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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-Q
(Mark One)
[X] Quarterly report pursuant to Section 13 or 15 (d) of the Securities
Exchange Act of 1934
For the quarterly period ended September 30, 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
incorporation or organization) Identification No.)
4400 Post Oak Pkwy Ste 2700 , Houston, Texas 77027
--------------------------------------------------
(Address of principal executive office & Zip Code)
Registrant's telephone number, including area code (713) 881-3600
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. YES [X] NO [ ]
Indicate by check mark whether the registrant is an accelerated filer
as defined in Rule 12b-2 of the Act. YES [ ] NO [X]
A total of 4,217,596 shares of Common Stock were outstanding at
November 4, 2003.
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENT OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Nine Months Ended Three Months Ended
September 30, September 30,
----------------------------- ----------------------------
2003 2002 2003 2002
---- ---- ---- ----
REVENUES:
Marketing........................................... $ 1,266,362 $ 1,343,989 $ 388,859 $ 492,150
Transportation...................................... 26,574 27,308 8,149 9,426
Oil and gas......................................... 6,564 3,047 2,235 1,144
------------- ------------ ------------- ------------
1,299,500 1,374,344 399,243 502,720
------------- ------------ ------------- ------------
COSTS AND EXPENSES:
Marketing........................................... 1,255,613 1,334,344 386,089 490,540
Transportation...................................... 24,374 24,227 8,107 8,382
Oil and gas......................................... 2,485 2,008 889 734
General and administrative.......................... 4,647 5,608 1,640 1,454
Depreciation, depletion and amortization............ 3,951 3,762 1,317 1,470
------------- ------------ ------------- ------------
1,291,070 1,369,949 398,042 502,580
------------- ------------ ------------- ------------
Operating earnings..................................... 8,430 4,395 1,201 140
Other income (expense):
Interest income .................................... 333 80 63 34
Interest expense.................................... (106) (93) (44) (36)
------------- ------------ ------------- ------------
Earnings from continuing operations before
income taxes and cumulative effect of
accounting change................................... 8,657 4,382 1,220 138
Income tax provision................................... 3,252 1,616 393 33
------------- ------------ ------------- ------------
Earnings from continuing operations.................... 5,405 2,766 827 105
Income (loss) from discontinued operation,
net of tax benefit (provision) of $1,753, $874,
$71 and $(51), respectively......................... (2,862) (1,427) (154) 84
------------- ------------ ------------- ------------
Earnings before cumulative effect of
accounting change................................... 2,543 1,339 673 189
Cumulative effect of accounting change,
net of tax of $57................................... (92) - - -
------------- ------------ ------------- ------------
Net earnings........................................... $ 2,451 $ 1,339 $ 673 $ 189
============= ============ ============= ============
EARNINGS (LOSS) PER SHARE:
From continuing operations.......................... $ 1.28 $ .66 $ .20 $ .03
From discontinued operation......................... (.68) (.34) (.04) .02
Cumulative effect of accounting change.............. (.02) - - -
------------- ------------ ------------- ------------
Basic and diluted net earnings
per common share.................................. $ .58 $ .32 $ .16 $ .05
============= ============ ============= ============
DIVIDENDS PER COMMON SHARE............................. $ - $ - $ - $ -
============= ============ ============= ============
The accompanying notes are an integral part of these financial statements.
-2-
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED BALANCE SHEET
(IN THOUSANDS)
September 30, December 31,
2003 2002
------------ ------------
ASSETS
Current assets:
Cash and cash equivalents................................... $ 34,422 $ 27,262
Accounts receivable, net.................................... 116,115 120,036
Inventories................................................. 3,252 5,645
Risk management receivables................................. 1,679 1,934
Income tax receivable....................................... 57 382
Prepayments................................................. 4,473 3,147
Current assets of discontinued operation.................... 6,759 20,994
------------ ------------
Total current assets.......................... 166,757 179,400
------------ ------------
Property and equipment........................................ 80,904 75,419
Less - accumulated depreciation,
depletion and amortization........................... (56,645) (53,115)
------------ ------------
24,259 22,304
------------ ------------
Other assets.................................................. 415 416
------------ ------------
$ 191,431 $ 202,120
============ ============
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable............................................ $ 128,173 $ 137,100
Risk management payables.................................... 1,091 2,004
Accrued and other liabilities............................... 4,175 3,950
Current liabilities of discontinued operation............... 1,361 5,030
------------ ------------
Total current liabilities..................... 134,800 148,084
Long-term debt................................................ 11,475 11,475
Deferred taxes and other...................................... 2,605 2,461
------------ ------------
148,880 162,020
------------ ------------
Commitments and contingencies (Note 7)
Shareholders' equity:
Preferred stock - $1.00 par value, 960,000 shares
authorized, none outstanding............................ - -
Common stock - $.10 par value, 7,500,000 shares
authorized, 4,217,596 shares outstanding................ 422 422
Contributed capital......................................... 11,693 11,693
Retained earnings .......................................... 30,436 27,985
------------ ------------
Total shareholders' equity ................... 42,551 40,100
------------ ------------
$ 191,431 $ 202,120
============ ============
The accompanying notes are an integral part of these financial statements.
