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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 June 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 August 4,
2003.
ADAMS RESOURCES & ENERGY, INC. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENT OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Six Months Ended Three Months Ended
June 30, June 30,
--------------------------- ----------------------------
2003 2002 2003 2002
------------- ------------ ------------- -------------
REVENUES:
Marketing........................................... $ 877,503 $ 851,839 $ 414,947 $ 482,232
Transportation...................................... 18,425 17,882 9,415 9,713
Oil and gas......................................... 4,329 1,903 2,605 1,044
------------- ------------ ------------- -------------
900,257 871,624 426,967 492,989
------------- ------------ ------------- -------------
COSTS AND EXPENSES:
Marketing........................................... 869,524 843,804 411,386 479,802
Transportation...................................... 16,267 15,845 8,256 8,529
Oil and gas......................................... 1,596 1,274 1,084 660
General and administrative.......................... 3,007 4,154 1,566 1,965
Depreciation, depletion and amortization............ 2,634 2,292 1,342 1,183
------------- ------------ ------------- -------------
893,028 867,369 423,634 492,139
------------- ------------ ------------- -------------
Operating earnings..................................... 7,229 4,255 3,333 850
Other income (expense):
Interest income .................................... 270 46 115 33
Interest expense.................................... (62) (57) (29) (6)
------------- ------------ ------------- -------------
Earnings from continuing operations before
income taxes and cumulative effect of
accounting change................................... 7,437 4,244 3,419 877
Income tax provision................................... 2,859 1,583 1,334 321
------------- ------------ ------------- -------------
Earnings from continuing operations.................... 4,578 2,661 2,085 556
Loss from discontinued operation, net of tax
benefit of $1,682, $926, $424 and
$1, respectively................................... (2,708) (1,511) (655) (1)
------------- ----------- ------------- -------------
Earnings before cumulative effect of
accounting change................................... 1,870 1,150 1,430 555
Cumulative effect of accounting change,
net of tax of $57................................... (92) - - -
------------- ------------ ------------- -------------
Net earnings........................................... $ 1,778 $ 1,150 $ 1,430 $ 555
============= ============ ============= =============
EARNINGS (LOSS) PER SHARE:
From continuing operations.......................... $ 1.08 $ .63 $ .49 $ .13
From discontinued operation......................... (.64) (.36) (.15) -
Cumulative effect of accounting change.............. (.02) - - -
------------- ------------ ------------- -------------
Basic and diluted net earnings
per common share.................................. $ .42 $ .27 $ .34 $ .13
============= ============ ============= =============
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)
June 30, December 31,
2003 2002
------------ ---------------
ASSETS
Current assets:
Cash and cash equivalents................................... $ 33,890 $ 27,262
Accounts receivable, net.................................... 131,943 120,036
Inventories................................................. 7,018 5,645
Risk management receivables................................. 4,621 1,934
Income tax receivable....................................... 192 382
Prepayments................................................. 7,282 3,147
Current assets of discontinued operation.................... 9,786 20,994
------------ ---------------
Total current assets.......................... 194,732 179,400
------------ ---------------
Property and equipment........................................ 79,145 75,419
Less - accumulated depreciation,
depletion and amortization........................... (55,329) (53,115)
------------- ---------------
23,816 22,304
------------ ---------------
Other assets.................................................. 416 416
------------ ---------------
$ 218,964 $ 202,120
============ ===============
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable............................................ $ 151,834 $ 137,100
Risk management payables.................................... 3,762 2,004
Accrued and other liabilities............................... 4,135 3,950
Current liabilities of discontinued operation............... 2,736 5,030
------------ ---------------
Total current liabilities..................... 162,467 148,084
Long-term debt................................................ 11,475 11,475
Deferred taxes and other...................................... 3,144 2,461
------------ ---------------
177,086 162,020
