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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, 2003
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
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE
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. [X]
Indicate by check mark whether the registrant is an accelerated filer
as defined in Rule 126-2 of the Act. YES [ ] NO [X]
The aggregate market value of the voting stock held by nonaffiliates as
of June 30, 2003 was $18,392,692. A total of 4,217,596 shares of Common Stock
were outstanding at March 1, 2004.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for Annual Meeting of Stockholders to be held
May 14, 2004 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 revenues, operating results and identifiable assets of each industry segment
for the three years ended December 31, 2003 are set forth in Note (10) of Notes
to Consolidated Financial Statements included elsewhere herein.
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 2003, Gulfmark purchased approximately
85,000 barrels per day of crude oil at the wellhead or lease level. Gulfmark
also operates 70 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 317,000 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 back-to-back fixed price
arrangements are in place, the contracted sales price is also pegged 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. It is the Company's policy not to hold crude oil, natural gas,
futures contracts or other derivative products for the purpose of speculating on
price changes. While the Company's policies are designed to minimize market
risk, some degree of exposure to unforeseen fluctuations in market conditions
remains.
I-1
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 241 truck tractors and 350
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 the Houston terminal facility. This terminal is 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-9002 Quality Management
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-9002 certification, the
American Chemistry Council recognizes STC as a Responsible Care(C) Partner.
Responsible Care(C) 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.
I-2
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 327 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, 2003. 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 Wells
--------- --------- -----------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Texas............. 65 15.14 70 7.85 135 22.99
Other............. 132 3.49 60 8.30 192 11.79
--- ---- -- ---- --- -----
197 18.63 130 16.15 327 34.78
=== ===== === ===== === =====
Acreage--The following table sets forth the Company's gross and net
developed and undeveloped acreage as of December 31, 2003. Gross acreage
represents the Company's direct ownership and net acreage represents the sum or
fractional interests owned.
Developed Acreage Undeveloped Acreage
----------------- -------------------
Gross Net Gross Net
----- --- ----- ---
Texas............. 61,548 11,204 73,823 8,001
Other............. 8,567 1,266 4,238 772
------ ------ ------ -----
70,115 12,470 78,061 8,773
====== ====== ====== =====
Drilling Activity--The following table sets forth the Company's
drilling activity for each of the three years ended December 31, 2003. All
drilling activity was onshore in Texas and Louisiana.
2003 2002 2001
-------------- -------------- -----------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Exploratory wells drilled
- Productive.................. 7 .49 1 .10 - -
- Dry......................... 11 1.03 4 1.08 5 .65
Development wells drilled
- Productive.................. 16 1.42 12 .99 17 1.41
- Dry......................... 1 .20 4 .22 2 .05
In addition to the above wells drilled and completed, at year-end 2003,
the Company had one well in process, which was successfully completed in 2004.
I-3
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, 2003, are presented in the table below (in thousands).
December 31,
------------------------------------------
2003 2002 2001
---- ---- ----
Crude oil (barrels)........................................... 438 579 618
Natural gas (mcf)............................................. 8,971 7,480 7,618
Future net cash flows before income taxes..................... $46,186 $31,385 $16,989
Present value of future net cash flows before
income taxes.............................................. $27,835 $16,728 $ 9,353
The estimates of oil and gas reserves and future net revenues from oil
and gas reserves were made by the Company's independent petroleum engineers. The
reserve value estimates provided at December 31, 2003, 2002 and 2001 are based
on year-end market prices of $30.15, $27.94 and $17.55 per barrel for crude oil
and $5.71, $4.20 and $2.34 per mcf for natural gas, respectively.
Reserve estimates are based on many judgmental 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, 2003 was as follows:
Years Ended Crude Oil Natural
December 31, (barrels) Gas (mcf)
------------ --------- ---------
2003............................ 61,900 1,239,000
2002............................ 55,000 1,047,000
2001............................ 64,000 1,031,000
I-4
Certain financial information relating to the Company's oil and gas
activities is summarized as follows:
Years Ended December 31,
--------------------------
2003 2002 2001
---- ---- ----
Average oil and condensate
sales price per barrel........................... $ 30.67 $ 26.10 $27.08
Average natural gas
sales price per mcf.............................. $ 5.23 $ 3.17 $ 4.23
Average production cost, per equivalent
barrel, charged to expense...................... $ 8.48 $ 9.10 $ 9.08
For comparative purposes, prices received by the Company's oil and gas
division at varying points in time during 2003 were as follows:
Crude Oil Natural Gas
--------- -----------
Average Annual Price for 2003 ................ $30.67 per barrel $5.23 per mcf
Average Price for December 2003 .............. $29.87 per barrel $4.45 per mcf
Price at December 31, 2003.................... $30.15 per barrel $5.71 per mcf
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 License-- The Company holds an undivided 25
percent interest in an offshore block in the United Kingdom sector of the
Central North Sea. Rights to the Block were awarded in 2003 under the United
Kingdom's 21st licensing round and is one of the new Promote Licenses. 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. The original plan, as approved by the UK Department of
Trade & Industry, requires the reprocessing of existing seismic data and the
submittal of a drilling plan within two years from the effective date (October
1, 2003). 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 Block is located approximately 200 miles east of
Aberdeen, Scotland not far from the Forties and Buchan Fields. None of the
Company's partners in the Block are affiliates of the Company.
Reference is made to Note (14) of the Notes to Consolidated Financial
Statements for additional disclosures relating to oil and gas exploration and
production activities.
I-5
Environmental Compliance and Regulation
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.
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.
I-6
All states in which the Company owns significant 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. The EPA's Office of
Underground Tanks and applicable state laws have established 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 Company would be obligated for clean
up costs. The Company has secured insurance covering both third party liability
and clean up costs. Currently, the Company has three active underground storage
tanks.
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.
As a result of terrorist events, the Company has increased 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 transponders are also equipped with a
"distress button" to notify the dispatcher that the driver is in immediate
distress. 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
I-7
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, 2003,
the Company is unaware of any unresolved environmental issues for which an
accounting accrual is necessary.
Employees
At December 31, 2003 the Company employed 634 persons, 14 of whom were
employed in the exploration and production of oil and gas, 243 in the marketing
of crude oil, natural gas and petroleum products, 367 in transportation
operations and 10 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, 2003 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) Competition, (c) Regulatory Status and Potential
Environmental Liability, (d) Management's Discussion and Analysis of Financial
Condition and Results of Operations, (e) Liquidity and Capital Resources, (f)
Critical Accounting Policies and Use of Estimates, (g) Quantitative and
Qualitative Disclosures about Market Risk, (h) Income Taxes, (i) Concentration
of Credit Risk, (j) Price Risk Management Activities, and (k) Commitments and
Contingencies, among others, contain forward-looking statements. Where the
Company expresses an expectation or belief to future results or events, such
expression is made in good faith and believed to have a reasonable basis in
fact. However, there can be no assurance that such expectation or belief will
actually result or be achieved.
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.
Continued financial instability and national security threats exist.
The terrorist attacks of September 11, 2001, and the ongoing conflict
in Iraq has caused instability in the global financial markets and may generate
global economic instability. The continued threat of terrorism and the impact of
military or other action have led to, and may lead to additional,
I-8
volatility in prices for oil and gas and could affect the markets for our
operations. Further, the United States government has issued public warnings
that indicate that energy assets might be specific targets of terrorist
organizations. These developments have subjected operations to increased risk
and have prompted the Company to adopt additional security measures that could
result in increased costs. Depending on the ultimate magnitude of any financial
volatility, terrorist attack, military action or security threat, there could be
a material adverse affect on the Company's business.
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
I-9
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 counterparties' 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
I-10
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.
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 costs of investigation,
litigation and possibly settlement or 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.
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 represent only estimates. 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
I-11
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.
I-12
Item 3. LEGAL PROCEEDINGS
On August 30, 2000, CJC Leasing, Inc. ("CJC"), a wholly owned
subsidiary of the Company previously involved in the coal mining business,
received a "Notice of Taxes Due" from the State of Kentucky regarding the
results of a coal severance tax audit covering the years 1989 through 1993. The
audit initially proposed a tax assessment of $8.3 million plus penalties and
interest. CJC protested the assessment and set forth a number of defenses
including that CJC was not a taxpayer engaged in severing and/or mining coal at
anytime during the assessment period. Further, it is CJC's informed belief that
such taxes were properly paid by the third parties that had in fact mined the
coal. In October 2003, CJC resolved this matter by payment of $40,000 to the
State in full settlement of all issues included therein. Such settlement payment
was expensed in fourth quarter 2003 results.
On July 31, 2002, pursuant to a workmen's compensation claim filed by
the family of a deceased employee, the plaintiffs in the workmen's compensation
case also filed a complaint with the Occupational Safety and Health
Administration ("OSHA"). The OSHA complaint alleging that the Company's wholly
owned subsidiary, Service Transport Company, failed to produce employee exposure
and other records including air sampling data and medical monitoring records
from years 1989 through 1997. The Company responded to the alleged violations
denying that it failed to produce such data. To date, the Company has not
received a response from OSHA and no further action from OSHA is expected.
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. Management believes the claims made
for the arbitration are not consistent with the terms of the joint venture
agreement. Further, management does not believe a re-audit or arbitration of
this matter will have a significant 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.
I-13
Item 4. SUBMISSION OF MATTER TO A VOTE OF SECURITY HOLDERS.
None.
EXECUTIVE OFFICERS OF THE REGISTRANT
The persons who are currently serving as executive officers of the
Company or its subsidiaries, their ages and the positions they hold with the
Company are as follows:
Name Age Positions with the Company
---- --- --------------------------
K. S. Adams, Jr. 81 Chairman, President and Chief Executive Officer
Vincent H. Buckley 81 Executive Vice President and General Counsel
Claude H. Lewis 60 Vice President-Land Transportation
Richard B. Abshire 51 Vice President-Finance
Juanita G. Simmons 49 Vice President-Gulfmark Energy, Inc.
John M. Fetzer 50 President-Gulfmark Energy, Inc.
James Brock Moore 63 President-Adams Resources Exploration Corp.
Lee A. Beauchamp 51 President-Ada Resources, Inc.
David B. Hurst 51 Secretary
Each officer has served in his present position for at least five years
except Mr. Buckley and Mr. Fetzer. For the five years prior to joining the
Company, Mr. Buckley was Of Counsel to the law firm of Locke Liddell & Sapp LLP,
and Mr. Fetzer was Executive Vice President of Genesis Energy, LP. No family
relationship exists between any of the officers. Mr. Hurst 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 lease 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.
I-14
PART II
Item 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDER
MATTERS
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, 2002.
