist of large multinational integrated oil
companies and utilities. In addition, the Company transacts business with
independent oil producers, major chemical concerns, crude oil and natural gas
trading companies and a variety of commercial energy users. Accounts receivable
associated with crude oil and natural gas marketing activities comprise
approximately 86 percent of the Company's total receivables as of December 31,
2004, and industry practice requires payment for purchases of crude oil to take
place on the 20 th of the
month following a transaction, while natural gas transactions are settled on the
25 th of the
month following a transaction. The Company's credit policy and the relatively
short duration of receivables mitigate the uncertainty typically associated with
receivables management. The Company had accounts receivable from two customers
that comprised 13.6 percent and 10.3 percent, respectively, of total receivables
at December 31, 2003. One customer represented 11.6 percent of total accounts
receivable as of December 31, 2004.
 
 There
were no single significant bad debt write-offs in 2004, 2003 and 2002. An
allowance for doubtful accounts is provided where appropriate and accounts
receivable presented herein are net of allowances for doubtful accounts of
$384,000 and $1,935,000 at December 31, 2004 and 2003, respectively. An analysis
of the changes in the allowance for doubtful accounts is presented as follows
(in thousands):
 
 2004
    
    2003
    
    2002Balance,
      beginning of year
    
    $
    1,935
    
    $
    1,723
    
    $
    1,993Provisions
      for bad debts
    
    
    90
    
    
    433
    
    
    390Less:
      Write-offs and recoveries
    
    
    (1,641
    )
    
    (221
    )
    
    (660
    )Balance,
      end of year
    
    $
    384
    
    $
    1,935
    
    $
    1,723
 
 **(6)
Employee Benefits**
 
 The
Company maintains a 401(k) savings plan for the benefit of its employees.
Company contributions to the plan were $454,000 in 2004, $384,000 in 2003 and
$388,000 in 2002. There are no pension or retirement plans maintained by the
Company.
 
 **(7)
Transactions with Related Parties**
 
 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 no better than those afforded the
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 December 31, 2004 and 2003, the Company owed a combined net
total of $349,500 and $1,088,000, respectively, to these related parties. In
connection with the operation of certain oil and gas properties, the Company
also charges such related parties for administrative overhead primarily as
prescribed by the Council of Petroleum Accountants Society (“COPAS”) Bulletin 5.
Such overhead recoveries totaled $152,000 in 2004 and $138,000 in
2003.
  18
  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.
 
 
 **(8)
Commitments and Contingencies**
 
 The
Company has operating lease arrangements for tractors, trailers, office space,
and other equipment and facilities. Rental expense for the years ended December
31, 2004, 2003, and 2002 was $6,650,000, $5,831,000 and $5,944,000,
respectively. At December 31, 2004, commitments under long-term non-cancelable
operating leases for the next five years and thereafter are payable as follows:
2005 - $4,604,000; 2006 - $3,841,000; 2007 - $3,530,000; 2008 - $3,329,000; 2009
- $1,199,000 and thereafter - $233,000.
 
 In April
2003, Gulfmark Energy Marketing, Inc a wholly owned subsidiary of the company
previously involved in a crude oil marketing joint venture, received a demand
for arbitration seeking monetary damages of $11.6 million and a re-audit of the
joint venture activity for the period of its existence from May 2000 through
October 2001. This claim is further described in Note 11 of Notes to
Consolidated Financial Statements. This matter was resolved in July 2004 by the
Company assuming 100 percent of any future obligations of the joint venture plus
a cash payment of $350,000 to the joint venture claimant in exchange for an
assignment of all accounts receivable from the joint venture and relief from the
Company’s cash obligations otherwise due to the joint venture.
 
 In March
2004, a suit styled *Le
Petit Chateau Le Luxe, et. a. 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 is a party to motor vehicle accidents, worker compensation
claims and 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.
  19
  **(9)
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 performance under these guarantees to be remote.
Aggregate guaranteed residual values for tractors and trailers under operating
leases as of December 31, 2004 are as follows (in thousands):
 
 2005
    
    2006
    
    2007
    
    2008
    
    Thereafter
    
    TotalLease
      residual values
    
    $
    762
    
    $
    150
    
    $
    -
    
    $
    304
    
    $
    2,180
    
    $
    3,396
 
 Presently,
neither the Company nor any of its subsidiaries have any other types of
guarantees outstanding that require liability recognition under the provisions
of Interpretation No. 45.
 