------------ ---------------
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 .......................................... 29,763 27,985
------------ ---------------
Total shareholders' equity ................... 41,878 40,100
------------ ---------------
$ 218,964 $ 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)
Six Months Ended
June 30,
----------------------
2003 2002
-------- --------
CASH PROVIDED BY OPERATIONS:
Earnings from continuing operations .................. $ 4,578 $ 2,661
Adjustments to reconcile net earnings to net
cash provided by operating activities -
Depreciation, depletion and amortization ........... 2,634 2,292
Risk management activities ......................... (929) 2,083
Gains on property sales ............................ (98) (269)
Write-off of dry hole costs ........................ - 245
Other, net ......................................... 469 6
Changes in operating assets and liabilities -
Decrease (increase) in accounts receivable, net .... (11,907) (17,627)
Decrease (increase) in inventories ................. (1,373) 1,858
Decrease (increase) in income tax receivable ....... 190 552
Decrease (increase) in prepayments ................. (4,135) 4,702
Increase (decrease) in accounts payable ............ 14,734 667
Increase (decrease) in accrued and other liabilities 185 (716)
-------- --------
Net cash provided by (used in) continuing operations ... 4,348 (3,546)
Net cash provided by discontinued operation ............ 6,206 6,977
-------- --------
Net cash provided by operating activities .............. 10,554 3,431
-------- --------
INVESTING ACTIVITIES:
Property and equipment additions ..................... (4,044) (1,499)
Proceeds from property sales ......................... 118 280
-------- --------
Net cash used in investing activities .............. (3,926) (1,219)
-------- --------
FINANCING ACTIVITIES:
Repayment of debt .................................. - (1,000)
-------- --------
Net cash used in financing activities .............. - (1,000)
-------- --------
Increase in cash and cash equivalents .................. 6,628 1,212
Cash at beginning of period ............................ 27,262 14,177
-------- --------
Cash at end of period .................................. $ 33,890 $ 15,389
======== ========
Supplemental disclosure of cash flow information:
Interest paid during the period .................... $ 26 $ 88
======== ========
Income taxes paid during the period ................ $ 811 $ 61
======== ========
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 June 30, 2003 and December 31, 2002 and its results of
operations for the six months and three months ended June 30, 2003 and 2002 and
its cash flows for the six months ended June 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 June 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):
June 30, December 31,
2003 2002
-------- ------------
Crude oil ............ $3,870 $3,062
Petroleum products ... 2,525 1,919
Materials and supplies 623 664
------ ------
$7,018 $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 six month and the three month periods
ended June 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. In
the latter case, 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 June 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 June 30, 2003 is $859,000,
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 June 30, 2003. (IN THOUSANDS):
2003
-----------
Net fair value on January 1,............................................... $ (70)
Activity during 2003
- Net cash paid on settled contracts .................................... 316
- Net realized (loss) from prior years' contracts ...................... (163)
- Net unrealized gain from prior years' contracts ...................... 322
- Net unrealized gain from current year contracts ...................... 454
-----------
Net fair value on June 30,............................................... $ 859
===========
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 will adopt SFAS No.
149 on a prospective basis at its effective date of July 1, 2003. Under
Statement 133 and related amendments and interpretations, volumes with physical
delivery that were net scheduled for delivery purposes and where gross payments
were made and credit risk was assumed were designated for the normal purchase
and sale exemption and were exempt from derivative accounting treatment. SFAS
No. 149 eliminates this exemption if net scheduling occurs. Therefore, certain
of the Company's contracts representing a small volume will be required to be
treated as derivatives in the future and marked to market each period.
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 is
required to adopt SFAS No. 150 effective July 1, 2003. The adoption of this
statement is not expected to 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
$8.3 million and intangible assets would have increased by a like amount at June
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.