American Stock Exchange
-----------------------
Year High Low
---- ---- ---
2002
First Quarter.............................................. $ 10.55 $ 7.35
Second Quarter............................................. 8.85 6.00
Third Quarter.............................................. 6.43 3.80
Fourth Quarter............................................. 5.40 3.96
2003
First Quarter.............................................. $ 6.50 $ 5.35
Second Quarter............................................. 10.45 5.57
Third Quarter.............................................. 10.82 8.65
Fourth Quarter............................................. 13.96 10.06
At March 10, 2004 there were 358 holders of record of the Company's
common stock and the closing stock price was $13.55 per share. The Company has
no securities authorized for issuance under equity compensation plans.
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 and December 17, 2001 the Company paid an annual cash dividend
of $.13 per common share to common stock holders of record on December 2, 2002
and December 3, 2001, respectively. Such dividends totaled $970,047 for 2003 and
$548,000 for each of 2002 and 2001.
The terms of the Company's bank loan agreement require the Company to
maintain consolidated net worth in excess of $33,634,000. 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.
II-1
Item 6. SELECTED FINANCIAL DATA
FIVE YEAR REVIEW OF SELECTED FINANCIAL DATA
Years Ended December 31,
-----------------------------------------------------------------------------
2003 2002 2001 2000 1999
----------- ----------- ----------- ----------- -----------
(In thousands, except per share data)
Revenues:
Marketing ........................ $ 1,677,728 $ 1,726,194 $ 3,444,050 $ 5,743,500 $ 3,761,730
Transportation ................... 35,806 36,406 33,149 35,824 35,559
Oil and gas ...................... 8,395 4,750 6,111 6,059 3,441
----------- ----------- ----------- ----------- -----------
$ 1,721,929 $ 1,767,350 $ 3,483,310 $ 5,785,383 $ 3,800,730
=========== =========== =========== =========== ===========
Operating earnings:
Marketing ........................ $ 12,244 $ 10,872 $ (8,846)(2) $ 16,362 $ 10,424
Transportation ................... 973 2,142 1,053 2,311 3,495
Oil and gas ...................... 2,310 (633)(1) 693 1,624 (520)
General and administrative ....... (6,299) (7,259) (7,165) (6,221) (4,819)
----------- ----------- ----------- ----------- -----------
9,228 5,122 (14,265) 14,076 8,580
Other income (expense):
Interest income .................. 362 115 456 1,233 565
Interest expense ................. (108) (117) (128) (172) (75)
----------- ----------- ----------- ----------- -----------
Earnings (loss) from continuing
operations before income taxes
and cumulative effect of
accounting change ................ 9,482 5,120 (13,937) 15,137 9,070
Income tax provision (benefit) ....... 3,056 1,751 (4,776) 5,495 2,683
----------- ----------- ----------- ----------- -----------
Earnings (loss) from continuing
operations ....................... 6,426 3,369 (9,161) 9,642 6,387
Earnings (loss) from discontinued
operations, net of taxes ......... (3,232) (1,917) 4,537 (802) -
----------- ----------- ----------- ----------- -----------
Earnings (loss) before cumulative
effect of accounting change ...... 3,194 1,452 (4,624) 8,840 6,387
Cumulative effect of accounting
change, net of taxes ............. (92) - 55 - -
----------- ----------- ----------- ----------- -----------
Net earnings (loss) .................. $ 3,102 $ 1,452 $ (4,569) $ 8,840 $ 6,387
=========== =========== =========== =========== ===========
EARNINGS (LOSS) PER SHARE:
From continuing operations ....... $ 1.53 $ .79 $ (2.17) $ 2.29 $ 1.51
From discontinued operations ..... (.77) (.45) 1.08 (.19) -
Cumulative effect of
accounting change ............. (.02) - .01 - -
----------- ----------- ----------- ----------- -----------
Basic earnings (loss) per share ...... $ .74 $ .34 $ (1.08) $ 2.10 $ 1.51
=========== =========== =========== =========== ===========
Dividends per common share ........... $ .23 $ .13 $ .13 $ .13 $ .10
=========== =========== =========== =========== ===========
FINANCIAL POSITION
Working capital ...................... $ 32,986 $ 31,292 $ 30,334 $ 32,656 $ 19,438
Total assets ......................... 210,261 202,120 227,027 448,044 293,048
Long-term debt, net of
current maturities ............... 11,475 11,475 12,475 11,900 9,900
Shareholders' equity ................. 42,232 40,100 39,196 44,313 36,021
Dividends on common shares ........... 970 548 548 548 422
- ----------------------
(1) The 2002 oil and gas loss includes $1.7 million in dry hole costs and
property valuation write-downs.
(2) The 2001 marketing 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.
II-2
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):
2003 2002 2001
------------ ----------- -----------
Revenues.................................... $ 1,677,728 $ 1,726,194 $ 3,444,050
Operating Earnings (Loss)................... $ 12,244 $ 10,872 $ (8,846)
Depreciation................................ $ 1,397 $ 1,611 $ 2,600
Marketing segment operating statistics were as follows:
2003 2002 2001
-------------- --------------- --------------
Wellhead Purchases per day (1)
- Crude Oil................................... 85,000 bbls 101,000 bbls 130,000 bbls
- Natural Gas................................. 317,000 mmbtu 482,000 mmbtu 796,000 mmbtu
Average Price
- Crude Oil................................... $ 29.80/bbl $ 24.18/bbl $ 24.59/bbl
- Natural Gas................................. $ 5.28/mmbtu $ 3.10/mmbtu $ 4.07/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.
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. In contrast, gross revenues for the marketing
division decreased by $1.7 billion or 50 percent for 2002 relative to 2001
revenues. This trend resulted because during 2000 and 2001, management was
reducing its scope of operations including the October 2001 sale of the
Company's onshore Texas crude oil pipeline and related withdrawal from a six
county area. The strategy to reduce the size of operations was originally
implemented because management believed its capital structure was not sufficient
to safely support the expanded level of business existing at the time. With
Enron Corp. filing for bankruptcy in December
II-3
2001, credit support for the crude oil and natural gas industries became of
paramount importance. Numerous industry participants either withdrew or
significantly curtailed their activities within the crude oil and natural gas
marketplace. Spurred by the fallout from Enron, the contraction in volumes and
revenues continued during 2002. In response, the Company concentrated its crude
oil operation in its areas of strength including Central and South Texas, the
onshore Louisiana Gulf Coast and the State of Michigan. For natural gas, the
Company continues to focus on offshore Gulf of Mexico supply and those pipeline
pooling points with multiple delivery connections in order to increase
flexibility and end-market options. Management believes the contraction of
volumes has stabilized at present levels. While volume growth is not anticipated
for 2004, management believes that profitability can be maintained within the
present, more manageable level of activity.
The $1.4 million or 13 percent operating earnings increase for 2003
resulted from improved per unit margins for both crude oil and natural gas. Most
notably in the first half of the year, 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, resulting from the final true-up of the
accounting for such items.
Comparing 2002 marketing earnings relative to 2001, the market
conditions for crude oil purchase and sale margins were significantly improved
due to Iraqi war fears and production problems in Venezuela. These issues caused
a significant prompt or current month premium and led to increased margins. In
addition to margin improvement, domestic crude oil prices rose from the $19 per
barrel range at year-end 2001 to the $30 range by year-end 2002. As part of the
Company's strategy to reduce its exposure to price fluctuation, during 2002, the
Company chose to liquidate lower priced inventory into a relatively high value
market which increased operating margins by $1.1 million. In contrast with 2001,
prompt month prices became exceptionally weak and normal margins narrowed.
Further, due to declining crude oil prices that were accelerated by the events
of September 11, 2001, the Company recognized approximately $7.2 million in
charges related to crude oil inventory liquidations and valuation write-downs.
Operating earnings for 2001 were also adversely impacted by a $1.5 million bad
debt provision resulting from the Enron bankruptcy.
Of particular significant effect on 2002 operating earnings was the
earning of fee income totaling $2,433,000 during the first six months of 2002.
This fee originated pursuant to the terms of the agreement to dissolve the
Williams-Gulfmark joint venture. Effective with November 2001 business, the
Company began to earn 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. Unfortunately, effective 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 recorded no fee income during the remainder of
2002 and no such fee is anticipated in future periods. The Company and the
co-venture participant continue to cooperate in the final wind-down and
settlement of open trade account items. As of December 31, 2003 the venture's
remaining trade accounts due totaled approximately $3.1 million and trade
accounts payable totaled approximately $6.8 million. As the venture either
collects or funds cash proceeds in settlement of such accounts, the Company will
receive or pay its pro-rata 50 percent share of such cash proceeds or
requirements. See also Note (11) of the Notes to Consolidated Financial
Statements.
II-4
- Transportation
The transportation segment continued to face a generally stagnant
marketplace in both 2003 and 2002, as has been the situation since the second
quarter of 2000. Revenues and operating earnings were as follows (in thousands):
2003 2002 2001
------------------------ ------------------------ -------------------------
Amount Change(1) Amount Change(1) Amount Change(1)
---------- --------- ---------- --------- ---------- ---------
Revenues...................... $ 35,806 (2%) $ 36,406 10% $ 33,149 (7%)
Operating Earnings............ $ 973 (55%) $ 2,142 103% $ 1,053 (55%)
Depreciation.................. $ 2,093 14% $ 1,838 11% $ 1,660 13%
- --------------------
(1) Represents the percentage increase (decrease) from the prior year.
Results from the transportation segment 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. For most of 2003, a weak
U.S. economy and high natural gas feedstock costs served to suppress demand. The
reduced demand picture was aggravated by high maintenance costs of an aging
fleet, driver recruitment and retention issues, inflated insurance costs, fuel
cost increases, heightened security concerns and low competitive freight rates.
There was however, a spark in demand during portions of the fourth quarter of
2003 that has carried forward in 2004.
Due to the fixed cost component of the trucking operation, as revenues
are reduced, operating earnings decline at a faster rate. Operating earnings
were reduced in 2003 because of higher diesel fuel prices and insurance cost
increases. Fuel costs increased by $369,000 or 10 percent for 2003, consistent
with higher average crude oil prices. Insurance expense increased by $957,000 or
25 percent consistent with the general trend of escalating insurance costs.
Partially offsetting increased costs and reduced demand was a $351,000 gain
recorded upon the sale of 60 used truck tractors. These units were replaced with
60 new units obtained under an operating lease.
Based on its current infrastructures, the Company's transportation
segment is designed to maximize efficiency and earnings at a level of revenues
approaching $42 million per year. When profitable demand is short of designed
capacity, earnings are reduced and become a function of the current level of
demand and the Company's ability to control costs. 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. Management believes that if
escalating insurance and fuel costs subside, 2004 is potentially a turnaround
year for this operation. Further, since a number of weaker competitors have left
the industry, a demand surge should create positive upward pressure on freight
rates. All of this should enhance profitability in 2004.