 This
interpretation also sets forth disclosure requirements for guarantees including
the guarantees by a parent company on behalf of its subsidiaries. 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
obligations, 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, such obligations are not recorded again on the books
of the parent. The parent would only be called upon to perform under the
guarantee in the event of a payment default by the applicable subsidiary
company. In satisfying such obligations, the parent would first look to the
assets of the defaulting subsidiary company. As of December 31, 2004, the amount
of parental guaranteed obligations are approximately as follows (in
thousands):
 
 2005
    
    2006
    
    2007
    
    2008
    
    Thereafter
    
    TotalBank
      Debt
    
    $
    -
    
    $
    1,434
    
    $
    5,738
    
    $
    4,303
    
    $
    -
    
    $
    11,475Operating
      leases
    
    
    4,604
    
    
    3,841
    
    
    3,530
    
    
    3,329
    
    
    1,432
    
    
    16,736Lease
      residual values
    
    
    762
    
    
    150
    
    
    -
    
    
    304
    
    
    2,180
    
    
    3,396Commodity
      purchases
    
    
    18,080
    
    
    -
    
    
    -
    
    
    
    
    
    
    
    
    18,080Letters
      of credit
    
    
    23,900
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    23,900$
    47,346
    
    $
    5,425
    
    $
    9,268
    
    $
    7,936
    
    $
    3,612
    
    $
    73,587
 
 **(10)
Segment Reporting**
 
 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. Information concerning the Company's
various business activities is summarized as follows (in
thousands):
  20
  
 Segment
      Operating
    
    Depreciation
      Depletion and
    
    Property
      and EquipmentRevenues
    
    
    Earnings
      (Loss
    )
    
    Amortization
    
    
    AdditionsYear
      ended December 31, 2004 -Marketing
    
    $
    2,011,669
    
    $
    13,783
    
    $
    1,498
    
    $
    1,278Transportation
    
    
    47,323
    
    
    5,687
    
    
    2,125
    
    
    6,736Oil
      and gas
    
    
    10,796
    
    
    2,362
    
    
    2,949
    
    
    4,147$
    2,069,788
    
    $
    21,832
    
    $
    6,572
    
    $
    12,161Year
      ended December 31, 2003 -Marketing
    
    $
    1,677,728
    
    $
    12,244
    
    $
    1,397
    
    $
    1,798Transportation
    
    
    35,806
    
    
    973
    
    
    2,093
    
    
    1,377Oil
      and gas
    
    
    8,395
    
    
    2,310
    
    
    2,175
    
    
    4,586$
    1,721,929
    
    $
    15,527
    
    $
    5,665
    
    $
    7,761Year
      ended December 31, 2002 -Marketing
    
    $
    1,726,194
    
    $
    10,872
    
    $
    1,611
    
    $
    150Transportation
    
    
    36,406
    
    
    2,142
    
    
    1,838
    
    
    1,908Oil
      and gas
    
    
    4,750
    
    
    (633
    )
    
    2,116
    
    
    2,561$
    1,767,350
    
    $
    12,381
    
    $
    5,565
    
    $
    4,619
 ____________
 Note:
 - In 2002,
the oil and gas segment operating loss totaled $633,000. Such loss includes $1.7
million in dry hole costs and oil and gas property valuation
write-downs.
 
 Intersegment
sales are insignificant. All sales by the Company occurred in the United States.
In each of 2004 and 2003, the Company had sales to one customer that totaled
$249,482,000 and $177,000,000, respectively. Such sales were attributable to the
Company’s marketing segment. No other customers accounted for greater than 10
percent of sales in any of the three years presented herein. The loss of any of
the Company’s 10 percent customers would not have a material adverse effect on
the Company’s future operating results and all such customers could be readily
replaced.
 