-10-
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 had negative operating margins of $4,390,000 and
$2,437,000 and had after tax losses totaling $2,708,000 and $1,511,000 during
the six month periods ended June 30, 2003 and 2002, respectively. For the three
month periods ended June 30, 2003 and 2002, this unit had negative operating
margins of $1,079,000 and $2,000, 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. The winter of 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 divested 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):
June 30, December 31,
2003 2002
-------- ------------
Accounts receivable, net .......... $ 6,656 $13,214
Risk management assets ............ 2,783 6,632
Inventory ......................... 120 946
Prepaid deposit ................... 227 202
------- -------
Total Assets ............. $ 9,786 $20,994
======= =======
Accounts payable .................. $ 93 $ 144
Accrued liabilities ............... 29 115
Risk management liabilities ....... 2,614 4,771
------- -------
Total Liabilities ........ $ 2,736 $ 5,030
======= =======
-11-
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 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 all
intangible assets such as customer lists, industry
specific accounting software and experienced sales
and back-office personnel.
As consideration for the intangible assets, the Company anticipates
that an interested third party would hire the Company's personnel and assume
associated office operating lease obligations. 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. The final stages of negotiation for implementing this plan are in
process with one such third party and management anticipates a final signed
agreement will be completed during the third quarter of 2003.
For comparative purposes, marketing segment revenues and costs and
expenses have been restated for the six months ended June 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-
Depreci-
ation,
Depletion Property
Segment and and
Operating Amorti- Equipment
Revenues Earnings zation Additions
------------- ------------- ----------- -----------
For the six months ended
June 30, 2003
Marketing........................ $ 877,503 $ 7,261 $ 718 $ 724
Transportation................... 18,425 1,130 1,028 595
Oil and gas...................... 4,329 1,845 888 2,725
------------- ------------- ----------- -----------
$ 900,257 $ 10,236 $ 2,634 $ 4,044
============= ============= =========== ===========
For the six months ended
June 30, 2002
Marketing........................ $ 851,839 $ 7,093 $ 942 $ 23
Transportation................... 17,882 1,287 750 462
Oil and gas...................... 1,903 29 600 1,014
------------- ------------- ----------- -----------
$ 871,624 $ 8,409 $ 2,292 $ 1,499
============= ============= =========== ===========
For the three months ended
June 30, 2003
Marketing........................ $ 414,947 $ 3,284 $ 277 $ 634
Transportation................... 9,415 631 528 66
Oil and gas...................... 2,605 984 537 1,583
------------- ------------- ----------- -----------
$ 426,967 $ 4,899 $ 1,342 $ 2,283
============= ============= =========== ===========
For the three months ended
June 30, 2002
Marketing........................ $ 482,232 $ 2,004 $ 426 $ 3
Transportation................... 9,713 812 372 444
Oil and gas...................... 1,044 (1) 385 -
------------- ------------- ----------- -----------
$ 492,989 $ 2,815 $ 1,183 $ 447
============= ============= =========== ===========
Identifiable assets by industry segment are as follows (IN THOUSANDS):
June 30, December 31,
2003 2002
------------ ------------
Marketing......................................... $ 143,439 $ 124,336
Transportation.................................... 14,356 15,931
Oil and gas....................................... 14,143 11,504
Discontinued operations........................... 9,786 20,994
Other............................................. 37,240 29,355
------------ ------------
$ 218,964 $ 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.
-13-
Segment operating earnings reflect revenues net of operating costs and
depreciation, depletion and amortization. Segment earnings reconcile to earnings
from continuing operations before income taxes and cumulative effect of
accounting change, as follows (IN THOUSANDS):
Six months ended Three months ended
June 30, June 30,
----------------------- -----------------------
2003 2002 2003 2002
---------- ---------- ---------- ----------
Segment operating earnings........................... $ 10,236 $ 8,409 $ 4,899 $ 2,815
General and administrative........................... (3,007) (4,154) (1,566) (1,965)
---------- ---------- ---------- ----------
Operating earnings.............................. 7,229 4,255 3,333 850
Interest income...................................... 270 46 115 33
Interest expense..................................... (62) (57) (29) (6)
---------- ---------- ---------- ----------
Earnings from continuing operations before
income taxes, and cumulative effect
of accounting change............................ $ 7,437 $ 4,244 $ 3,419 $ 877
========== ========== ========== ==========
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 June 30, 2003,
the Company owed a total of $725,000 to these affiliates. The amount due was
comprised of $481,000 of oil and gas revenues to be disbursed to such working
interest owners, plus $244,000 of joint interest credits due to 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 $52,000 during the first
half 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 has protested this assessment and has
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. Management intends to vigorously defend CJC in
this matter and believes that it will not ultimately have a significant adverse
effect on the Company's financial position or results of operations.