-3-
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
(IN THOUSANDS)
Nine Months Ended
September 30,
---------------------------
2003 2002
---- ----
CASH PROVIDED BY OPERATIONS:
Earnings from continuing operations............................................ $ 5,405 $ 2,766
Adjustments to reconcile net earnings to net
cash provided by operating activities -
Depreciation, depletion and amortization..................................... 3,951 3,762
Gains on property sales...................................................... (102) (281)
Write-off of dry hole costs.................................................. - 245
Other, net................................................................... (302) (57)
Changes in operating assets and liabilities -
Decrease (increase) in accounts receivable, net ............................. 3,921 4,375
Decrease (increase) in inventories .......................................... 2,393 2,196
Risk management activities................................................... (658) 2,186
Decrease (increase) in income tax receivable................................. 325 1,958
Decrease (increase) in prepayments........................................... (1,326) 4,103
Increase (decrease) in accounts payable...................................... (8,927) (20,346)
Increase (decrease) in accrued and other liabilities......................... 225 (300)
---------- ----------
Net cash provided by continuing operations....................................... 4,905 607
Net cash provided by discontinued operation...................................... 7,704 13,370
---------- ----------
Net cash provided by operating activities ....................................... 12,609 13,977
---------- ----------
INVESTING ACTIVITIES:
Property and equipment additions .............................................. (5,572) (3,810)
Proceeds from property sales................................................... 123 320
---------- ----------
Net cash used in investing activities........................................ (5,449) (3,490)
---------- ----------
FINANCING ACTIVITIES:
Repayment of debt............................................................ - (1,000)
---------- ----------
Net cash used in financing activities........................................ - (1,000)
---------- ----------
Increase in cash and cash equivalents............................................ 7,160 9,487
Cash at beginning of period...................................................... 27,262 14,177
---------- ----------
Cash at end of period............................................................ $ 34,422 $ 23,664
========== ==========
Supplemental disclosure of cash flow information:
Interest paid during the period ............................................. $ 53 $ 96
========== ==========
Income taxes paid during the period.......................................... $ 1,581 $ 1,575
========== ==========
The accompanying notes are an integral part of these financial statements.
-4-
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Basis of Presentation
The accompanying consolidated financial statements are unaudited but,
in the opinion of the Company's management, include all adjustments (consisting
of normal recurring accruals) necessary for the fair presentation of its
financial position at September 30, 2003 and December 31, 2002 and its results
of operations for the nine months and three months ended September 30, 2003 and
2002 and its cash flows for the nine months ended September 30, 2003 and 2002.
Certain information and note disclosures normally included in annual financial
statements prepared in accordance with generally accepted accounting principles
have been condensed or omitted pursuant to Securities and Exchange Commission
rules and regulations. Although the Company believes the disclosures made are
adequate to make the information presented not misleading, it is suggested that
these consolidated financial statements be read in conjunction with the
financial statements, and the notes thereto, included in the Company's latest
annual report on Form 10-K. The interim statement of operations is not
necessarily indicative of results to be expected for a full year.
Note 2 - Summary of Significant Accounting Policies
Principles of Consolidation
The accompanying consolidated financial statements include the accounts
of Adams Resources & Energy, Inc., a Delaware corporation, and its wholly owned
subsidiaries (the "Company") after elimination of all significant intercompany
accounts and transactions. 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 (5) of Notes to Unaudited 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 maturity of 30 days or less. Included in
the cash balance at September 30, 2003 and December 31, 2002 is a deposit of $2
million to collateralize the Company's month-to-month crude oil letter of credit
facility.
-5-
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. Components of inventory are
as follows (IN THOUSANDS):
September 30, December 31,
2003 2002
------------- ------------
Crude oil....................................... $ 434 $ 3,062
Petroleum products.............................. 2,229 1,919
Materials and supplies.......................... 589 664
------------- ------------
$ 3,252 $ 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.
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.
-6-
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
contracts. 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.
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 the nine month and the three month periods
ended September 30, 2003 and 2002. There were no potentially dilutive securities
during 2003 and 2002.
Use of Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from those estimates. Examples of significant estimates used in the accompanying
consolidated financial statements include the accounting for depreciation,
depletion and amortization, income taxes, contingencies and price risk
management activities.
Price Risk Management Activities
SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities", as amended by SFAS No. 137 and No. 138 establishes accounting and
reporting standards that require every derivative instrument (including certain
derivative instruments embedded in other contracts) be recorded on the balance
sheet as either an asset or liability measured at its fair value, unless the
derivative qualifies and has been designated as a normal purchase or sale.
Changes in fair value are recognized immediately in earnings unless the
derivatives qualify for, and the Company elects, cash flow hedge accounting. For
cash flow hedges, the effected portion of the change in fair value will be
deferred in other comprehensive income until the related hedge item impacts
earnings. The Company had no contracts designated for hedge accounting under
SFAS No. 133 during any current reporting periods.
-7-
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-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 (9) of Notes
to Unaudited Consolidated Financial Statements for a table summarizing the
effect on the period ended September 30, 2002.
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 September 30, 2003 is
$588,000, all of which will be received in 2003. The estimated future cash
inflow approximates the net fair value recorded in the Company's risk management
assets and liabilities.
-8-
The following table illustrates the factors impacting the change in the
net value of the Company's risk management assets and liabilities for the period
ended September 30, 2003. (IN THOUSANDS):
2003
----
Net fair value on January 1,......................................... $ (70)
Activity during 2003
- Net cash paid on settled contracts .......................... 206
- Net realized (loss) from prior years' contracts ............. (136)
- Net unrealized gain from prior years' contracts ............. 320
- Net unrealized gain from current year contracts ............. 399
- Net unrealized loss from current year contracts............. (131)
----------
Net fair value on September 30,...................................... $ 588
==========
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 Unaudited
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
-9-
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 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 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
September 30, 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.