 Segment
operating earnings reflect revenues net of operating costs and depreciation,
depletion and amortization and are reconciled to earnings from continuing
operations before income taxes, as follows (in thousands):
 
 Years
      Ended December 31,2004
    
    
    2003
    
    
    2002Segment
      operating earnings
    
    $
    21,832
    
    $
    15,527
    
    $
    12,381General
      and administrative expenses
    
    
    (7,867
    )
    
    (6,299
    )
    
    (7,259
    )Operating
      earnings
    
    
    13,965
    
    
    9,228
    
    
    5,122Interest
      income
    
    
    62
    
    
    362
    
    
    115Interest
      expense
    
    
    (107
    )
    
    (108
    )
    
    (117
    )Earnings
      from continuing operationsbefore
      income taxes
    
    $
    13,920
    
    $
    9,482
    
    $
    5,120
 
  21
  Identifiable
assets by industry segment are as follows (in thousands):
 
 Years
      Ended December 31,2004
    
    
    2003
    
    
    2002Marketing
    
    $
    178,691
    
    $
    144,722
    
    $
    124,336Transportation
    
    
    22,308
    
    
    14,564
    
    
    15,931Oil
      and gas
    
    
    15,354
    
    
    13,817
    
    
    11,504Discontinued
      operation
    
    
    -
    
    
    5,140
    
    
    20,994Other
    
    
    22,501
    
    
    32,364
    
    
    29,355$
    238,854
    
    $
    210,607
    
    $
    202,120
 
 Other
identifiable assets are primarily corporate cash, accounts receivable, and
properties not identified with any specific segment of the Company's business.
 
 **(11)
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 net earnings of the
venture and accounted for its interest under the equity method of accounting.
The Company included its net investment in the venture in the consolidated
balance sheet and its equity in the venture’s pretax earnings was included in
marketing segment revenues in the consolidated statement of earnings. Other than
ordinary trade credit under standard industry terms, the joint venture had no
third party debt or other obligations. The participants maintained management of
cash flow and all cash flow requirements.
 
 Effective
November 1, 2001, the joint venture participants agreed to dissolve the venture
pursuant to the terms of a joint venture dissolution agreement. As part of the
consideration for terminating the joint venture, the Company was to receive a
monthly per barrel fee to be paid by the former joint venture co-participant for
a period of sixty months on certain barrels purchased by the participant in the
offshore Gulf of Mexico region. Included in 2002 marketing segment revenues is
$2,433,000 of pre-tax earnings derived from this fee. While the co-venture
participant willingly paid this fee through January 31, 2002 activity, effective
with February 2002 business, the participant notified the Company of its intent
to withhold the fee until they audited the previous joint venture activity.
Subsequently, due primarily to credit constraints, the co-participant
substantially curtailed and ultimately ceased its purchase of crude oil in the
affected region.
 
 In April
2003, the Company received a demand for arbitration seeking monetary damages of
$11.6 million 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. This
settlement was completed by the Company assuming 100 percent of any future
obligations of the joint venture plus a cash payment of $350,000 to the joint
venture claimant in exchange for an assignment of all accounts receivable from
the joint venture. In addition, the Company was relieved from any cash
obligations otherwise due to the joint venture. In connection with the
resolution of this dispute, the Company recorded $1,476,000 as a reduction of
cost of sales during 2004.
 
 The
Company continues to implement the final wind-down and settlement of open trade
account items and the Company will receive or pay the entire balance of such
cash proceeds or requirements.
  22
  **(12)
Quarterly Financial Data (Unaudited) -**
 
 Selected
quarterly financial data and earnings per share of the Company are presented
below for the years ended December 31, 2004 and 2003 (in thousands, except per
share data):
 
 Earnings
      fromContinuingOperations
    
    Net
      Earnings
    
    DividendsPer
    
    
    
    Per
    
    
    