II-5
- 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):
2003 2002 2001
-------- --------- ---------
Revenues.................................... $ 8,395 $ 4,750 $ 6,111
Operating Earnings (Loss)................... $ 2,310 $ (633) $ 693
Depreciation and Depletion.................. $ 2,175 $ 2,116 $ 2,456
Production volumes and price information is as follows:
2003 2002 2001
--------------- -------------- ---------------
Production Volumes
- Crude Oil................................... 61,900 bbls 55,000 bbls 64,000 bbls
- Natural Gas................................. 1,239,000 mcf 1,047,000 mcf 1,031,000 mcf
Average Price
- Crude Oil................................... $ 30.67/bbl $ 26.10 /bbl $ 27.08 /bbl
- Natural Gas................................. $ 5.23/mcf $ 3.17/mcf $ 4.23/mcf
As shown above, improved oil and gas division revenues and operating
earnings in 2003 resulted from increased crude oil and natural gas production
volumes as well as higher prices for both crude oil and natural gas. Recent
results from exploration efforts caused the production volume increases. During
2003, the Company participated in the drilling of thirty-six wells. Twenty-three
wells were successfully completed with twelve dry holes and one well in process
at year-end. In addition to the completions of wells spud in 2003, the Company
also successfully brought on production three wells that were drilling at
year-end 2002. The well in process at December 31, 2003 was subsequently brought
on production in the first quarter of 2004.
Oil and gas revenues and operating earnings for 2002 were reduced
relative to 2001 primarily because of declining natural gas prices from an
average of $4.23/mcf in 2001 to $3.17/mcf in 2002. An additional factor
contributing to reduced 2002 earnings were dry hole and other exploration
expenses totaling $1,177,000 in 2002 as compared to $821,000 for 2001 and
$1,638,000 for 2003.
The results of 2003 exploration efforts yielded estimated reserve
additions totaling 144,000 barrels of oil and 2,693,000 mcf of gas. With the
Company's production for 2003 being 61,900 barrels of oil and 1,239,000 mcf of
gas, the estimated reserve additions for 2003 represent more than a complete
replacement of current production. Estimated future net cash flow before income
taxes from oil and gas properties was increased from $31,385,000 at year-end
2002 to $46,186,000 at year-end 2003.
Justified by improved commodity prices, 2003 was the Company's most
active year of drilling since the early 1990's. During the year, in Fort Bend
County, Texas, the Company participated in the drilling of fifteen wells with
ten productive and five dry holes. The success in this area is the result of the
culmination of work done on two large 3-D seismic acquisitions made in 1999.
Together with its joint interest partners, the Company plans to expand
exploration in this area in 2004 by acquiring additional existing seismic data
and applying the same techniques that were successful in 2003.
II-6
In Calcasieu Parish, Louisiana, the Company drilled eight wells in 2003
with two dry holes. With its joint interest partners, the Company hopes to
continue this success by exploiting a large 3-D survey that was completed in
2003. The data obtained from this survey was processed and is yielding multiple
prospects to drill in 2004. The first of these is scheduled to spud in April
2004. For the Austin Chalk field of central Texas, drilling continued in 2003
with four wells being successfully completed and two wells scheduled for 2004.
In Alabama, fieldwork on a large 3-D seismic survey began in October 2003.
Recording of data began in 2004 and is expected to conclude by mid-year. The
Alabama 3-D survey should confirm several prospect leads and the first well
could spud as early as the upcoming fourth quarter. The Company is also
participating in the drilling of a rank wildcat well in Edwards County, Texas.
Although high in risk with a low chance of success, if this well is successful,
the Company will be participating with a three percent working interest in the
exploitation of approximately 40,000 acres.
The Company has obtained a 25 percent equity interest in an offshore
block in the central sector of the UK North Sea. The block, 21-1b, was awarded
in August 2003 as a new promote license being offered by the Department of Trade
and Industry in the recently completed 21st round. As a participant in this
block together with its joint interest partners, the Company has two years to
acquire existing 3-D seismic and reprocess it in order to develop a drillable
prospect. The terms of the license do not include a well commitment. This
project has large upside potential with minimal up front cost. Work on
reprocessing the seismic began in January 2004 with results anticipated by the
end of the second quarter. If a prospect is confirmed, the Company and its joint
interest partners will seek an additional participant to drill the well on a
promoted basis in order to provide limited capital exposure on the initial
exploratory well.
- General and administrative
General and administrative expenses decreased $960,000, or 13 percent,
for 2003 relative to 2002. This savings resulted in part because $536,000 was
incurred in 2002 for a due diligence review of the Company's operations
following the collapse of Enron Corp., a trading counterparty of the Company.
While the review produced no adverse findings, continuous improvement in
practices and procedures remains an important goal of the Company. In 2002, the
Company also incurred $338,000 of audit expense in connection with a review of
the activities of the Company's former marketing joint venture. See also Note
(11) of Notes to Consolidated Financial Statements.
- Discontinued operations
During 2003, the Company's management decided to withdraw from its New
England region retail natural gas marketing business, which was included in the
marketing segment. This business unit caused after tax losses totaling
$3,232,000 during 2003 with $2,053,000 occurring in the first quarter. Such
losses resulted from certain "full requirements" contracts with weather
sensitive end-use customers. Under these contracts, the Company bears the risk
associated with any differences between expected volumes and actual usage.
January through March 2003 was abnormally cold and, due to strong demand
conditions, natural gas prices were elevated. As a result, during that period,
this category of customer caused the Company to purchase supplemental quantities
of natural gas at prices greater than the contracted sales realization. Because
of the losses sustained and the desire to reduce working capital requirements,
management decided to exit this region and type of account.
II-7
Presently, the Company has ceased entering into New England region
contracts. Existing contract requirements are being met in accordance with their
original terms. Expiring contracts were not renewed and substantially all
contracts expired prior to December 31, 2003. Additionally, effective November
1, 2003, the Company entered into an agreement with a third party to hire the
Company's personnel and assume associated office operating lease obligations.
Management believes that no significant severance or shutdown costs will be
incurred as a result of discontinuance of this operation. Activity in 2004
consists of collecting accounts receivable and honoring the remaining less than
5 percent of contracts that extended into the new year. With the reduction in
volume requirements for 2004, the Company does not anticipate further
significant losses from this operation. See Note (3) of Notes to Consolidated
Financial Statements.
- Outlook
With the issue of the New England operation resolved, 2004 looks to be
a promising year. A current problem is the ever-increasing cost of all forms of
insurance, including general liability, automobile, workers compensation and
employee medical insurance. In 2003, the Company's insurance cost totaled $9.9
million, a 98 percent increase in just two years. The absorption of insurance
increases has suppressed earnings with no tangible solution presently in sight.
The Company is hopeful, however, that the insurance marketplace has at least
stabilized as the Company strives to find the means to factor the new cost
structure into its business planning.
Looking ahead for the marketing operation, management believes the
exceptionally strong margin conditions that existed during 2003 are not likely
to remain. However, sound profitable operation should continue. For
transportation, the Company presently has excess facilities capacity and
management is hopeful of continued strengthened demand. In the case of oil and
gas exploration, there exists a strong price environment and the Company has a
number of very exciting opportunities.
The Company has the following major objectives for 2004:
- Maintain marketing operating earnings at the $9
million level.
- Restore transportation operating earnings to the $2
million level.
- Maintain oil and gas operating earnings at $2.3
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 activity with available cash generated
from operations. During 2003, the Company's cash flow from operations totaled
$9,093,000 and such funds were utilized to make $7,771,000 in capital
expenditures and pay $970,000 in common stock dividends. Over time, cash
utilized for property and equipment additions, tends to track with the non-cash
provision for depreciation, depletion and amortization. A summary of this
relationship follows (in thousands):
II-8
Years Ended December 31,
--------------------------------------------
2003 2002 2001 Total
-------- -------- -------- --------
Depreciation, depletion
and amortization ......... $ 5,665 $ 5,565 $ 6,726 $ 17,956
Property and equipment
additions ................ (7,771) (4,622) (3,591) (15,984)
-------- -------- -------- --------
Other (sources) uses of cash $ (2,106) $ 943 $ 3,135 $ 1,972
======== ======== ======== ========
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 1 percent. The working capital loan provides for borrowings up to
$7,500,000 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, 2003 was established at $7,500,000. 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
$5,000,000 as of December 31, 2003. The line of credit loans are scheduled to
expire on October 31, 2005, with the then present balance outstanding converting
to a term loan payable in 8 equal quarterly installments. As of December 31,
2003, 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 $33,634,000.
The Company's Gulfmark Energy, Inc. subsidiary maintains a separate
banking relationship with BNP Paribas in order to support its crude oil
purchasing activities. In addition to providing up to $40 million in letters of
credit, the facility also finances up to $6 million of crude oil inventory and
certain accounts receivable associated with crude oil sales. Such financing is
provided on a demand note basis with interest at the bank's prime rate plus 1
percent. As of December 31, 2003, the Company had $2.1 million of eligible
borrowing capacity under this facility. No working capital advances were
outstanding as of December 31, 2003. Letters of credit outstanding under this
facility totaled approximately $21 million as of December 31, 2003. 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 on a demand note basis. Such financing is provided on a demand note basis
with interest at the bank's prime rate plus 1 per cent. No working capital
advances were outstanding under this facility as of December 31, 2003. Letters
of credit outstanding under this facility totaled approximately $9.2 million as
of December 31, 2003. 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.
II-9
Management maintains that the greatest uncertainty facing a marketing
company is the banking community's continued willingness to support commodity
credit facilities. The events leading to Enron's bankruptcy support this belief.
The Company remains positioned to operate the commodity portions of its business
without bank support should such a need develop.
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, 2003, 2002, and 2001 was $5,831,000, $5,944,000 and $7,035,000,
respectively. At December 31, 2003, commitments under long-term noncancelable
operating leases for the next five years and thereafter are payable as follows:
2004 - $4,609,000; 2005 - $3,135,000; 2006 - $2,373,000; 2007 - $2,064,000; 2008
and thereafter - $2,678,000.