Note 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.
The Company's management has decided to withdraw from its New England
region retail natural gas marketing business, which is included in the marketing
segment. This business unit
-10-
had negative operating margins of $4,615,000 and $2,301,000 and had after tax
losses totaling $2,862,000 and $1,427,000 during the nine-month periods ended
September 30, 2003 and 2002, respectively. For the three-month periods ended
September 30, 2003 and 2002, this unit had negative operating margins of
$154,000 and positive margins of $84,000, respectively. Such losses 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. In June 2003, two
customers of this unit filed for Chapter 11 bankruptcy. As a result, the Company
incurred a $475,000 bad debt charge to discontinued operation earnings during
the second quarter of 2003.
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 New England operation is presented as follows (IN THOUSANDS):
September 30, December 31,
2003 2002
------------- ------------
Accounts receivable, net.................... $ 5,193 $ 13,214
Risk management assets...................... 1,251 6,632
Inventory................................... 88 946
Prepaid deposit............................. 227 202
------------- ------------
Total Assets....................... $ 6,759 $ 20,994
============= ============
Accounts payable............................ $ 21 $ 144
Accrued liabilities......................... 71 115
Risk management liabilities................. 1,269 4,771
------------- ------------
Total Liabilities.................. $ 1,361 $ 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.
In addition to the weather sensitive "full requirements" contracts,
this unit's largest accounts are manufacturing facilities where natural gas
usage does not vary widely with the
-11-
season. For manufacturing type accounts, volume usage is required to meet
certain narrow tolerances to reduce exposure to volume risk. Management believes
the New England operation is viable with concentration on manufacturing accounts
and elimination of full requirements contracts. However, by discontinuing the
operation, the Company eliminates the requirement to fund substantial amounts of
net working capital. Management believes such working capital is better utilized
by the Company's wholesale crude oil and natural gas businesses.
An exit plan has been 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 to a third party intangible
assets such as customer lists, industry specific accounting
software and experienced sales and back-office personnel.
The Company has 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. Management believes it has a workable exit plan and
expects the New England operation to be divested prior to March 31, 2004.
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 the nine months ended September 30, 2002 to
conform to the current year presentation. See Note (9) of Notes to Unaudited
Consolidated Financial Statements for a table summarizing the effect on prior
period presentation.
Note 4 - Segment Reporting
The Company is primarily engaged in the business of marketing crude
oil, natural gas and petroleum products; tank truck transportation of liquid
chemicals; and oil and gas exploration and production. Information concerning
the Company's various business activities is summarized as follows (IN
THOUSANDS):
-12-
Segment Depreciation, Property
Operating Depletion and
Earnings and Equipment
Revenues (Losses) Amortization Additions
-------- ------------ ------------ ---------
For the nine months ended
September 30, 2003
Marketing........................ $ 1,266,362 $ 9,705 $ 1,044 $ 1,651
Transportation................... 26,574 667 1,533 730
Oil and gas...................... 6,564 2,705 1,374 3,191
------------- ------------ ------------ -----------
$ 1,299,500 $ 13,077 $ 3,951 $ 5,572
============= ============ ============ ===========
For the nine months ended
September 30, 2002
Marketing........................ $ 1,343,989 $ 8,359 $ 1,286 $ 38
Transportation................... 27,308 1,805 1,276 1,876
Oil and gas...................... 3,047 (161) 1,200 1,896
------------- ------------ ------------ -----------
$ 1,374,344 $ 10,003 $ 3,762 $ 3,810
============= ============ ============ ===========
For the three months ended
September 30, 2003
Marketing........................ $ 388,859 $ 2,444 $ 326 $ 927
Transportation................... 8,149 (463) 505 135
Oil and gas...................... 2,235 860 486 466
------------- ------------ ------------ -----------
$ 399,243 $ 2,841 $ 1,317 $ 1,528
============= ============ ============ ===========
For the three months ended
September 30, 2002
Marketing........................ $ 492,150 $ 1,266 $ 344 $ 15
Transportation................... 9,426 518 526 1,414
Oil and gas...................... 1,144 (190) 600 882
------------- ------------ ------------ -----------
$ 502,720 $ 1,594 $ 1,470 $ 2,311
============= ============ ============ ===========
Identifiable assets by industry segment are as follows (IN THOUSANDS):
September 30, December 31,
2003 2002
------------- ------------
Marketing......................................... $ 121,017 $ 124,336
Transportation.................................... 13,069 15,931
Oil and gas....................................... 13,628 11,504
Discontinued operations........................... 6,759 20,994
Other............................................. 36,958 29,355
------------- ------------
$ 191,431 $ 202,120
============= ============
Intersegment sales are insignificant. Other identifiable assets are
primarily corporate cash, accounts receivable, and properties not identified
with any specific segment of the Company's business. All sales by the Company
occurred in the United States.