    PerRevenues
    
    Amount
    
    Share
    
    Amount
    
    Share
    
    Amount
    
    Share**2004
      -**March
      31
    
    $
    461,315
    
    $
    1,191
    
    $
    .28
    
    $
    938
    
    $
    .22
    
    $
    -
    
    $
    -June
      30
    
    
    495,616
    
    
    1,118
    
    
    .27
    
    
    1,118
    
    
    .27
    
    
    -
    
    
    -September
      30
    
    
    550,563
    
    
    4,352
    
    
    1.03
    
    
    4,352
    
    
    1.03
    
    
    -
    
    
    -December
      31
    
    
    562,294
    
    
    2,200
    
    
    .52
    
    
    2,200
    
    
    .52
    
    
    1,265
    
    
    .30$
    2,069,788
    
    $
    8,861
    
    $
    2.10
    
    $
    8,608
    
    $
    2.04
    
    $
    1,265
    
    $
    .30**2003
      -**March
      31
    
    $
    473,290
    
    $
    2,493
    
    $
    .59
    
    $
    348
    
    $
    .08
    
    $
    -
    
    $
    -June
      30
    
    
    426,967
    
    
    2,085
    
    
    .50
    
    
    1,430
    
    
    .34
    
    
    -
    
    
    -September
      30
    
    
    399,243
    
    
    827
    
    
    .20
    
    
    673
    
    
    .16
    
    
    -
    
    
    -December
      31
    
    
    422,429
    
    
    1,021
    
    
    .24
    
    
    651
    
    
    .16
    
    
    970
    
    
    .23$
    1,721,929
    
    $
    6,426
    
    $
    1.53
    
    $
    3,102
    
    $
    .74
    
    $
    970
    
    $
    .23
 
 The above
unaudited interim financial data reflect all adjustments that are in the opinion
of management necessary to a fair statement of the results for the period
presented. All such adjustments are of a normal recurring nature.
 
 **(13)**  **Oil
and Gas Producing Activities (Unaudited)**
 
 The
following information concerning the Company’s oil and gas segment has been
provided pursuant to Statement of Financial Accounting Standards No. 69,
“Disclosures about Oil and Gas Producing Activities.” The Company’s oil and gas
exploration and production activities are conducted in the United States,
primarily along the Gulf Coast of Texas and Louisiana.
 
 *Oil
and Gas Producing Activities (Unaudited) -*
 
 Total
costs incurred in oil and gas exploration and development activities, all
incurred within the United States, were as follows (in thousands, except per
barrel information):
 
 Years
      Ended December 31,2004
    
    2003
    
    2002Property
      acquisition costsUnproved
    
    $
    574
    
    $
    1,311
    
    $
    1,126Proved
    
    
    -
    
    
    -
    
    
    -Exploration
      costsExpensed
    
    
    2,504
    
    
    1,638
    
    
    1,177Capitalized
    
    
    1,565
    
    
    1,339
    
    
    75Development
      costs
    
    
    2,210
    
    
    1,936
    
    
    1,248Total
      costs incurred
    
    $
    6,853
    
    $
    6,224
    
    $
    3,626
 
 The
aggregate capitalized costs relative to oil and gas producing activities are as
follows (in thousands):
 
 December
      31,2004
    
    2003Unproved
      oil and gas properties
    
    $
    3,293
    
    $
    2,713Proved
      oil and gas properties
    
    
    42,096
    
    
    38,95345,389
    
    
    41,666Accumulated
      depreciation, depletionand
      amortization
    
    
    (32,242
    )
    
    (29,292
    )Net
      capitalized cost
    
    $
    13,147
    
    $
    12,374
 
 **
 *Estimated Oil and Natural Gas
Reserves (Unaudited) -*
 
 The
following information regarding estimates of the Company's proved oil and gas
reserves, all located in the United States, is based on reports prepared on
behalf of the Company by its independent and in-house licensed petroleum
engineers. Approximately ninety-five percent of the values presented herein were
determined by the independent petroleum engineers. Because oil and gas reserve
estimates are inherently imprecise and require extensive judgments of reservoir
engineering data, they are generally less precise than estimates made in
conjunction with financial disclosures. The revisions of previous estimates as
reflected in the table below result from more precise engineering calculations
based upon additional production histories and price changes. Proved developed
and undeveloped reserves are presented as follows (in thousands):
 
 Years
      Ended December 31,2004
    
    2003
    
    2002Natural
    
    
    
    Natural
    
    
    
    NaturalGas
    
    Oil
    
    Gas
    
    Oil
    
    Gas
    
    Oil(Mcf’s)
    
    (Bbls.)
    