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. A summary of contractual debt
and lease obligations is as follows (in thousands):
Payment Period
-----------------------------------------------------------------------------
2004 2005 2006 2007 2008 Thereafter Total
----------- --------- -------- --------- -------- ------------ ------------
Long-term debt........ $ - $ 1,434 $ 5,738 $ 4,303 $ - $ - $ 11,475
Operating leases...... 4,609 3,135 2,373 2,064 1,864 814 14,859
----------- --------- -------- --------- -------- ------------ ------------
Total $ 4,609 $ 4,569 $ 8,111 $ 6,367 $ 1,864 $ 814 $ 26,334
=========== ========= ======== ========= ======== ============ ============
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, 2003 are as follows: (In thousands)
January Remaining
2004 2004 2005 2006 Thereafter Total
------------ ----------- --------- --------- ---------- -----
Crude Oil.................. $ 130,373 $ 14,643 $ - $ - $ - $ 145,016
Natural Gas................ 43,077 2,131 - - - 45,208
Refined Products........... 287 - - - - 287
------------ ----------- --------- --------- ----------- -----------
$ 173,737 $ 16,774 $ - $ - $ - $ 190,511
============ =========== ========= ========= =========== ===========
II-10
Investment Activities
During 2003, the Company invested approximately $4,586,000 in oil and
gas projects, $1,387,000 for replacement equipment for its petrochemical
trucking fleet and $1,798,000 in equipment for the Company's marketing
operations. Oil and gas exploration and development efforts continue, and the
Company plans to invest approximately $5 million toward such projects in 2004
including $750,000 of seismic costs to be expensed during the year. An
additional approximate $1.2 million is projected in 2004 for the purchase of
transportation equipment as present lease financing arrangements mature.
Certain items of Cash Flow
Interest paid totaled $96,000, $121,000 and $128,000 during the years
ended December 31, 2003, 2002 and 2001, respectively. Interest expense was
reduced in 2003 as a result of a reduced prime bank rate and reduced average
loan amount outstanding. Income taxes paid during these same periods totaled
$1,659,000, $465,000 and $322,000, respectively. Federal tax refunds received
during 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.
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 expense totaled
$9.9 million, a 27 percent increase over 2002. Based on insurance renewals in
2003, the Company is anticipating further insurance increases for 2004. The
Company has no effective way to pass on such cost increases and any increase
will thus 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
II-11
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 single
most significant assets and liabilities of the Company. Particularly within the
Company's energy marketing and oil and gas exploration and production
operations, there is a high degree of interdependence with and reliance upon
third parties, (including transaction counterparties) to provide adequate
information for the proper recording of amounts receivable or payable.
Substantially all such third parties are larger firms providing the Company with
the source documents for recording trade activity. It is commonplace for these
entities to retroactively adjust or correct such documents. This typically
requires the Company to either absorb, benefit from, or pass along such
corrections to another third party.
Due to (a) the volume of transactions, (b) the complexity of
transactions and (c) the high degree of interdependence with third parties, this
is a difficult area to control and manage. The Company manages this process by
participating in a monthly settlement process with each of its counterparties.
Ongoing account balances are monitored monthly and the Company attempts to gain
the cooperation of such counterparties to reconcile outstanding balances. The
Company also places great emphasis on
II-12
collecting cash balance 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.
II-13
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.
New Accounting Pronouncements
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 completed its assessment of
SFAS No. 143 and, as of January 1, 2003, the Company estimated the present value
of its future Asset Retirement Obligations is approximately $672,000. 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.
On April 30, 2003, the FASB issued SFAS No. 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities". This statement
amends and clarifies accounting for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities
under SFAS No. 133. This statement is effective for contracts entered into or
modified after June 30, 2003, for hedging relationships designated after June
30, 2003, and to certain preexisting contracts. The Company adopted SFAS No. 149
on July 1, 2003.
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity". SFAS
No. 150 establishes standards for how an issuer classifies and measures certain
freestanding instruments with characteristics of both liabilities and equity.
SFAS No. 150 requires that an issuer classify a financial instrument that is
within its scope as a liability (or asset in some circumstances). The Company
adopted SFAS No. 150 effective July 1, 2003. The adoption of this statement did
not have a material effect on the Company's financial position, results of
operations or cash flows.
In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable
Interest Entities- An Interpretation of Accounting Research Bulletin 51". FIN 46
addresses consolidation by business enterprises of variable interest entities
("VIEs") and the primary objective is to provide guidance on the identification
of, and financial reporting for, entities over which control is achieved through
means other than voting rights; such entities are known as VIEs. FIN 46 requires
an entity to consolidate a VIE if the entity has a variable interest (or
combination of variable interests) that will absorb a majority of the entity's
expected losses if they occur, receive a majority of the entity's expected
residual returns if they occur or both. The guidance applies immediately to VIEs
created after January 31, 2003, and to VIEs in which an enterprise obtains an
interest after that date. Consolidation of previously existing VIEs is required
in the Company's December 31, 2003 financial statements. The Company has no VIEs
to consolidate as of December 31, 2003.
In June 2001, the FASB issued SFAS No. 141, "Business Combinations",
requiring the purchase method of accounting for business combinations initiated
after June 30, 2001, which eliminates the pooling-of-interests method. In July
2001, the FASB also issued SFAS No. 142, "Goodwill and Other
II-14
Intangible Assets", which discontinues the practice of amortizing goodwill and
indefinite lived intangible assets and initiates an annual review for
impairment. Intangible assets with a determinable useful life will continue to
be amortized over that period. The amortization provisions apply to goodwill and
intangible assets acquired after June 30, 2001. SFAS No. 141 and 142 clarify
that more assets should be distinguished and classified between tangible and
intangible. The Company did not change or reclassify contractual mineral rights
included in oil and gas properties on the balance sheet upon adoption of SFAS
No. 142. The Company believes the treatment of such mineral rights as tangible
assets under the successful efforts method of accounting for crude oil and
natural gas properties is appropriate. An issue has arisen regarding whether
contractual mineral rights should be classified as intangible rather than
tangible assets. If it is determined that reclassification is necessary, the
Company's net property, plant and equipment would be reduced by approximately
$9.9 million and $8 million and intangible assets would have increased by a like
amount at December 31, 2003 and 2002, respectively, representing unamortized
cost incurred since inception. The provisions of SFAS No. 141 and 142 impact
only the balance sheet and associated footnote disclosure, and reclassifications
necessary would not impact the Company's cash flows or results of operations.
II-15
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, 2003 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, 2003. 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, 2003.
Commodity Price Risk
The Company's major market risk exposure is in the pricing applicable
to its marketing and production of crude oil and natural gas. Realized pricing
is primarily driven by the prevailing spot prices applicable to oil and gas.
Commodity price risk in the Company's marketing operations represents the
potential loss that may result from a change in the market value of an asset or
a commitment. From time to time, the Company enters into forward contracts to
minimize or hedge the impact of market fluctuations on its purchases of crude
oil and natural gas. The Company may also enter into price support contracts
with certain customers to secure a floor price on the purchase of certain
supply. In each instance, the Company locks in a separate matching price support
contract with a third party in order to minimize the risk of these financial
instruments. Substantially all forward contracts fall within a 6-month to 1-year
term with no contracts extending longer than two years in duration. The Company
monitors all commitments and positions and endeavors to maintain a balanced
portfolio.
Certain forward contracts are recorded at fair value, depending on
management's assessments of numerous accounting standards and positions that
comply with generally accepted accounting principles. The 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, 2003 and 2002 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
$692,000 all to be received in 2004. The estimated future cash inflow
approximates the net fair value recorded in the Company's risk management assets
and liabilities.
II-16
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, 2003 (in thousands):
2003
-----------
Net fair value on January 1, ......................................... $ (70)
Activity during 2003
- Cash received from settled contracts ............................ 21
- Net realized (loss) from prior years' contracts ................. (32)
- Net unrealized gain from prior years' contracts ................. 340
- Net unrealized gain from current year contracts.................. 433
-----------
Net fair value on December 31, ...................................... $ 692
===========
Historically, prices received for oil and gas production have been
volatile and unpredictable. Price volatility is expected to continue. From
January 1, 2002 through December 31, 2003 natural gas price realizations ranged
from a monthly low of $2.12 mmbtu to a monthly high of $7.18 per mmbtu. Oil
prices ranged from a low of $19.30 per barrel to a high of $36.77 per barrel
during the same period. A hypothetical 10 percent adverse change in average
natural gas and crude oil prices, assuming no changes in volume levels, would
have reduced earnings by approximately $1,250,000 and $781,000, respectively,
for the comparative years ended December 31, 2003 and 2002.
II-17
ITEM 8. FINANCIAL STATEMENTS
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS
Page
----
INDEPENDENT AUDITORS' REPORT ........................................................................ II-19
FINANCIAL STATEMENTS:
Consolidated Balance Sheet as of
December 31, 2003 and 2002 ............................................................... II-20
Consolidated Statement of Operations for
the Years Ended December 31, 2003
2002 and 2001............................................................................. II-21
Consolidated Statement of Shareholders'
Equity for the Years Ended
December 31, 2003, 2002 and 2001.......................................................... II-22
Consolidated Statement of Cash Flows
for the Years Ended December 31,
2003, 2002 and 2001....................................................................... II-23
Notes to Consolidated Financial Statements ................................................. II-24
II-18
INDEPENDENT AUDITORS' REPORT
To the Shareholders of Adams Resources & Energy, Inc.:
We have audited the accompanying consolidated balance sheet of Adams
Resources and Energy, Inc. and subsidiaries (the "Company") as of December 31,
2003 and 2002 and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 2003. 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 auditing standards
generally accepted in the United States of America. Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidences supporting the amounts and disclosures in
the financial statements. An audit also includes 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,
2003 and 2002 and the results of its operations and its cash flows for the each
of the three years in the period ended December 31, 2003 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 and natural gas marketing revenues.