Segment operating earnings reflect revenues net of operating costs and
depreciation,
-13-
depletion and amortization. Segment earnings reconcile to earnings from
continuing operations before income taxes and cumulative effect of accounting
change, as follows (IN THOUSANDS):
Nine months ended Three months ended
September 30, September 30,
----------------------- -----------------------
2003 2002 2003 2002
---------- ---------- ---------- ----------
Segment operating earnings........................... $ 13,077 $ 10,003 $ 2,841 $ 1,594
General and administrative........................... (4,647) (5,608) (1,640) (1,454)
---------- ---------- ---------- ----------
Operating earnings.............................. 8,430 4,395 1,201 140
Interest income...................................... 333 80 63 34
Interest expense..................................... (106) (93) (44) (36)
---------- ---------- ---------- ----------
Earnings from continuing operations before
income taxes, and cumulative effect
of accounting change............................ $ 8,657 $ 4,382 $ 1,220 $ 138
========== ========== ========== ==========
Note 5 - Marketing Joint Venture
Commencing in May 2000, the Company entered into a joint venture
arrangement with a third party for the purpose of purchasing, distributing and
marketing crude oil in the offshore Gulf of Mexico region. The intent behind the
joint venture was to combine the Company's marketing expertise with stronger
financial and credit support from the co-venture participant. The venture
operated as Williams-Gulfmark Energy Company pursuant to the terms of a joint
venture agreement. The Company held a 50 percent interest in the 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.
Effective November 1, 2001, the joint venture participants agreed to
dissolve the venture pursuant to the terms of a joint venture dissolution
agreement. As part of the consideration for terminating the joint venture, the
Company was to receive a monthly per barrel fee to be paid by the former joint
venture co-participant for a period of sixty months on certain barrels purchased
by the participant in the offshore Gulf of Mexico region. Included in 2002
marketing segment revenues is $2,433,000 of pre-tax earnings derived from this
fee. While the co-venture participant willingly paid this fee through January
31, 2002 activity, effective with February 2002 business, the participant
notified the Company of its intent to withhold the fee until they audited the
previous joint venture activity. Subsequently, due primarily to credit
constraints, the co-participant substantially curtailed and ultimately ceased
its purchase of crude oil in the affected region.
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. 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.
-14-
Note 6 - Transactions with Affiliates
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, these partnerships as well as Sakdril, Inc. ("Sakdril"), a wholly
owned subsidiary of KSA Industries, Inc., a major stockholder of the Company,
and Mr. Adams individually 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 affiliate transactions tend to result
after the Company has first identified oil and gas prospects of interest. Due to
capital budgeting constraints, typically the available dollar commitment to
participate in such transactions is greater than the amount management is
comfortable putting at risk. In such event, the Company first determines the
percentage of the transaction it wants to obtain, which allows a related party
to participate in the investment to the extent there is excess available. Such
affiliate transactions are individually reviewed and approved by a committee of
independent directors on the Company's Board of Directors. As of September 30,
2003, the Company owed a net total of $614,000 to these affiliates. The amount
due was comprised of $796,000 of oil and gas revenues to be disbursed to such
working interest owners, net of $182,000 of joint interest billings due from
such joint interest owners. In connection with the operation of certain oil and
gas properties, the Company also charges such affiliates for administrative
overhead primarily as prescribed by the Council of Petroleum Accountants Society
("COPAS") Bulletin 5. Such overhead recoveries totaled $78,000 during the nine
months of 2003.
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 may also enter into certain transactions in the normal
course of business with other affiliated entities. These transactions with
affiliated companies are on the same terms as those prevailing at the time for
comparable transactions with unrelated entities.
Note 7 - Commitments and Contingencies
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. This amount was adjusted downward by the State in August 2002 to $3.4
million plus penalties and interest. CJC protested this 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. 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 included as an expense
in third quarter 2003 results.
-15-
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 believes it is in compliance with such rules
and regulations.
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 or other items of general liability as would be
typical for the industry. Except as disclosed herein, management of the Company
is presently unaware of any claims against the Company that are either outside
the scope of insurance coverage, or that may exceed the level of insurance
coverage, and could potentially represent a material adverse effect on the
Company's financial position or results of operations.
Note 8 - Guarantees
Pursuant to arranging operating lease financing for truck tractors and
tank trailers, individual subsidiaries of the Company may guarantee the lessor a
minimum residual sales value upon the expiration of a lease and sale of the
underlying equipment. Aggregate guaranteed residual values for tractors and
trailers under operating leases as of September 30, 2003 are as follows (IN
THOUSANDS):
2003 2004 2005 2006 Total
---- ---- ---- ---- -----
Lease residual values.............. $ 698 $ 551 $ 763 $ 150 $ 2,162
Historically, the market value of the tractor/trailer equipment at the
end of the lease term has always exceeded the guaranteed residual value.
Therefore, the Company and its subsidiaries have never been required to fund any
shortfall in value. Presently, neither the Company nor any of its subsidiaries
have any other types of guarantees outstanding that in the future would require
liability recognition.
Adams Resources & Energy, Inc. frequently issues parent guarantees of
commitments resulting from the ongoing activities of its subsidiary companies.