    (Mcf’s)
    
    (Bbls.)
    
    (Mcf’s)
    
    (Bbls.)Total
      proved reserves-Beginning
      of year
    
    
    8,971
    
    
    438
    
    
    7,480
    
    
    579
    
    
    7,618
    
    
    618Revisions
      of previous estimates
    
    
    122
    
    
    (52
    )
    
    37
    
    
    (223
    )
    
    206
    
    
    (1
    )Oil
      and gas reserve purchases
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -Extensions,
      discoveries andother
      reserve additions
    
    
    3,166
    
    
    121
    
    
    2,693
    
    
    144
    
    
    703
    
    
    17Production
    
    
    (1,309
    )
    
    (71
    )
    
    (1,239
    )
    
    (62
    )
    
    (1,047
    )
    
    (55
    )End
      of year
    
    
    10,950
    
    
    436
    
    
    8,971
    
    
    438
    
    
    7,480
    
    
    579Proved
      developed reserves-End
      of year
    
    
    10,220
    
    
    410
    
    
    8,971
    
    
    438
    
    
    7,480
    
    
    579
 
 *Standardized
Measure of Discounted Future Net Cash Flows from Oil and Gas Operations and
Changes Therein (Unaudited) -*
 
 The
standardized measure of discounted future net cash flows was determined based on
the economic conditions in effect at the end of the years presented, except in
those instances where fixed and determinable gas price escalations are included
in contracts. The disclosures below do not purport to present the fair market
value of the Company's oil and gas reserves. An estimate of the fair market
value would also take into account, among other things, the recovery of reserves
in excess of proved reserves, anticipated future changes in prices and costs, a
discount factor more representative of the time value of money and risks
inherent in reserve estimates. The standardized measure of discounted future net
cash flows is presented as follows (in thousands):
 Y
      Years
      Ended December 31,2004
    
    2003
    
    2002Future
      gross revenues
    
    $
    83,668
    
    $
    64,442
    
    $
    47,887Future
      costs -Lease
      operating expenses
    
    
    (20,128
    )
    
    (18,035
    )
    
    (16,142
    )Development
      costs
    
    
    (1,228
    )
    
    (221
    )
    
    (360
    )Future
      net cash flows before income taxes
    
    
    62,312
    
    
    46,186
    
    
    31,385Discount
      at 10% per annum
    
    
    (27,771
    )
    
    (18,351
    )
    
    (14,657
    )Discounted
      future net cash flowsbefore
      income taxes
    
    
    34,541
    
    
    27,835
    
    
    16,728Future
      income taxes, net of discount at10%
      per annum
    
    
    (11,744
    )
    
    (9,464
    )
    
    (5,687
    )Standardized
      measure of discountedFuture
      net cash flows
    
    $
    22,797
    
    $
    18,371
    
    $
    11,041
 
 The
reserve estimates provided at December 31, 2004, 2003 and 2002 are based on
year-end market prices of $40.50, $30.15 and $27.94 per barrel for crude oil and
$6.06, $5.71 and $4.20 per Mcf for natural gas, respectively. The year-end
December 31, 2004 price used in the 2004 reserve estimate is comparable to
average actual December 2004 price received for sales of crude oil ($41.65 per
barrel) and sales of natural gas ($6.80 per mcf).
 