-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 June 30, 2003 are as follows (IN
THOUSANDS):
2003 2004 2005 2006 Total
--------- -------- -------- -------- ----------
Lease residual values..................... $ 698 $ 551 $ 763 $ 150 $ 2,162
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 June 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 ........... 1,977 2,674 1,133 420 456 6,660
Lease residual values ...... 698 551 763 150 - 2,162
Commodity purchases ........ 23,886 - - - - 23,886
Letters of credit .......... 41,300 - - - - 41,300
------- ------- ------- ------- ------- -------
$67,861 $ 4,659 $ 7,634 $ 4,873 $ 456 $85,483
======= ======= ======= ======= ======= =======
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):
Six Months Ended Three Months Ended
June 30, 2002 June 30, 2002
----------------------------- -----------------------------
Currently Previously Currently Previously
Reported Reported Reported Reported
---------- ---------- ---------- ----------
Revenues:
Marketing ................................. $ 851,839 $1,163,501 $ 482,232 $ 643,403
Costs and Expenses:
Marketing ................................. $ 843,804 $1,157,392 $ 479,802 $ 640,679
Operating earnings .......................... $ 4,255 $ 1,849 $ 850 $ 879
Earnings before income tax .................. $ 4,244 $ 1,807 $ 877 $ 875
Loss from discontinued operations, net ...... $ (1,511) $ - $ (1) $ -
Net earnings ................................ $ 1,150 $ 1,150 $ 555 $ 555
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):
Six Months Ended Three Months Ended
June 30, June 30,
------------------------- -------------------------
2003 2002 2003 2002
-------- -------- -------- --------
Revenues .......................... $877,503 $851,839 $414,947 $482,232
Operating earnings ................ $ 7,261 $ 7,093 $ 3,284 $ 2,004
Depreciation ...................... $ 718 $ 942 $ 277 $ 426
Supplemental volume and price information is as follows:
Six Months Ended Three Months Ended
June 30, June 30,
------------------------------- -------------------------------
2003 2002 2003 2002
----------- ----------- ----------- ----------
Wellhead Purchases - Per day (1)
Crude oil - barrels ...................... 91,000 110,000 90,000 106,000
Natural gas - mmbtu's .................... 319,000 584,000 331,000 525,000
Average Purchase Price
Crude oil - per barrel ................... $ 30.21 $ 22.14 $ 27.84 $ 24.67
Natural gas - per mmbtu .................. $ 5.82 $ 2.82 $ 5.38 $ 3.31
- ------------------------------------
(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 half of 2003 compared to 2002 as crude oil price increases were
substantially offset by reductions in crude oil purchase volumes. For the
comparative second quarter of 2003, marketing revenues decreased by $67 million
or 14 percent despite overall higher crude oil prices. This 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 for the six month period and $1,117,000 for the three month
period ended June 30, 2002, respectively. 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 in 2003.
See Note (5) of the Notes to Unaudited Consolidated Financial Statements. Absent
the fee income, comparative operating earnings would have been as follows (IN
THOUSANDS):
2003 2002 Increase
------ ------ --------
Six month period ended June 30 ........................ $7,261 $4,660 $2,601
Three month period ended June 30 ...................... $3,284 $ 887 $2,397
The comparative earnings increase for 2003 resulted from improved per
unit margin for both crude oil and natural gas. As a result of the war in Iraq
and a continuation of a period of uncertainty during the recent aftermath, near
month crude oil prices remained very strong relative to future month prices
(also known as a backwardated market). During such periods, the Company's
margins tend to widen causing improved profitability. Per unit margins for
natural gas also improved during 2003 as a result of reduced competition
associated with the wholesale purchasing and marketing of natural gas. A number
of large-scale competitors recently left the marketplace or significantly
curtailed their natural gas trading activity as the industry continues to
experience a shakeout following the Enron bankruptcy.