The guarantees generally result as incident to subsidiary commodity purchase
obligation, subsidiary lease commitments and subsidiary bank debt. The nature of
such guarantees is to guarantee the performance of the subsidiary companies in
meeting their respective underlying obligations. Except for operating lease
commitments, all such underlying obligations are recorded on the books of the
subsidiary companies and are included in the consolidated financial statements
included herein. Therefore, none of such obligations is recorded again on the
books of the parent. The parent would only be called upon to perform under the
guarantee in the event of a payment default by the applicable subsidiary
company. In satisfying such obligations, the parent would first look to the
assets of the defaulting subsidiary company. As of September 30, 2003, the
amount of parental guaranteed obligations are approximately as follows (IN
THOUSANDS):
-16-
2003 2004 2005 2006 Thereafter Total
---- ---- ---- ---- ---------- -----
Bank debt............................... $ - $ 1,434 $ 5,738 $ 4,303 $ - $ 11,475
Operating leases........................ 988 2,674 1,133 420 456 5,671
Lease residual values................... 698 551 763 150 - 2,162
Commodity purchases..................... 2,211 - - - - 2,211
Letters of credit....................... 40,400 - - - - 40,400
---------- --------- ----------- -------- ---------- ----------
$ 44,297 $ 4,659 $ 7,634 $ 4,873 $ 456 $ 61,919
========== ========= =========== ======== ========== ==========
Note 9 - Restatement of Revenues and Costs and Expenses
As discussed in Notes (2) and (3) of Notes to Unaudited Consolidated
Financial Statements, the presentation of marketing segment Revenues and Costs
and Expenses was changed for 2002 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 for
these changes (IN THOUSANDS):
Nine Months Ended Three Months Ended
September 30, 2002 September 30, 2002
--------------------------- ------------------------
Currently Previously Currently Previously
Reported Reported Reported Reported
--------- ---------- -------- ----------
Revenues:
Marketing............................................... $ 1,343,989 $ 1,777,899 $ 492,150 $ 614,398
Costs and Expenses:
Marketing............................................... $ 1,334,344 $ 1,769,814 $ 490,540 $ 612,422
Operating earnings........................................ $ 4,395 $ 2,097 $ 140 $ 248
Earnings before income tax................................ $ 4,382 $ 2,081 $ 138 $ 274
Earnings (loss) from discontinued operations, net......... $ (1,427) $ - $ 84 $ -
Net earnings.............................................. $ 1,339 $ 1,339 $ 189 $ 189
As discussed in Note (3) of Notes to Unaudited 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
Accrued and other liabilities............................. $ 3,950 $ 4,066
Risk management payable................................... $ 2,004 $ 6,452
Current liabilities of discontinued operation............. $ 5,030 $ -
Risk management liabilities............................... $ - $ 322
-17-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Results of Operations
- Marketing
Marketing division revenues, operating earnings and depreciation are
presented as follows (IN THOUSANDS):
Nine Months Ended Three Months Ended
September 30, September 30,
--------------------------------- ---------------------------
2003 2002 2003 2002
---- ---- ---- ----
Revenues...................... $ 1,266,362 $ 1,343,989 $ 388,859 $ 492,150
Operating earnings ........... $ 9,705 $ 8,359 $ 2,444 $ 1,266
Depreciation.................. $ 1,044 $ 1,286 $ 326 $ 344
Supplemental volume and price information is as follows:
Nine Months Ended Three Months Ended
September 30, September 30,
-------------------------- ------------------------
2003 2002 2003 2002
---------- ----------- ---------- ----------
Wellhead Purchases - Per day (1)
Crude oil - barrels................. 87,000 105,600 80,000 96,700
Natural gas - mmbtu................. 316,000 530,000 306,000 422,000
Average Purchase Price
Crude oil - per barrel.............. $ 29.95 $ 23.49 $ 29.05 $ 26.59
Natural gas - per mmbtu............. $ 5.47 $ 2.89 $ 4.74 $ 3.05
- -----------------------
(1) Reflects the volume purchased from third parties at the wellhead level.
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.
-18-
Gross revenues for the marketing operation were relatively flat for the
first nine months of 2003 compared to 2002 as crude oil price increases were
substantially offset by reductions in crude oil purchase volumes. For the
comparative third quarter of 2003, marketing revenues decreased by $103 million
or 21 percent despite overall higher crude oil prices. The current quarter
revenue reduction reflects the Company's continuing efforts to simplify its
business model and reduce the volume of crude oil trading activity.
In the prior year, marketing operating earnings included fee income
totaling $2,433,000, of which none was attributable to the prior year third
quarter. Previously, the Company earned a fee on crude oil purchases by a third
party in the offshore Gulf of Mexico pursuant to the dissolution of a marketing
joint venture. Such fee did not recur after June 2002. See Note (5) of the Notes
to Unaudited Consolidated Financial Statements. Excluding the fee income, during
the comparative periods, operating earnings were as follows (IN THOUSANDS):
2003 2002 Increase
---- ---- --------
Nine month period ended September 30................. $ 9,705 $ 5,926 $ 3,779
Three month period ended September 30................ $ 2,444 $ 1,266 $ 1,178
The 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 values 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. However, relative to the second quarter of 2003 for this
segment, third quarter operating earnings are reduced by 25% from the $3,284,000
level experienced in the previous quarter. While remaining stable, third quarter
2003 operating margins for crude oil were reduced from the previous quarter as
wellhead purchase values approached parity with the end use refining markets.
The more recent trend appears to be holding into the fourth quarter of 2003.
- Transportation
Transportation revenues, operating earnings and depreciation are as
follows (IN THOUSANDS):
Nine Months Ended Increase Three Months Ended Increase
September 30, (Decrease) September 30, (Decrease)
----------------------- ---------- ------------------------ ----------
2003 2002 2003 2002
---- ---- ---- ----
Revenues......................... $ 26,574 $ 27,308 (3)% $ 8,149 $ 9,426 (14)%
Operating earnings (loss)........ $ 667 $ 1,805 (63)% $ (463) $ 518 (189)%
Depreciation..................... $ 1,533 $ 1,276 20% $ 505 $ 526 (4)%
Demand for the Company's transportation services was reduced during the
current periods, most notably in the third quarter. Due to the fixed cost
component of the trucking operation, as revenues are reduced, operating earnings
decline at a faster rate. Operating earnings were further reduced in 2003
because of higher diesel fuel prices and insurance cost
-19-
increase. Fuel costs increased by $286,000, or 11 percent, for the comparative
nine-month period, consistent with higher average crude oil prices. Insurance
expense increased by $304,000, or 11 percent, consistent with the general trend
of escalating insurance costs. The Company's tank truck operation is highly
dependent on demand from the petrochemical sector of the United States economy.