 The
following are the principal sources of changes in the standardized measure of
discounted future net cash flows (in thousands):
 Years
      Ended December 31,2004
    
    2003
    
    2002Beginning
      of year
    
    $
    18,371
    
    $
    11,041
    
    $
    6,173Revisions
      to reserves proved in prior years -Net
      change in prices and production costs
    
    
    2,306
    
    
    6,508
    
    
    9,016Net
      change due to revisions in quantity estimates
    
    
    (534
    )
    
    (3,235
    )
    
    353Accretion
      of discount
    
    
    1,835
    
    
    1,465
    
    
    763Production
      rate changes and other
    
    
    (1,280
    )
    
    1,228
    
    
    (2,375
    )Total
      revisions
    
    
    2,327
    
    
    5,966
    
    
    7,757Purchase
      of oil and gas reserves, net of futureproduction
      costs
    
    
    -
    
    
    -
    
    
    -New
      field discoveries and extensions, net of futureproduction
      costs
    
    
    12,194
    
    
    11,264
    
    
    2,278Sales
      of oil and gas produced, net of production costs
    
    
    (7,815
    )
    
    (6,123
    )
    
    (2,660
    )Net
      change in income taxes
    
    
    (2,280
    )
    
    (3,777
    )
    
    (2,507
    )Net
      change in standardized measure ofdiscounted
      future net cash flows
    
    
    4,426
    
    
    7,330
    
    
    4,868End
      of year
    
    $
    22,797
    
    $
    18,371
    
    $
    11,041
 
  23
  *Results
of Operations for Oil and Gas Producing Activities (Unaudited) -*
 
 The
results of oil and gas producing activities, excluding corporate overhead and
interest costs, are as follows (in thousands):
 Years
      Ended December 31,2004
    
    2003
    
    2002Revenues
    
    $
    10,796
    
    $
    8,395
    
    $
    4,750Costs
      and expenses -Production
    
    
    2,981
    
    
    2,272
    
    
    2,090Exploration
    
    
    2,504
    
    
    1,638
    
    
    1,177Depreciation,
      depletion and amortization
    
    
    2,949
    
    
    2,175
    
    
    2,116Operating
      income (loss) before income taxes
    
    
    2,362
    
    
    2,310
    
    
    (633
    )Income
      tax (expense) benefit
    
    
    (803
    )
    
    (788
    )
    
    215Operating
      income (loss)
    
    $
    1,559
    
    $
    1,522
    
    $
    (418
    )
 
 Item
9.  CHANGES
IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
 
 None
 
 Item
9A.  CONTROLS
AND PROCEDURES
 
 The
Company maintains disclosure controls and procedures that are designed to ensure
that information required to be disclosed in the reports under the Securities
Exchange Act of 1934, as amended (“Exchange Act”) are communicated, processed,
summarized and reported within the time periods specified in the SEC’s rules and
forms. At the end of the Company’s fourth quarter of 2004, as required by Rules
13a-15 and 15d-15 of the Exchange Act, an evaluation was carried out under the
supervision and with the participation of the Company’s management, including
the Chief Executive Officer and Chief Financial Officer, of the effectiveness of
the design and operation of disclosure controls and procedures (as defined in
Rule 13a-15(e) under the Exchange Act). 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 as of that
date. No changes in internal controls over financial reporting identified in
connection with its evaluation (as required by Rules 13a-15(d) and 15d-15(d) of
the Exchange Act) occurred during the fourth quarter of 2004 that affected, or
were reasonably likely to materially affect, the Company’s internal control over
financial reporting.
 
 
 Item 9B.
OTHER
 
 None
  24
  PART
III
 
 
 Item 10.
DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
 
 The
information concerning executive officers of the Company is included in Part I.
The information concerning directors of the Company is incorporated by reference
from the Company’s definitive Proxy Statement for the Annual Meeting of
Shareholders to be held May 18, 2005, under the heading “Election of Directors”
to be filed with the Commission not later than 120 days after the end of the
fiscal year covered by this Form 10-K.
 
 Item 11.
EXECUTIVE COMPENSATION
 
 The
information required by Item 11 is incorporated by reference from the Company’s
definitive Proxy Statement for the Annual Meeting of Shareholders to be held May
18, 2005, under the heading “Executive Compensation” to be filed with the
Commission not later than 120 days after the end of the fiscal year covered by
this Form 10-K.
 