DELOITTE & TOUCHE LLP
Houston, Texas
March 16, 2004
II-19
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(IN THOUSANDS)
December 31,
-----------------------
2003 2002
---------- ----------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ......................... $ 28,342 $ 27,262
Accounts receivable, net of allowance for doubtful
accounts of $1,935 and $1,723, respectively .... 135,306 120,036
Inventories ....................................... 6,874 5,645
Risk management receivables ....................... 3,809 1,934
Income tax receivable ............................. 1,310 382
Prepayments ....................................... 4,870 3,147
Current assets of discontinued operation .......... 5,140 20,994
---------- ----------
Total current assets ......................... 185,651 179,400
---------- ----------
PROPERTY AND EQUIPMENT:
Marketing ......................................... 20,771 19,042
Transportation .................................... 18,213 18,799
Oil and gas (successful efforts method) ........... 41,666 37,479
Other ............................................. 99 99
---------- ----------
80,749 75,419
Less -Accumulated depreciation, depletion
and amortization ........................... (56,342) (53,115)
---------- ----------
24,407 22,304
---------- ----------
OTHER ASSETS:
Other assets ...................................... 203 416
---------- ----------
$ 210,261 $ 202,120
========== ==========
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable .................................. $ 145,047 $ 137,100
Risk management payables .......................... 3,117 2,004
Accrued and other liabilities ..................... 3,364 3,950
Current liabilities of discontinued operation ..... 1,137 5,030
---------- ----------
Total current liabilities .................. 152,665 148,084
LONG-TERM DEBT ....................................... 11,475 11,475
OTHER LIABILITIES:
Asset retirement obligations ...................... 706 -
Deferred taxes and other .......................... 3,183 2,461
---------- ----------
168,029 162,020
---------- ----------
COMMITMENTS 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 .... 422 422
Contributed capital ............................... 11,693 11,693
Retained earnings ................................. 30,117 27,985
---------- ----------
Total shareholders' equity ................... 42,232 40,100
---------- ----------
$ 210,261 $ 202,120
========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
II-20
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Years Ended December 31,
------------------------------------------
2003 2002 2001
------------ ------------ ------------
REVENUES:
Marketing ......................................... $ 1,677,728 $ 1,726,194 $ 3,444,050
Transportation .................................... 35,806 36,406 33,149
Oil and gas ....................................... 8,395 4,750 6,111
------------ ------------ ------------
1,721,929 1,767,350 3,483,310
------------ ------------ ------------
COSTS AND EXPENSES:
Marketing ......................................... 1,664,087 1,713,711 3,450,296
Transportation .................................... 32,740 32,426 30,436
Oil and gas ....................................... 3,910 3,267 2,952
General and administrative ........................ 6,299 7,259 7,165
Depreciation, depletion and amortization .......... 5,665 5,565 6,726
------------ ------------ ------------
1,712,701 1,762,228 3,497,575
------------ ------------ ------------
Operating Earnings (Loss) ............................. 9,228 5,122 (14,265)
Other Income (Expense):
Interest income ................................... 362 115 456
Interest expense .................................. (108) (117) (128)
------------ ------------ ------------
Earnings (loss) from continuing operations
before income tax and cumulative effect
of accounting change .............................. 9,482 5,120 (13,937)
Income Tax Provision (Benefit):
Current ........................................... 2,346 4,084 (6,268)
Deferred .......................................... 710 (2,333) 1,492
------------ ------------ ------------
3,056 1,751 (4,776)
------------ ------------ ------------
Earnings (loss) from continuing operations ............ 6,426 3,369 (9,161)
Earnings (loss) from discontinued operations,
net of tax benefit (provision) of $1,664,
$987, and $(2,338), respectively .................. (3,232) (1,917) 4,537
------------ ------------ ------------
Earnings (loss) before cumulative effect of
accounting change ................................. 3,194 1,452 (4,624)
Cumulative effect of accounting change,
net of tax benefit (provision) of $57,
zero and $(29), respectively ...................... (92) - 55
------------ ------------ ------------
Net Earnings (Loss) ................................... $ 3,102 $ 1,452 $ (4,569)
============ ============ ============
EARNINGS (LOSS) PER SHARE:
From continuing operations ........................ $ 1.53 $ .79 $ (2.17)
From discontinued operations ...................... (.77) (.45) 1.08
Cumulative effect of accounting change ............ (.02) - .01
------------ ------------ ------------
Basic and diluted net earnings (loss) per share ....... $ .74 $ .34 $ (1.08)
============ ============ ============
Dividends Per Common Share ............................ $ .23 $ .13 $ .13
============ ============ ============
The accompanying notes are an integral part of these consolidated financial
statements.
II-21
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, 2001 .............................. $ 422 $ 11,693 $ 32,198 $ 44,313
Net (loss) ......................................... - - (4,569) (4,569)
Dividends paid on common stock ..................... - - (548) (548)
------------ ------------ ------------ ------------
BALANCE, December 31, 2001 ............................ 422 11,693 27,081 39,196
Net earnings ....................................... - - 1,452 1,452
Dividends paid on common stock ..................... - - (548) (548)
------------ ------------ ------------ ------------
BALANCE, December 31, 2002 ............................ 422 11,693 27,985 40,100
Net earnings ....................................... - - 3,102 3,102
Dividends paid on common stock ..................... - - (970) (970)
------------ ------------ ------------ ------------
BALANCE, December 31, 2003 ............................ $ 422 $ 11,693 $ 30,117 $ 42,232
============ ============ ============ ============
The accompanying notes are an integral part of these consolidated financial
statements.
II-22
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
(IN THOUSANDS)
Years Ended December 31,
------------------------------------
2003 2002 2001
---------- ---------- ----------
CASH PROVIDED BY OPERATIONS:
Earnings (loss) from continuing operations .................... $ 6,426 $ 3,369 $ (9,161)
Adjustments to reconcile net earnings to net cash
provided by (used in) operating activities-
Depreciation, depletion and amortization .................... 5,665 5,565 6,726
Gains on property sales ..................................... (448) (447) (5,132)
Impairment of non-producing oil and gas properties .......... 461 537 -
Cumulative effect of accounting change ...................... (149) - 84
Other, net .................................................. 250 (292) 441
Decrease (increase) in accounts receivable .................... (15,270) 2,255 170,517
Decrease (increase) in inventories ............................ (1,229) 3,534 25,763
Risk management activities .................................... (762) 2,687 (322)
Decrease (increase) in tax receivable ......................... (928) 3,548 (3,930)
Decrease (increase) in prepayments ............................ (1,723) 4,492 (5,035)
Increase (decrease) in accounts payable ....................... 7,947 (14,356) (193,875)
Increase (decrease) in accrued liabilities .................... (586) 294 (2,356)
Increase (decrease) in deferred taxes ......................... 710 (3,075) 1,492
---------- ---------- ----------
Net cash provided by (used in) continuing operations ........ 364 8,111 (14,788)
Net cash provided by (used in) discontinued operations ...... 8,729 11,533 (9,717)
---------- ---------- ----------
Net cash provided by (used in) operating activities ............. 9,093 19,644 (24,505)
---------- ---------- ----------
INVESTING ACTIVITIES:
Property and equipment additions .............................. (7,771) (4,622) (3,591)
Proceeds from property sales .................................. 728 561 5,156
---------- ---------- ----------
Net cash (used in) provided by investing activities .... (7,043) (4,061) 1,565
---------- ---------- ----------
FINANCING ACTIVITIES:
Net borrowings under credit agreements ........................ - (1,000) 575
Dividend payments ............................................. (970) (548) (548)
---------- ---------- ----------
Net cash (used in) provided by financing activities ....... (970) (1,548) 27
---------- ---------- ----------
Increase (decrease) in cash and cash equivalents ................ 1,080 14,035 (22,913)
Cash and cash equivalents at beginning of year .................. 27,262 13,227 36,140
---------- ---------- ----------
Cash and cash equivalents at end of year ........................ $ 28,342 $ 27,262 $ 13,227
========== ========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
II-23
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The accompanying consolidated financial statements include the accounts
of Adams Resources & Energy, Inc., a Delaware corporation, and its wholly owned
subsidiaries (the "Company") after elimination of all significant intercompany
accounts and transactions. In addition, these statements include the Company's
share of oil and gas joint interests using pro-rata consolidation and its
interest in a 50% owned crude oil marketing joint venture using the equity
method of accounting. See Note (11) of Notes to Consolidated Financial
Statements.
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, 2003 and 2002 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. Materials and supplies are included in inventory at specific
cost, with a valuation allowance provided if needed. As a result of declining
crude oil prices, during 2001 the Company recognized a combined $7.2 million in
changes from inventory liquidation and valuation write-downs. No such changes
were incurred in 2003 and 2002. Components of inventory are as follows (in
thousands):
December 31,
----------------------
2003 2002
---------- ----------
Crude oil................................................ $ 4,108 $ 3,062
Petroleum products....................................... 2,192 1,919
Materials and supplies................................... 574 664
---------- ----------
$ 6,874 $ 5,645
========== ==========
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.
II-24
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 $461,000 and a $537,000 impairment
provision on non-producing properties was recorded in 2003 and 2002,
respectively. Also for 2002, a $492,000 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. In 2001, declining oil and natural gas prices during the fourth
quarter resulted in a $1,062,000 asset impairment charge being recorded and
included in DD&A for the year.
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 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.
II-25
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Statement of Cash Flows
Interest paid totaled $96,000, $121,000 and $128,000 during the years
ended December 31, 2003, 2002 and 2001, respectively. Income taxes paid during
these same periods totaled $1,659,000, $465,000 and $322,000, respectively.
Federal tax refunds received during 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 2003, 2002 and 2001. There were no
potentially dilutive securities during 2003, 2002 and 2001.
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.
In October 2002, the Financial Accounting Standards Board's Emerging
Issues Task Force ("EITF") amended and rescinded certain prior consensus related
to the Accounting for Contracts Involved in Energy Trading and Risk Management
Activities and issued EITF 02-03. This new EITF consensus requires: (i) all
mark-to-market gains and losses on trading contracts be shown net in the income
statement whether or not settled physically and (ii) precludes mark-to-market
accounting for non-SFAS No. 133 derivatives. As required, the Company adopted
EITF 02-03 effective October 26, 2002 for any new contracts and effective
January 1, 2003 for any existing contracts. Upon adoption, the latest consensus
requires restatement to historical cost for any contracts that no longer qualify
for mark
II-26
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -to-market treatment. Such restatement, if necessary, is recorded as a
cumulative effect of an accounting change and comparative financial statements
for prior periods must be reclassified to conform to the new consensus. In the
Company's case, however, no contracts required restatement to historical cost.
Effective January 1, 2003, the Company's natural gas marketing
activities are presented and prior periods were retroactively restated to
reflect all physical activity associated with the trading of natural gas on a
net basis. This change in accounting did not impact net income; however
presenting natural gas marketing revenues net of associated costs significantly
reduced revenues reflected in the statement of operations. See Note (12) of
Notes to Consolidated Financial Statements for a table summarizing the effect on
the prior periods presented herein.
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, 2003 is
$692,000, all of which will be received in 2004. 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, 2003 and 2002 (in thousands):
2003 2002
----------- -----------
Net fair value on January 1, ..................................... $ (70) $ 2,617
Activity during 2003
- Cash received from settled contracts ......................... 21 -
- Cash paid on settled contracts................................ - (3,631)
- Net realized (loss) from prior years' contracts .............. (32) -
- Net realized gain from prior years' contracts................. - 389
- Net unrealized gain from prior year's contracts............... 340 6
- Net unrealized gain from current years' contracts............. 433 549
----------- -----------
Net fair value on December 31, ................................... $ 692 $ (70)
=========== ============
II-27
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
New Accounting Pronouncements
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 completed its assessment of
SFAS No. 143, and as of January 1, 2003, the Company estimated the present value
of its future Asset Retirement Obligations is approximately $672,000. 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.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities", which addresses accounting for
restructuring and similar costs. SFAS No. 146 supersedes previous accounting
guidance, principally EITF Issue No. 94-3. The Company has adopted the
provisions of SFAS No. 146 for restructuring activities initiated after December
31, 2002. SFAS No. 146 requires that the liability for costs associated with an
exit or disposal activity be recognized when the liability is incurred. Under
Issue No. 94-3, a liability for an exit cost was recognized at the date of
commitment to an exit plan. SFAS No. 146 also establishes that the liability
should initially be measured and recorded at fair value. Accordingly, SFAS No.