With the present situation of elevated natural gas prices, chemical
manufacturers have generally reduced their activities. This situation serves to
suppress ongoing demand for the Company's transportation services.
- Oil and Gas
Oil and gas division revenues and operating earnings are primarily a
function of crude oil and natural gas prices and volumes. Comparative amounts
for revenues, operating earnings and depreciation and depletion are as follows
(IN THOUSANDS):
Nine Months Ended Three Months Ended
September 30, September 30,
---------------------- ----------------------
2003 2002 2003 2002
---- ---- ---- ----
Revenues........................... $ 6,564 $ 3,047 $ 2,235 $ 1,144
Operating earnings (loss).......... $ 2,705 $ (161) $ 860 $ (190)
Depreciation and depletion........ $ 1,374 $ 1,200 $ 486 $ 600
Comparative volume and price information is a follows:
Nine Months Ended Three Months Ended
September 30, September 30,
------------------------ ------------------------
2003 2002 2003 2002
---- ---- ---- ----
Crude oil
Volume - barrels............................ 47,700 39,600 19,000 13,200
Average price per barrel.................... $ 31.18 $ 24.52 $ 31.41 $ 24.50
Natural gas
Volume - mcf................................ 931,500 710,000 293,100 262,000
Average price per mcf....................... $ 5.41 $ 2.73 $ 5.52 $ 3.10
As shown above, improved oil and gas division revenues and operating
earnings 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 the first
nine months of 2003, the Company participated in the drilling of twenty-three
wells. Twelve wells were successfully completed with six dry holes and five
presently in process. 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.
Preliminary estimates of crude oil and natural gas reserves, resulting
from exploration
-20-
efforts in 2003, were made by the Company's in-house staff. These estimates
indicate reserve additions totaling 99,000 barrels of oil and 1,690,000 mcf of
gas from these results. With the Company's production for all of 2002 being
55,000 barrels of oil and 1,047,000 mcf of gas, the current estimated reserve
additions represent more than a complete replacement of prior year production.
For the remainder of 2003, five additional wells are planned for Fort
Bend County, Texas following the success of seven wells already drilled in the
area this year. The Company's Austin Chalk program will also continue following
three successes thus far this year. Three wells are slated to drill this year in
the Chalk formation with two additional wells under consideration.
The Company recently completed shooting a 95 square mile 3-D survey in
Calcasieu Parish, Louisiana. This project is in a prolific area and is expected
to yield numerous drilling prospects. The data is currently being processed and
is expected to begin yielding drilling opportunities in early 2004. Fieldwork on
a second large 3-D survey in Alabama began in October of this year. This survey
is expected to confirm prospect leads identified with 2-D seismic data. An
estimated $400,000 of seismic expenditures is estimated to be incurred and
expensed, during the fourth quarter of 2003 for these projects.
- General and administrative
General and administrative expenses decreased $961,000, or 17 percent,
in the comparative nine months of 2003. This savings resulted primarily because
$536,000 was incurred in the first quarter of 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 (5) of the Unaudited Notes to Consolidated
Financial Statements.
- Discontinued operations
The Company's management has 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
$2,862,000 during the nine month period ended September 30, 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 January, February and March 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 the losses sustained
and the desire to reduce working capital requirements, management decided to
exit this region and type of account.
In June of 2003, two of the Company's New England region customers
filed for Chapter 11 bankruptcy. As a result, the Company incurred a $475,000
charge to discontinued operation earnings during the second quarter of 2003 in
the form of a provision for bad debts. Presently,
-21-
the Company has ceased entering into New England region contracts. Existing
contract requirements are being met in accordance with their original terms.
Expiring contracts are not being renewed and substantially all contracts expire
prior to December 31, 2003. With the reduction in volume requirements, the
Company does not anticipate further significant losses from this operation. See
Note (3) of Notes to Unaudited Consolidated Financial Statements.
- Outlook
Consistent with recent increased economic activity for the United
States, beginning in October 2003, demand for the Company's petrochemical
trucking services improved. If demand remains strong, a rebound to profitability
for the transportation segment will result. Near term profitability from
marketing operations is more difficult to assess. The marketplace for crude oil
weakened significantly in September 2003 with some subsequent improvement. In
any event, marketing margins are expected to remain narrow, constricting
profitability. For exploration and production, natural gas prices are holding
strong in the $4 to $5 per unit range, a positive development. Coupled with
recent volume increases, continued positive results are anticipated and, overall
for the Company, further earnings strength is anticipated.
Liquidity and Capital Resources
During the first nine months of 2003, net cash provided by operating
activities totaled $12,609,000. The Company invested $5,572,000 in capital
expenditures including $1,651,000 toward marketing operations, $730,000 in
transportation operations and $3,191,000 in oil and gas drilling activities. The
remaining $7 million of cash flow from operating activities was used to boost
cash reserves and generally improve liquidity.