 Item 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
 
 The
information required by Item 12 is incorporated by reference from the Company’s
definitive Proxy Statement for the Annual Meeting of Shareholders to be held May
18, 2005, under the heading “Voting Securities and Principal Holders Thereof” to
be filed with the Commission not later than 120 days after the end of the fiscal
year covered by this Form 10-K.
 
 Item 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
 
 The
information required by Item 13 is incorporated by reference from the Company’s
definitive Proxy Statement for the Annual Meeting of Shareholders to be held May
18, 2005, under the heading “Transactions with Related Parties” to be filed with
the Commission not later than 120 days after the end of the fiscal year covered
by this Form 10-K.
 
 
 Item 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
 
 The
information required by Item 14 is incorporated by reference from the Company’s
definitive Proxy Statement for the Annual Meeting of Shareholders to be held May
18, 2005, under the heading “Audit and Other Services” to be filed with the
Commission not later than 120 days after the end of the fiscal year covered by
this Form 10-K.
 
 
  25
  PART
IV
 
 
 Item
15.  EXHIBITS,
FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 10-K
 
 (a)  The
following documents are filed as a part of this Form 10-K:
 
 1.  Financial
Statements
 
 Report of Independent
Public Accountants
 
 Consolidated Balance
Sheet as of December 31, 2004 and 2003
 
 Consolidated
Statement of Operations for the Years Ended
 December 31, 2004,
2003 and 2002
 
 Consolidated
Statement of Shareholders' Equity for the Years Ended
 December 31, 2004,
2003 and 2002
 
 Consolidated
Statement of Cash Flows for the Years Ended
 
 December 31, 2004,
2003 and 2002
 
 Notes to Consolidated
Financial Statements
 
 2. All
financial schedules have been omitted because they are not applicable or the
required information is shown in the financial statements or notes
thereto.
 
 3. Exhibits
required to be filed
 
 3(a)  -  Certificate
of Incorporation of the Company, as amended. (Incorporated by reference to
Exhibit 3(a) filed with the Annual Report on Form 10-K (-File No. 1-7908) of the
Company for the fiscal year ended December 31, 1987)
 
 3(b)  -  Bylaws of
the Company, as amended (Incorporated by reference to Exhibits 3.2 and 3.2.1 of
Amendment No. 1 to the Registration Statement on Form S-1 filed with the
Securities and Exchange Commission on October 29, 1973 - File No. 2-48144)
 
 3(c)  -  Amendment
to the Bylaws of the Company to add an Article VII, Section 8. Indemnification
of Directors, Officers, Employees and Agents (Incorporated by reference to
Exhibit 3(c) of the Annual Report on Form 10-K (-File No. 1-7908) of the Company
for the fiscal year ended December 31, 1986)
 
 3(d)  -  Adams
Resources & Energy, Inc. and Subsidiaries’ Code of Ethics (Incorporated by
reference to Exhibit 3(d) of the Annual Report on Form 10-K (-File No. 1-7908)
of the Company for the fiscal year ended December 31, 2002)
 
 4(a)  -  Specimen
common stock Certificate (Incorporated by reference to Exhibit 4(a) of the
Annual Report on Form 10-K of the Company (-File No. 1-7908) for the fiscal year
ended December 31, 1991)
 
 4(b)*  -  Twelfth
Amendment to Loan Agreement between Service Transport Company et al and Bank of
America, N.A. dated December 21, 2004.
 
 21*  -  Subsidiaries
of the Registrant
 
 31.1*  -  Adams
Resources & Energy, Inc. Certification Pursuant To 17 CFR 13a-14
(a)/15d-14(a), As Adopted Pursuant To Section 302 Of The Sarbanes-Oxley Act of
2002
 
 31.2*  -  Adams
Resources & Energy, Inc. Certification Pursuant To 17 CFR
13a-14(a)/15d-14(a), As Adopted Pursuant To Section 302 Of The Sarbanes-Oxley
Act of 2002
 
 32.1*  -  Certification
Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant To Section 906 Of The
Sarbanes-Oxley Act of 2002
 