146 may affect the timing of recognizing future restructuring costs as well as
the amounts recognized. The impact that SFAS No. 146 will have on the
consolidated financial statements will depend on the circumstances of any
specific exit or disposal activity. See Note (3) of Notes to Consolidated
Financial Statements.
In December 2002, the FASB issued SFAS No. 148, "Accounting for
Stock-Based Compensation-Transition and Disclosure", which provides alternative
methods of transition for a voluntary change to the fair value based method of
accounting for stock-based employee compensation. In addition, SFAS No. 148
amends the disclosure requirements of SFAS No. 123 in both annual and interim
financial statements. SFAS No. 148 is effective for financial statements for
fiscal years ending after December 15, 2002, and financial reports containing
condensed financial statements for interim periods beginning after December 15,
2002. At this time, there is no outstanding stock-based employee compensation.
Therefore, the adoption of this statement had no effect on either the financial
position, results of operations, cash flows or disclosure requirements of the
Company.
On April 30, 2003, the FASB issued SFAS No. 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities". This statement
amends and clarifies accounting for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities
under SFAS No. 133. This statement is effective for contracts entered into or
modified after June 30, 2003, for hedging relationships designated after June
30, 2003, and to certain preexisting contracts. The Company adopted SFAS No. 149
on July 1, 2003.
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity". SFAS
No. 150 establishes standards for how an issuer classifies and measures certain
freestanding instruments with characteristics of both liabilities and equity.
SFAS No. 150 requires that an issuer classify a financial instrument that is
within its scope as a
II-28
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
liability (or asset in some circumstances). The Company adopted SFAS No. 150
effective July 1, 2003. The adoption of this statement did not have a material
effect on the Company's financial position, results of operations or cash flows.
In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable
Interest Entities- An Interpretation of Accounting Research Bulletin 51". FIN 46
addresses consolidation by business enterprises of variable interest entities
("VIEs") and the primary objective is to provide guidance on the identification
of, and financial reporting for, entities over which control is achieved through
means other than voting rights; such entities are known as VIEs. FIN 46 requires
an entity to consolidate a VIE if the entity has a variable interest (or
combination of variable interests) that will absorb a majority of the entity's
expected losses if they occur, receive a majority of the entity's expected
residual returns if they occur or both. The guidance applies immediately to VIEs
created after January 31, 2003, and to VIEs in which an enterprise obtains an
interest after that date. Consolidation of previously existing VIEs is required
in the Company's December 31, 2003 financial statements. The Company has no VIEs
to consolidate as of December 31, 2003.
In June 2001, the FASB issued SFAS No. 141, "Business Combinations",
which requires the purchase method of accounting for business combinations
initiated after June 30, 2001 and eliminates the pooling-of-interests method. In
July 2001, the FASB also issued SFAS No. 142, "Goodwill and Other Intangible
Assets", which discontinues the practice of amortizing goodwill and indefinite
lived intangible assets and initiates an annual review for impairment.
Intangible assets with a determinable useful life will continue to be amortized
over that period. The amortization provisions apply to goodwill and intangible
assets acquired after June 30, 2001. SFAS No. 141 and 142 clarify that more
assets should be distinguished and classified between tangible and intangible.
The Company did not change or reclassify contractual mineral rights included in
oil and gas properties on the balance sheet upon adoption of SFAS No. 142. The
Company believes the treatment of such mineral rights as tangible assets under
the successful efforts method of accounting for crude oil and natural gas
properties is appropriate. An issue has arisen regarding whether contractual
mineral rights should be classified as intangible rather than tangible assets.
If it is determined that reclassification is necessary, the Company's net
property, plant and equipment would be reduced by approximately $9.9 million and
$8 million and intangible assets would be increased by a like amount at December
31, 2003 and December 31, 2002, respectively, representing unamortized cost
incurred since inception. The provisions of SFAS No. 141 and 142 impact only the
balance sheet and associated footnote disclosure, and any necessary
reclassifications would not impact the Company's cash flows or results of
operations.
(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 $7,500,000 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, 2003 was established at $7,500,000 with the full amount
outstanding at December 31, 2003. 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
$5,000,000 as of December 31, 2003 with the next scheduled borrowing base
re-determination date of September 1, 2004. As of December 31, 2003, $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, 2003, letters of credit under this facility
II-29
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
totaled $25,000. The revolving line of credit loans are scheduled to expire on
October 31, 2005, with the then present balance outstanding converting to a term
loan payable in 8 equal quarterly installments
Long-term debt is summarized as follows (in thousands):
December 31,
--------------------------
2003 2002
----------- ----------
Bank lines of credit, secured by substantially all of
the Company's assets (excluding Gulfmark and
ARM), due in eight quarterly installments
commencing on October 31, 2005....................................... $ 11,475 $ 11,475
Less - 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 $33,634,000.
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 2003 and 2002, Gulfmark had no amounts outstanding under the
inventory-based line of credit. Gulfmark had approximately $21 million and $13.7
million in letters of credit outstanding as of December 31, 2003 and 2002,
respectively, in support of its crude oil purchasing activities. As of December
31, 2003, the Company had $2.1 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 2003 and 2002, ARM had no working capital advances outstanding. ARM had
approximately $9.2 million and $4.3 million in letters of credit outstanding at
December 31, 2003 and 2002, 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 2003, 2002
and 2001 was 3.1%, 3.7%, and 5.7%, respectively. No interest was capitalized
during 2003, 2002 or 2001. At December 31, 2003, the scheduled aggregate
principal maturities of the Company's long-term debt are: 2005 - $1,434,375;
2006 - $5,737,500; and 2007 - $4,303,125.
II-30
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(3) DISCONTINUED OPERATIONS
Effective January 1, 2002, the Company adopted SFAS No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets", that addresses
the financial accounting and reporting for the impairment or disposal of
long-lived assets. SFAS No. 144 requires that one accounting model be used for
long-lived assets to be disposed of by sale and broadens the presentation of
discontinued operations to include more disposal transactions.
During 2003, Company management decided to withdraw from its New
England region retail natural gas marketing business, which is included in the
marketing segment. This business unit had negative operating margins of
$4,896,000 and $2,904,000 and after tax losses totaling $3,232,000 and
$1,917,000 during 2003 and 2002, respectively. Previously in 2001, this business
unit had positive operating margins of $6,875,000 or $4,537,000 net of tax. The
losses sustained in 2002 and 2003 resulted primarily from certain "full
requirements" contracts with weather sensitive end-use customers. Under these
contracts, the Company bears the risk associated with any differences between
expected volumes and actual usage. January through March 2003 was abnormally
cold and due to strong demand conditions, natural gas prices were elevated. As a
result, during the first quarter of 2003, this category of customer caused the
Company to purchase supplemental quantities of natural gas at prices greater
than the contracted sales realization. Because of losses sustained and the
desire to reduce working capital requirements, management decided to exit this
region and type of account.
Under SFAS No. 144, the assets, liabilities and operating results of
the discontinued operation have been restated and presented separately as
discontinued operations in both the Company's consolidated balance sheet and
statement of operations for all periods presented. A summary of account balances
for the discontinued New England operation is presented as follows (in
thousands):
Year Ended December 31,
--------------------------
2003 2002
----------- ------------
Accounts receivable, net...................................... $ 4,082 $ 13,214
Risk management assets........................................ 785 6,632
Inventory ................................................. 39 946
Prepaid deposit............................................... 234 202
----------- ------------
Total Assets......................................... $ 5,140 $ 20,994
=========== ============
Accounts payable.............................................. $ 438 $ 144
Accrued liabilities........................................... 61 115
Risk management liabilities................................... 638 4,771
----------- ------------
Total Liabilities.................................... $ 1,137 $ 5,030
=========== ============
The New England operation has no fixed assets or capitalized costs
associated with intangibles; therefore, an impairment assessment of long-lived
assets is not necessary. Further, all contracts associated with this operation
are recorded at fair value pursuant to SFAS No. 133, as amended, with such
valuation included in the above presentation as risk management assets and
liabilities.
II-31
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
An exit plan was implemented and provides for the following:
- Cessation of any new contracts.
- Satisfaction of existing contracts in accordance with
required terms.
- Collection of accounts receivable as they become due.
- Sale, assignment or transfer of intangible assets
such as customer lists, industry specific accounting
software and experienced personnel.
The Company entered into an agreement with a third party to hire the
Company's personnel and assume associated office operating lease obligations
effective November 1, 2003. Additionally, management believes that no
significant severance or shut-down cost will be incurred as a result of
discontinuance of this operation.
For comparative purposes, marketing segment revenues and costs and
expenses have been restated for each of the years ended December 31, 2002 and
2001 to conform to the current year presentation. See Note (12) of Notes to
Consolidated Financial Statements for a table summarizing the effect on prior
period presentation.
(4) INCOME TAXES
The following table shows the components of the Company's income tax
provision (benefit) (in thousands):
Years Ended December 31,
----------------------------------------
2003 2002 2001
--------- ---------- ----------
Current:
Federal......................................... $ 515 $ 2,796 $ (3,901)
State........................................... 110 301 -
--------- ---------- ----------
625 3,097 (3,901)
Deferred:
Federal......................................... 674 (2,087) 1,492
State........................................... 36 (246) -
--------- ---------- ----------
$ 1,335 $ 764 $ (2,409)
========= ========== ===========
The following table summarizes the components of the income tax
provision (benefit) (in thousands):
Years Ended December 31,
-----------------------------------------
2003 2002 2001
----------- ------------ -----------
From continuing operations........................... $ 3,056 $ 1,751 $ (4,776)
From discontinued operations......................... (1,664) (987) 2,338
Cumulative effect of accounting change............... (57) - 29
----------- ------------ -----------
$ 1,335 $ 764 $ (2,409)
=========== ============ ===========
II-32
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Taxes computed at the corporate federal income tax rate reconcile to
the reported income tax provision as follows (in thousands):
Years Ended December 31,
--------------------------------------
2003 2002 2001
---------- ---------- ----------
Statutory federal income tax provision
(benefit) at 34%.......................................... $ 1,509 $ 735 $ (2,353)
State tax provision, net of federal benefit................. 96 55 -
Federal statutory depletion................................. (304) (100) (51)
Other....................................................... 34 74 (5)
---------- ---------- ----------
Income tax provision (benefit)..................... $ 1,335 $ 764 $ (2,409)
========== ========== ===========
Deferred income taxes primarily represent the net tax effect of
temporary differences between the financial statement carrying amounts in excess
of the underlying tax basis of property and equipment. The components of the net
federal deferred tax liability are as follows (in thousands):
Years Ended December 31,
----------------------------------
2003 2002
----------- ------------
Deferred tax assets:
Allowance for doubtful accounts..................... $ 663 $ 324
State net operating losses.......................... 236 336
Other............................................... 94 207
----------- ------------
993 867
----------- ------------
Deferred tax liabilities:
Derivative energy contracts......................... (317) -
Property and equipment.............................. (3,552) (3,123)
Other............................................... (91) -
----------- ------------
(3,960) (3,123)
----------- ------------
Net deferred tax (liability)............................. $ (2,967) $ (2,256)
=========== ============
(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
II-33
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 89 percent of the Company's total receivables as of
December 31, 2003, and industry practice requires payment for purchases of crude
oil to take place on the 20th of the month following a transaction, while
natural gas transactions are settled on the 25th 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 10.5 percent of total accounts
receivable as of December 31, 2002.