- Transportation
Transportation revenues, operating earnings and depreciation are as
follows (IN THOUSANDS):
Six Months Ended Increase Three Months Ended Increase
June 30, (Decrease) June 30, (Decrease)
-------------------- ---------- -------------------- ---------
2003 2002 2003 2002
------- ------- ------- -------
Revenues ..................... $18,425 $17,882 3% $ 9,415 $ 9,713 (3%)
Operating earnings ........... $ 1,130 $ 1,287 (12%) $ 631 $ 812 (22%)
Depreciation ................. $ 1,028 $ 750 37% $ 528 $ 372 42%
Demand for the Company's transportation services was relatively
consistent during the comparative periods. Operating earnings were reduced in
2003, however, because higher diesel fuel prices and insurance costs increased
operating expense. Fuel costs increased by $403,000 or 23 percent for the
comparative first half, consistent with higher average crude oil prices.
-19-
Insurance expense increased by $221,000 or 12 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):
Six Months Ended Three Months Ended
June 30, June 30,
-------------------- --------------------
2003 2002 2003 2002
------- ------- ------- -------
Revenues .......................... $ 4,329 $ 1,903 $ 2,605 $ 1,044
Operating earnings (loss) ......... $ 1,845 $ 29 $ 984 $ (1)
Depreciation and depletion ........ $ 888 $ 600 $ 537 $ 385
Comparative volume and price information is a follows:
Six Months Ended Three Months Ended
June 30, June 30,
---------------------------- ---------------------------
2003 2002 2003 2002
----------- ----------- ----------- ----------
Crude oil
Volume - barrels ................ 28,700 26,400 17,700 16,600
Average price per barrel ........ $ 31.03 $ 24.53 $ 29.42 $ 23.67
Natural gas
Volume - mmbtu's ................ 638,000 448,000 343,000 227,000
Average price per mmbtu ......... $ 5.36 $ 2.51 $ 6.03 $ 2.72
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
half of 2003, the Company participated in the drilling of fourteen wells. Ten
wells were successfully completed with three dry holes and one presently
drilling. In addition to the completions on wells spud in 2003, the Company also
successfully brought on production three wells that were drilling at year-end
2002.
-20-
Estimates of crude oil and natural gas reserves, resulting from 2003's
exploration efforts, were made by the Company's in-house staff. These estimates
indicate reserve additions totaling 93,000 barrels of oil and 1,302,000 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 reserve additions
represent more than a complete replacement of prior year production.
For the remainder of 2003, six additional wells are planned for Fort
Bend County, Texas following the success of six wells already drilled in the
area this year. The Company's Austin Chalk program will also continue following
three successes in this year's first half. Four more wells are slated to drill
this year in the Chalk formation with five 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 before year-end. Fieldwork
on a second large 3-D survey in Alabama will begin in September of this year.
This survey is expected to confirm prospect leads identified with 2-D seismic
data. An estimated $800,000 of seismic expenditures are estimated to be incurred
and expensed, during the third and fourth quarters of 2003 for these projects.
- General and administrative
General and administrative expenses decreased $1,147,000 or 27 percent
in the comparative first half 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 addition, during the second quarter of 2002, the Company
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
$2,708,000 during the six month period ended June 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. The winter of 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.
-21-
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 in the form of a provision for bad
debts. 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 are not being renewed and substantially all
contracts expire prior to December 31, 2003. With the end of the winter heating
season and 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
Natural gas prices appear to be holding strong in the $4 to $5 per unit
range. This is a positive result for the Company's exploration and production
efforts. Coupled with recent development efforts, continued positive results are
anticipated from the Company's oil and gas segment. In contrast, natural gas
prices and a sluggish United States economy are hampering chemical manufacturers
and hence the outlook for the transportation segment is less favorable results.