Included in marketing capital expenditures, the Company invested
$700,000 to purchase certain equipment, contracts and a non-compete clause
associated with a competitor's withdrawal from the purchase of crude oil in the
state of Michigan. This transaction establishes the Company as the dominant
purchaser of crude oil in a region that is not likely to attract new
competition. For the remainder of 2003, the Company anticipates spending
approximately $2.5 million on oil and gas exploration projects including
$900,000 of seismic expense. Further, approximately $700,000 will be expended on
tractor and trailer equipment additions as present lease financing arrangements
mature.
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 September 30, 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
$4,000,000 as of September 30, 2003. The line of credit loans are scheduled to
expire on October 29, 2004, with the then present balance outstanding converting
to a term loan payable in 8 equal quarterly installments. As of September 30,
2003, bank debt outstanding under the Company's two revolving credit facilities
totaled $11,475,000.
The Company's Gulfmark Energy, Inc. subsidiary maintains a separate
banking
-22-
relationship with BNP Paribas in order to support its crude oil purchasing
activities. In addition to providing up to $40 million in letters of credit, the
facility also finances up to $6 million of crude oil inventory and certain
accounts receivable associated with crude oil sales. Such financing is provided
on a demand note basis with interest at the bank's prime rate plus 1 percent. As
of September 30, 2003, the Company had $260,000 of eligible borrowing capacity
under this facility. No working capital advances were outstanding as of
September 30, 2003. Letters of credit outstanding under this facility totaled
approximately $30 million as of September 30, 2003. BNP Paribas has the right to
discontinue the issuance of letters of credit under this facility without prior
notification to the Company.
The Company's Adams Resources Marketing subsidiary also maintains a
separate banking relationship with BNP Paribas in order to support its natural
gas purchasing activities. In addition to providing up to $25 million in letters
of credit, the facility finances up to $4 million of general working capital
needs on a demand note basis. No working capital advances were outstanding under
this facility as of September 30, 2003. Letters of credit outstanding under this
facility totaled approximately $10.4 million as of September 30, 2003. Under
this facility, BNP Paribas has the right to discontinue the issuance of letters
of credit without prior notification to the Company.
Refer also to the "Liquidity and Capital Resources" section of the
Company's Annual Report on Form 10-K for the year ended December 31, 2002 for
additional discussion of the Company's banking relationships and other matters.
Critical Accounting Policies and Use of Estimates
- Fair Value Accounting
As an integral part of its marketing operation, the Company enters into
certain forward commodity contracts that are required to be recorded at fair
value in accordance with Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities" and related
accounting pronouncements. Management believes this required accounting, known
as mark-to-market accounting, creates variations in reported earnings and the
reported earnings trend. Under mark-to-market accounting, significant levels of
earnings are recognized in the period of contract initiation rather than the
period when the service is provided and title passes from supplier to customer.
As it affects the Company's operation, management believes mark-to-market
accounting impacts reported earnings and the presentation of financial condition
in three important ways.
1. Gross margins, derived from certain aspects of the
Company's ongoing business, are front-ended into the period in
which contracts are executed. While there is no particular
pattern to the timing of contract execution, it does tend to
occur in clusters during those periods of time when the
Company's natural gas customers perceive prices to be
advantageous. Meanwhile, personnel and other costs associated
with servicing accounts are expensed as incurred during the
period of physical product flow and title passage.
2. Mark-to-market earnings are calculated based on
stated contract volumes. One of
-23-
the significant risks associated with the Company's business
is to convert stated contract or planned volumes into actual
physical commodity movement volumes without a loss of margin.
Again the planned profit from such commodity contracts is
bunched and front-ended into one period while the risk of loss
associated with the difference between actual versus planned
production or usage of oil and gas 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 noted 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 12 months in duration.
However, the reader is cautioned to develop a full understanding of how fair
value or mark-to-market accounting creates differing reported results relative
to those otherwise presented under conventional accrual accounting.
- Trade Accounts
Accounts receivable and accounts payable typically represent the single
most significant assets and liabilities of the Company. Particularly within the
Company's energy marketing and oil and gas exploration and production
operations, there is a high degree of interdependence with and reliance upon
third parties, (including transaction counterparties) to provide adequate
information for the proper recording of amounts receivable or payable.
Substantially all such third parties are larger firms providing the Company with
the source documents for recording trade activity. It is commonplace for these
entities to retroactively adjust or correct such documents. This typically
requires the Company to either absorb, benefit from, or pass along such
corrections to another third party.
Due to (a) the volume of transactions, (b) the complexity of
transactions and (c) the high degree of interdependence with third parties, this
is a difficult area to control and manage. The Company manages this process by
participating in a monthly settlement process with each of its counterparties.
Ongoing account balances are monitored monthly and the Company attempts to gain
the cooperation of such counterparties to reconcile outstanding balances. The
Company also places great emphasis on collecting cash balances due and paying
only bonafide properly supported claims. In addition, the Company maintains and
monitors its bad debt allowance. A degree of risk remains, however, simply due
to the custom and practices of the industry.
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- Oil and Gas Reserve Estimate
The value of capitalized costs of oil and gas exploration and
production related assets are dependent on underlying oil and gas reserve
estimates. Reserve estimates are based on many judgmental 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. However, estimated oil and gas reserve quantities
are the basis for the rate of amortization under the Company 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
would be typical for the industry. In addition, the Company has extensive
operations that must comply with a wide variety of tax laws, environmental laws
and labor laws, among others. Should an incident occur, management would
evaluate the claim based on its nature, the facts and circumstances and the
applicability of insurance coverage. To the extent management believes that such
event may impact the financial condition of the Company, management will
estimate the monetary value of the claim and make appropriate accruals or
disclosure as provided in the guidelines of Statement of Financial Accounting
Standards No. 5.