 32.2*  -  Certification
Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant To Section 906 Of The
Sarbanes-Oxley Act of 2002
 
 ______________________________
 * - Filed
herewith
 
 Copies of
all agreements defining the rights of holders of long-term debt of the Company
and its subsidiaries, which agreements authorize amounts not in excess of 10% of
the total consolidated assets of the Company, are not filed herewith but will be
furnished to the Commission upon request.
  26
  **SIGNATURES**
 
 Pursuant
to the requirements of Section 13 or 15(d) 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)By
      /s/ RICHARD B. ABSHIRE
    By/s/
      K. S. ADAMS, JR.(Richard
      B. Abshire,
    (K.
      S. Adams, Jr.,Vice
      President, Director
    Chairman
      of the Board andand
      Chief Financial Officer)
    Chief
      Executive Officer)
 
 
 
 
 Date:
March 15, 2005
 
 Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the Registrant and in the
capacities and on the date indicated.
 
 
 By/s/
      FRANK T. WEBSTER
    By/s/
      VINCENT H. BUCKLEY(Frank
      T. Webster, Director)
    (Vincent
      H. Buckley, Director)By/s/
      EDWARD WIECK
    By/s/
      E. C. REINAUER, JR.(Edward
      Wieck, Director)
    (E.
      C. Reinauer, Jr., Director)By/s/
      E. JACK WEBSTER, JR.
    By/s/
      R. H. STEVENS(E.
      Jack Webster, Jr., Director)
    (R.
      H. Stevens, Director)By/s/
      WILLIAM B. WIENER III(William
      B. Wiener III, Director)
  27
  
 **EXHIBIT
INDEX**
 Exhibit
 Number   Description
 
 3(a)  -  Certificate
of Incorporation of the Company, as amended. (Incorporated by reference to
Exhibit 3(a) filed with the Annual Report on Form 10-K of the Company for the
fiscal year ended December 31, 1987)
 
 3(b)  -  Bylaws of
the Company, as amended (Incorporated by reference to Exhibits 3.2 and 3.2.1 of
Amendment No. 1 to the Registration Statement on Form S-1 filed with the
Securities and Exchange Commission on October 29, 1973 - File No. 2-48144)
 
 3(c)  -  Amendment
to the Bylaws of the Company to add an Article VII, Section 8. Indemnification
of Directors, Officers, Employees and Agents (Incorporated by reference to
Exhibit 3(c) of the Annual Report on Form 10-K of the Company for the fiscal
year ended December 31, 1986)
 
 3(d)  -  Adams
Resources & Energy, Inc. and Subsidiaries’ Code of Ethics (Incorporated by
reference to Exhibit 3(d) of the Annual Report on Form 10-K of the Company for
the fiscal year ended December 31, 2002)
 
 4(a)  -  Specimen
common stock Certificate (Incorporated by reference to Exhibit 4(a) of the
Annual Report on Form 10-K of the Company for the fiscal year ended December 31,
1991)
 
 4(b)  -  Loan
Agreement between Adams Resources & Energy, Inc. and NationsBank Texas N.A.
dated October 27, 1993 (Incorporated by reference to Exhibit 4(b) of the Annual
Report on Form 10-K of the Company for the fiscal year ended December 31, 1993)
 
 4(c)*  -  Twelfth
Amendment to Loan Agreement between Service Transport Company et al and Bank of
America, N.A. dated December 21, 2004.
 
 21*  -  Subsidiaries
of the Registrant
 
 31.1*  -  Certification
Pursuant to 17 CFR 13a-14(a)/15d-14(a), As Adopted Pursuant to Section 302 of
the Sarbarnes-Oxley Act of 2002
 
 31.2*  -  Certification
Pursuant to 17 CFR 13a-14(a)/15d-14(a), As Adopted Pursuant to Section302 of the
Sarbarnes-Oxley Act of 2002
 
 32.1*  -  Certification
Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
 
 32.2*  -  Certification
Pursuant To 18 U..S.C. Section 1350, As Adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
 
 ______________________________
 * - Filed
herewith


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