Near term profitability from marketing operations is more difficult to assess.
Should the present level of uncertainty in the Middle East subside, marketing
margins are expected to narrow, reducing profitability. In any event, the
overall outlook is positive and continued earnings strength is anticipated.
Liquidity and Capital Resources
During the first half of 2003, net cash provided by operating
activities totaled $10,554,000. The Company invested $4,044,000 in capital
expenditures including $724,000 in marketing equipment, $595,000 in
transportation operations and $2,725,000 in oil and gas drilling activities. The
remaining $6.5 million of cash flow from operating activities was used to boost
cash reserves and generally improve liquidity.
During July 2003, the Company expended $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 million on oil and gas
exploration projects and approximately $700,000 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 June 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 June 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 June 30, 2003, bank
debt outstanding under the Company's two revolving credit facilities totaled
$11,475,000.
-22-
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 June 30, 2003, the Company had $2.3 million of eligible borrowing
capacity under this facility. No working capital advances were outstanding as of
June 30, 2003. Letters of credit outstanding under this facility totaled
approximately $30 million as of June 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 June 30, 2003. Letters of credit outstanding under this
facility totaled approximately $11.3 million as of June 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.
-23-
2. Mark-to-market earnings are calculated based on stated
contract volumes. One of 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 vs 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.
- 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
-24-
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 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
$8.3 million and intangible assets would have increased by a like amount at June
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.
-25-
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 June 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 June 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 six
month period ended June 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 June 30, 2003 and December 31,
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
$859,000, 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.
-26-
The following table illustrates the factors that impacted the change in
the net value of the Company's risk management assets and liabilities for the
six months ended June 30, 2003 (IN THOUSANDS)
2003
----
Net fair value on January 1, ......................................... $ (70)
Activity during 2003
- Net cash paid on settled contracts ............................ 316
- Net realized loss from prior years' contracts ................. (163)
- Net unrealized gain from prior years' contracts ............... 322
- Net unrealized gain from current year contracts ............... 454
-----
Net fair value on June 30, ........................................... $ 859
=====
Historically, prices received for oil and gas production have been
volatile and unpredictable. Price volatility is expected to continue. From
January 1, 2003 through June 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 $387,000 for the six-month period ended
June 30, 2003.
Forward-Looking Statements--Safe Harbor Provisions
This report for the period ended June 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 regulatory
changes, (e) counterparty credit default, (f) inability to obtain bank and/or
trade credit support, (g) availability and cost of insurance, (h) changes in tax
laws, and (i) the availability of capital, (j) changes in regulations, (k)
results of current items of litigation, (l) uninsured items of litigation or
losses, (m) uncertainty in reserve estimates and cash flows, (n) ability to
replace oil and gas reserves, (o) security issues related to drivers and
terminal facilities (p) commodity price volatility and (q) successful completion
of drilling activity.
-27-
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 second
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. - The Annual Meeting of Stockholders was held on April 23, 2003. At such
meeting, the stockholders voted to elect the board of nine Directors as
presented in the Company's Proxy Statement filed on Schedule 14A on April 3,
2003. Results by nominee were:
Authority
Voted For Against Abstain
---------- ------- -------
K. S. Adams, Jr. 2,309,159 - 1,908,437
J. A. Barrett 2,309,159 - 1,908,437
C. H. Lewis 2,309,159 - 1,908,437
E. C. Reinauer, Jr. 2,309,159 - 1,908,437
J. G. Simmons 2,309,159 - 1,908,437
V. H. Buckley 2,309,159 - 1,908,437
E. Wieck 2,309,159 - 1,908,437
E. J. Webster, Jr. 2,309,159 - 1,908,437
R. B. Abshire 2,309,159 - 1,908,437
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 May 15, 2003 as filed on May 15, 2003 to
announce earnings for the first quarter ended March 31, 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: August 12, 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-