There were no single significant bad debt write-offs in 2003 and 2002.
In 2001, primarily as a result of the bankruptcy of Enron Corp., the Company
incurred $1,735,000 million of bad debt expense. An allowance for doubtful
accounts is provided where appropriate and accounts receivable presented herein
are net of allowances for doubtful accounts of $1,935,000 and $1,723,000 at
December 31, 2003 and 2002, respectively. An analysis of the changes in the
allowance for doubtful accounts is presented as follows (in thousands):
2003 2002 2001
--------- -------- ---------
Balance, Beginning of year....................... $ 1,723 $ 1,993 $ 559
Provisions for bad debts....................... 433 390 1,735
Less: Write-offs and reductions............... (221) (660) (301)
---------- -------- ---------
Balance, End of year............................. $ 1,935 $ 1,723 $ 1,993
========= ======== =========
(6) EMPLOYEE BENEFITS
The Company maintains a 401(k) savings plan for the benefit of its
employees. Company contributions to the plan were $384,000 in 2003, $388,000 in
2002, $433,000 in 2001. There are no pension or retirement plans maintained by
the Company.
(7) TRANSACTIONS WITH RELATED PARTIES
Mr. K. S. Adams, Jr., Chairman and President of the Company, is a
limited partner in certain family limited partnerships known as Sakco, Ltd.
("Sakco"), Kenada Oil & Gas, Ltd. ("Kenada") and Kasco, Ltd. ("Kasco"). From
time to time, Mr. Adams individually, the family partnerships as well as
Sakdril, Inc. ("Sakdril"), a wholly owned subsidiary of KSA Industries, Inc., (a
major stockholder of the Company, and controlled by Mr. Adams) participate as
working interest owners in certain oil and gas wells operated by the Company. In
addition, these entities may participate in non-Company operated wells where the
Company also holds an interest. Sakco, Kenada, Kasco, Sakdril and Mr. Adams
participated in each of the wells under terms no better than those afforded
other non-affiliated working interest owners. In recent years, such related
party transactions tend to result after the Company has first identified oil and
gas prospects of interest. Due to capital budgeting constraints, typically the
available dollar commitment to participate in such transactions is greater than
the amount management is
II-34
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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,
2003 and 2002, the Company owed a combined net total of $1,088,000 and $308,000,
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
$138,000 in 2003 and $146,000 in 2002.
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, 2003, 2002, and 2001 was $5,831,000, $5,944,000 and
$7,035,000, respectively. At December 31, 2003, commitments under long-term
non-cancelable operating leases for the next five years and thereafter are
payable as follows: 2004 - $4,609,000; 2005 - $3,135,000; 2006 - $2,373,000;
2007 - $2,064,000; 2008 and thereafter - $2,678,000.
On January 1, 2003, the Company adopted SFAS No. 143 "Accounting of
Asset Retirement Obligations". SFAS No. 143 establishes an accounting model for
accounting and reporting obligations associated with retirement of tangible
long-lived assets and associated retirement costs. A summary of the recording of
the estimated fair value of the Company's asset retirement obligations is
presented as follows (in thousands):
Amount
----------
Balance, January 1, 2003........................................... $ -
Impact of accounting change........................................ 672
Additions.......................................................... 63
Retirements........................................................ (29)
----------
Balance, December 31, 2003......................................... $ 706
==========
On August 30, 2000, CJC Leasing, Inc. ("CJC"), a wholly owned
subsidiary of the Company previously involved in the coal mining business,
received a "Notice of Taxes Due" from the State of Kentucky regarding the
results of a coal severance tax audit covering the years 1989 through 1993. The
audit initially proposed a tax assessment of $8.3 million plus penalties and
interest. CJC protested the assessment and set forth a number of defenses
including that CJC was not a taxpayer engaged in severing and/or mining coal at
anytime during the assessment period. Further, it is CJC's informed belief that
such taxes were properly paid by the third parties that had in fact mined the
coal. In October
II-35
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2003, CJC resolved this matter by payment of $40,000 to the State in full
settlement of all issues included therein. Such settlement payment was expensed
in fourth quarter 2003 results.
On July 31, 2002, pursuant to a workmen's compensation claim filed by
the family of a deceased employee, the plaintiffs in the workmen's compensation
case also filed a complaint with the Occupational Safety and Health
Administration ("OSHA"). The OSHA complaint alleging that the Company's wholly
owned subsidiary, Service Transport Company, failed to produce employee exposure
and other records including air sampling data and medical monitoring records
from years 1989 through 1997. The Company responded to the alleged violations
denying that it failed to produce such data. To date, the Company has not
received a response from OSHA and no further action from OSHA is expected.
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. Management believes the claims made
for the arbitration are not consistent with the terms of the joint venture
agreement. Further, management does not believe a re-audit or arbitration of
this matter will have a significant 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.
(9) GUARANTEES
In November 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees Including Indirect
Guarantees of Indebtedness of Others". In certain instances, this interpretation
requires a guarantor to recognize, at the inception of a guarantee, a liability
for the fair value of the obligation undertaken in issuing the guarantee.
Pursuant to arranging operating lease financing for truck tractors and tank
trailers, individual subsidiaries of the Company, may guarantee the lessor a
minimum residual sales value upon the expiration of a lease and sale of the
underlying equipment. Aggregate guaranteed residual values for tractors and
trailers under operating leases as of December 31, 2003 are as follows (in
thousands):
There-
2004 2005 2006 2007 after Total
----------- ---------- ---------- --------- --------- -------
Lease residual values................. $ 1,249 $ 762 $ 150 $ - $ 1,008 $ 3,169
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
II-36
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
parent guarantees of commitments resulting from the ongoing activities of its
subsidiary companies. The guarantees generally result as incident to subsidiary
commodity purchase obligation, subsidiary lease commitments and subsidiary bank
debt. The nature of such guarantees is to guarantee the performance of the
subsidiary companies in meeting their respective underlying obligations. Except
for operating lease commitments, all such underlying obligations are recorded on
the books of the subsidiary companies and are included in the consolidated
financial statements included herein. Therefore, 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, 2003, the amount of parental guaranteed obligations are approximately as
follows (in thousands):
2004 2005 2006 2007 Thereafter Total
---------- --------- ---------- --------- ---------- -----------
Bank Debt...................... $ - $ 1,434 $ 5,738 $ 4,303 $ - $ 11,475
Operating leases............... 4,609 3,135 2,373 2,064 2,678 14,859
Lease residual values.......... 1,249 762 150 - 1,008 3,169
Commodity purchases............ 17,401 - - - - 17,401
Letters of credit.............. 30,200 - - - - 30,200
---------- --------- ---------- --------- ---------- -----------
$ 53,459 $ 5,331 $ 8,261 $ 6,367 $ 3,686 $ 77,104
========== ========= ========== ========= ========== ===========
II-37
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(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):
Segment Property
Operating Depreciation, and
Earnings Depletion and Equipment
Revenues (Loss) Amortization Additions
------------- -------------- --------------- -------------
Year ended December 31, 2003-
Marketing........................ $ 1,677,728 $ 12,244 $ 1,397 $ 1,798
Transportation................... 35,806 973 2,093 1,387
Oil and gas...................... 8,395 2,310 2,175 4,586
------------- -------------- --------------- -------------
$ 1,721,929 $ 15,527 $ 5,665 $ 7,771
============= ============== =============== =============
Year ended December 31, 2002 -
Marketing........................ $ 1,726,194 $ 10,872 $ 1,611 $ 150
Transportation................... 36,406 2,142 1,838 1,911
Oil and gas...................... 4,750 (633)(1) 2,116 2,561
------------- -------------- --------------- -------------
$ 1,767,350 $ 12,381 $ 5,565 $ 4,622
============= ============== =============== =============
Year ended December 31, 2001 -
Marketing........................ $ 3,444,050 $ (8,846)(2) $ 2,600 $ 847
Transportation................... 33,149 1,053 1,660 635
Oil and gas...................... 6,111 693 2,456 2,109
Other............................ - - 10 -
------------- -------------- --------------- -------------
$ 3,483,310 $ (7,100) $ 6,726 $ 3,591
============= ============== =============== =============
- --------------------
(1) The 2002 oil and gas loss includes $1.7 million in dry hole costs and oil
and gas property valuation write-downs.
(2) The 2001 marketing 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.
Intersegment sales are insignificant. All sales by the Company occurred
in the United States. In each of 2003 and 2002, the Company had sales to one
customer that totaled $177,000,000 and $247,000,000, 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):
II-38
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Year Ended December 31,
--------------------------------
2003 2002 2001
-------- -------- --------
Segment operating earnings (loss) ....... $ 15,527 $ 12,381 $ (7,100)
General and administrative expenses...... (6,299) (7,259) (7,165)
-------- -------- --------
Operating earnings ...................... 9,228 5,122 (14,265)
Interest income ......................... 362 115 456
Interest expense ........................ (108) (117) (128)
-------- -------- --------
Earnings from continuing operations
before income taxes ................... $ 9,482 $ 5,120 $(13,937)
======== ======== ========
Identifiable assets by industry segment are as follows (in thousands):
Year Ended December 31,
--------------------------------------------
2003 2002 2001
------------ ----------- ------------
Marketing................................... $ 144,722 $ 124,336 $ 153,465
Transportation.............................. 14,564 15,931 14,268
Oil and gas................................. 13,817 11,504 11,265
Discontinued operations..................... 5,140 20,994 29,449
Other....................................... 32,018 29,355 18,580
------------ ----------- ------------
$ 210,261 $ 202,120 $ 227,027
============ =========== ============
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
II-39
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
The co-venture participant initially conducted an audit of the joint
venture in June 2002 and management was led to believe the audit produced no
adverse findings. However, 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. Management believes the claims made are not consistent with the
terms of the joint venture agreement. Further, management does not believe a
re-audit or arbitration of this matter will have a significant adverse effect on
the Company's financial position or results of operations.