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
-25-
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 September 30, 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 reclassifications necessary would
not impact the Company's cash flows or results of operations.
Quantitative and Qualitative Disclosures about Market Risk
The Company is exposed to market risk, including adverse changes in
interest rates and commodity prices.
- Interest Rate Risk
Total long-term debt at September 30, 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 September 30, 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 nine month period ended September 30, 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 three years in duration. The
Company monitors all commitments, positions and endeavors to maintain a balanced
portfolio.
Certain forward contracts are recorded at fair value, depending on
management's assessments of numerous accounting standards and positions that
comply with generally accepted accounting principles. The undiscounted fair
value of such contracts is reflected on the Company's balance sheet as risk
management assets and liabilities. The revaluation of such contracts is
recognized on a net basis in the Company's results of operations. Current market
price quotes from actively traded liquid markets are used in all cases to
determine the contracts' undiscounted fair value. Regarding net risk management
assets, 100 percent of presented values as of September 30, 2003 and December
31, 2002 were based on readily available market
-26-
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 market prices at September 30, 2003 is $588,000, all of which will be
received during the remainder of 2003. The estimated future cash inflow
approximates the net fair value recorded in the Company's risk management assets
and liabilities.
The following table illustrates the factors that impacted the change in
the net value of the Company's risk management assets and liabilities for the
nine months ended September 30, 2003 (IN THOUSANDS)
2003
----
Net fair value on January 1,........................................... $ (70)
Activity during 2003
- Net cash paid on settled contracts.............................. 206
- Net realized loss from prior years' contracts................... (136)
- Net unrealized gain from prior years' contracts................. 320
- Net unrealized gain from current year contracts ................ 399
- Net unrealized loss from current year contracts................. (131)
--------
Net fair value on September 30, ....................................... $ 588
========
Historically, prices received for oil and gas production have been
volatile and unpredictable. Price volatility is expected to continue. From
January 1, 2003 through September 30, 2003, natural gas price realizations
ranged from a monthly low of $4.16 per mmbtu to a monthly high of $25.00 per
mmbtu. Oil prices ranged from a low of $24.58 per barrel to a high of $36.14 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 $43,000 for the nine-month period
ended September 30, 2003.
Forward-Looking Statements--Safe Harbor Provisions
This report for the period ended September 30, 2003 contains certain
forward-looking statements intended to be covered by the safe harbors provided
under Federal securities law and regulation. To the extent such statements are
not recitations of historical fact, forward-looking statements involve risks and
uncertainties. In particular, statements under the captions (a) Management's
Discussion and Analysis of Financial Condition and Results of Operations, (b)
Liquidity and Capital Resources, (c) Critical Accounting Policies and Use of
Estimates, (d) Quantitative and Qualitative Disclosures about Market Risk, among
others, contain forward-looking statements. Where the Company expresses an
expectation or belief to future results or events, such expression is made in
good faith and believed to have a reasonable basis in fact. However, there can
be no assurance that such expectation or belief will actually result or be
achieved.
A number of factors could cause actual results or events to differ
materially from those anticipated. Such factors include, among others, (a)
general economic conditions, (b) fluctuations in hydrocarbon prices and margins,
(c) variations between crude oil and natural gas contract volumes and actual
delivery volumes, (d) unanticipated environmental liabilities or
-27-
regulatory changes, (e) counterparty credit default, (f) inability to obtain
bank and/or trade credit support, (g) availability and cost of insurance, (h)
changes in tax laws, (i) the availability of capital, (j) changes in
regulations, (k) results of current items of litigation, (l) uninsured items of
litigation or losses, (m) uncertainty in reserve estimates and cash flows, (n)
ability to replace oil and gas reserves, (o) security issues related to drivers
and terminal facilities (p) commodity price volatility and (q) successful
completion of drilling activity.
Disclosure 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 third
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 its Chief Executive Officer and Chief
Financial Officer, of the effectiveness of the design and operation of our
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.
-28-
PART II. OTHER INFORMATION
Item 1. - See Notes (5) and (7) of Notes to Unaudited Consolidated Financial
Statements
Item 2. - None
Item 3. - None
Item 4. - None
Item 6. Exhibits and Reports on Form 8-K
a. Exhibits
31.1 Certification Pursuant to 17 CFR 240.13a-15(e), As Adopted
Pursuant to Section 302 of the Sarbarnes-Oxley Act of 2002
31.2 Certification Pursuant to 17 CFR 240.13a-15(e), 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 I.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 August 13, 2003 as furnished on August 13,
2003 to announce earnings for the second quarter ended June 30, 2003.
-29-
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
ADAMS RESOURCES & ENERGY, INC.
(Registrant)
Date: November 13, 2003 By /s/ K. S. Adams, Jr.
--------------------------------
K. S. Adams, Jr.
Chief Executive Officer
By /s/ Richard B. Abshire
--------------------------------
Richard B. Abshire
Chief Financial Officer
-30-
EXHIBIT INDEX
Exhibit
Number Description
- ------- -----------
31.1 Certification Pursuant to 17 CFR 240.13a-15(e), As Adopted
Pursuant to Section 302 of the Sarbarnes-Oxley Act of 2002
31.3 Certification Pursuant to 17 CFR 240.13a-15(e), As Adopted
Pursuant to Section 302 of the Sarbarnes-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
32.2 Certification Pursuant To 18 I.S.C. Section 1350, As Adopted
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
-31-