The Company continues to implement the final wind-down and settlement
of open trade account items. As of December 31, 2003, the venture's remaining
trade accounts due totaled approximately $3.1 million and trade accounts payable
totaled approximately $6.8 million. As the venture either collects or funds cash
proceeds in settlement of such accounts, the Company will receive or pay its
pro-rata 50 percent share of such cash proceeds or requirements.
(12) RESTATEMENT OF REVENUES AND EXPENSES
As discussed in Notes (2) and (3) of Notes to Consolidated Financial
Statements, the presentation of marketing segment Revenues and Costs and
Expenses was changed for 2002 and 2001 reporting. Such change relates to the
presentation on a net basis of natural gas purchase and sales subject to
mark-to-market accounting and the reclassification of discontinued operations
for segregated disclosure. The table below summarizes the effect on 2002 and
2001 for these changes (in thousands):
Year Ended Year Ended
December 31, 2002 December 31, 2001
-------------------------- --------------------------
Currently Previously Currently Previously
Reported Reported Reported Reported
----------- ----------- ----------- -----------
Revenues:
Marketing ............................ $ 1,726,194 $ 2,282,161 $ 3,444,050 $ 4,677,982
Costs and Expenses:
Marketing ............................ $ 1,713,711 $ 2,271,664 $ 3,450,296 $ 4,676,612
Operating earnings ..................... $ 5,122 $ 2,222 $ (14,265) $ (7,378)
Earnings (loss) before income tax....... $ 5,120 $ 2,216 $ (13,937) $ (7,062)
Earnings (loss) from discontinued
operations, net ...................... $ (1,917) $ - $ 4,537 $ -
Net earnings (loss) .................... $ 1,452 $ 1,452 $ (4,569) $ (4,569)
II-40
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As discussed in Note (3) of Notes to Consolidated Financial Statements,
the presentation of certain balance sheet items was changed for 2002 reporting
of assets and liabilities from discontinued operations. The table below
summarizes the effect on 2002 for these changes (in thousands):
December 31, 2002
-------------------------
Currently Previously
Reported Reported
-------- --------
Accounts receivable, net ............................ $120,036 $133,250
Inventories ......................................... $ 5,645 $ 6,591
Risk management receivables ......................... $ 1,934 $ 8,220
Prepayments ......................................... $ 3,147 $ 3,349
Current assets of discontinued operation ............ $ 20,994 $ -
Risk management assets .............................. $ - $ 346
Accounts payable .................................... $137,100 $137,244
Risk management payable ............................. $ 2,004 $ 6,452
Accrued and other liabilities ....................... $ 3,950 $ 4,066
Current liabilities of discontinued operation........ $ 5,030 $ -
Risk management liabilities ......................... $ - $ 322
(13) QUARTERLY FINANCIAL DATA (UNAUDITED) -
Selected quarterly financial data and earnings per share of the Company
are presented below for the years ended December 31, 2003 and 2002 (in
thousands, except per share data):
Earnings from
Continuing
Operations Net Earnings Dividends
------------------------ --------------------- -------------------
Per Per Per
Revenues Amount Share Amount Share Amount Share
-------------- ----------- ------ ---------- ------- ------ ------
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
============== =========== ====== ========== ======= ====== ======
2002 -
March 31........... $ 378,635 $ 2,105 $ .50 595 $ .14 $ - $ -
June 30............ 492,989 556 .13 555 .13 - -
September 30....... 502,720 105 .02 189 .05 - -
December 31........ 393,006 603 .14 113 .02 548 .13
-------------- ----------- ------ ---------- ------- ------ ------
$ 1,767,350 $ 3,369(1) $ .79 $ 1,452 $ .34 $ 548 $ .13
============== =========== ====== ========== ======= ====== ======
- -----------------
(1) Reported earnings for 2002 are net of $1.7 million of dry hole costs and
property valuation write-downs.
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
II-41
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
are of a normal recurring nature.
(14) OIL AND GAS PRODUCING ACTIVITIES
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,
---------------------------------------
2003 2002 2001
---------- ---------- ----------
Property acquisition costs
Unproved...................................... $ 1,311 $ 1,126 $ 43
Proved........................................ - - -
Exploration costs
Expensed...................................... 1,638 1,177 821
Capitalized................................... 1,339 75 -
Development costs.................................. 1,936 1,248 2,067
---------- ---------- ----------
Total costs incurred............................... $ 6,224 $ 3,626 $ 2,931
========== ========== ==========
The aggregate capitalized costs relative to oil and gas producing
activities are as follows (in thousands):
December 31,
-----------------------------
2003 2002
---------- ----------
Unproved oil and gas properties...................... $ 2,713 $ 2,190
Proved oil and gas properties........................ 38,953 35,289
---------- ----------
41,666 37,479
Accumulated depreciation, depletion
and amortization................................... (29,292) (27,501)
---------- ----------
Net capitalized cost........................ $ 12,374 $ 9,978
========== ==========
II-42
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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,
----------------------------------------------------------------
2003 2002 2001
------------------- ------------------- ---------------------
Natural Natural Natural
Gas Oil Gas Oil Gas Oil
(Mcf's) (Bbls.) (Mcf's) (Bbls.) (Mcf's) (Bbls.)
-------- ------- ------- ------- ------- -------
Total proved reserves-
Beginning of year 7,480 579 7,618 618 8,642 626
Revisions of previous estimates 37 (223) 206 (1) (820) 7
Oil and gas reserve purchases - - - - 11 25
Extensions, discoveries and
other reserve additions 2,693 144 703 17 816 24
Production (1,239) (62) (1,047) (55) (1,031) (64)
------ ---- ------ --- ------ ---
End of year 8,971 438 7,480 579 7,618 618
------ --- ------ --- ------ ---
Proved developed reserves -
End of year 8,971 438 7,480 579 7,617 609
====== === ===== === ===== ===
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):
II-43
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31,
---------------------------------
2003 2002 2001
---- ---- ----
Future gross revenues....................... $ 64,442 $ 47,887 $ 28,465
Future costs -
Lease operating expenses................ (18,035) (16,142) (11,008)
Development costs....................... (221) (360) (468)
-------- -------- --------
Future net cash flows before income taxes... 46,186 31,385 16,989
Discount at 10% per annum................... (18,351) (14,657) (7,636)
-------- -------- --------
Discounted future net cash flows
before income taxes..................... 27,835 16,728 9,353
Future income taxes, net of discount at 10%
per annum............................... (9,464) (5,687) (3,180)
-------- -------- --------
Standardized measure of
discounted future net cash flows........ $ 18,371 $ 11,041 $ 6,173
======== ======== ========
The reserve estimates provided at December 31, 2003, 2002 and 2001 are
based on year-end market prices of $30.15, $27.94 and $17.55 per barrel for
crude oil and $5.71, $4.20 and $2.34 per Mcf for natural gas, respectively. The
year-end December 31, 2003 price used in the 2003 reserve estimate is comparable
to average actual December 2003 price received for sales of crude oil ($29.87
per barrel) and sales of natural gas ($4.45 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,
--------------------------------
2003 2002 2001
---- ---- ----
Beginning of year ..................................... $ 11,041 $ 6,173 $ 25,190
Revisions to reserves proved in prior years -
Net change in prices and production costs ....... 6,508 9,016 (32,056)
Net change due to revisions in quantity estimates (3,235) 353 (772)
Accretion of discount ........................... 1,465 763 3,158
Production rate changes and other ............... (3,463) (2,375) 3,195
-------- -------- --------
Total revisions .............................. 1,275 7,757 (26,475)
Purchase of oil and gas reserves, net of future
production costs ................................ - - 263
New field discoveries and extensions,
net of future production costs .................. 15,955 2,278 1,369
Sales of oil and gas produced, net of
production costs ................................ (6,123) (2,660) (3,970)
Net change in income taxes ........................ (3,777) (2,507) 9,796
-------- -------- --------
Net change in standardized measure of
discounted future net cash flows ................ 7,330 4,868 (19,017)
-------- -------- --------
End of year ........................................... $ 18,371 $ 11,041 $ 6,173
======== ======== ========
II-44
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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,
----------------------------------------
2003 2002 2001
----------- ---------- ----------
Revenues.......................................................... $ 8,395 $ 4,750 $ 6,111
Costs and expenses -
Production.................................................... 2,272 2,090 2,141
Exploration................................................... 1,638 1,177 821
Depreciation, depletion and amortization...................... 2,175 2,116 2,456
----------- ---------- ----------
Operating income (loss) before income taxes....................... 2,310 (633) 693
Income tax (expense) benefit...................................... (788) 215 (236)
------------ ---------- -----------
Operating income (loss)........................................... $ 1,522 $ (418) $ 457
=========== =========== ==========
II-45
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 2003, 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
significant changes were made in internal controls or procedures or in other
factors that could significantly affect these controls subsequent to the date of
their evaluation, including any corrective actions with regard to significant
deficiencies and material weaknesses.
II-46
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 14, 2004, 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 14, 2004, 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 14, 2004, 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 14, 2004, 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 14, 2004, 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.
III-1
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, 2003
and 2002
Consolidated Statement of Operations for the Years
Ended December 31, 2003, 2002 and 2001
Consolidated Statement of Shareholders' Equity for
the Years Ended December 31, 2003, 2002 and 2001
Consolidated Statement of Cash Flows for the Years
Ended December 31, 2003, 2002 and 2001
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)
IV-1
4(c)* - Eleventh Amendment to Loan Agreement between Service Transport
Company et al and Bank of America, N.A. dated March 16, 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
(b) - Reports on Form 8-K
A report on Form 8-K dated November 19, 2003 as furnished on
November 19, 2003 to announce earnings for the third quarter
ended September 30, 2003.
- ------------------------------
* - 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.
IV-2
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-Finance, Director President,Chairman of the Board,
and Chief Financial Officer) and Chief Executive Officer)
Date: March 16, 2004
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/JOHN A. BARRETT By /s/ E. C. REINAUER, JR.
------------------------------------- ---------------------------------
(John A. Barrett, Director) (E. C. Reinauer, Jr., Director)
By /s/ VINCENT H. BUCKLEY By /s/ E. JACK WEBSTER, JR.
------------------------------------- ---------------------------------
(Vincent H. Buckley, Director) (E. Jack Webster, Jr., Director)
By /s/ EDWARD WIECK
-------------------------------------
(Edward Wieck, Director)
Date: March 16, 2004
IV-3
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)* - Eleventh Amendment to Loan Agreement between Service Transport
Company et al and Bank of America, N.A. dated March 16, 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 Section 302 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
IV-4