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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
-----------------------
FORM 10-Q
[X] QUARTERLY REPORT UNDER SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-12295
GENESIS ENERGY, L.P.
(Exact name of registrant as specified in its charter)
Delaware 76-0513049
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
500 Dallas, Suite 2500, Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
(713) 860-2500
(Registrant's telephone number, including area code)
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
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This report contains 26 pages
2
GENESIS ENERGY, L.P.
Form 10-Q
INDEX
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements Page
----
Consolidated Balance Sheets - September 30, 2002 (Unaudited)
and December 31, 2001 3
Consolidated Statements of Operations for the Three and Nine
Months Ended September 30, 2002 and 2001 (Unaudited) 4
Consolidated Statements of Cash Flows for the Nine Months
Ended September 30, 2002 and 2001 (Unaudited) 5
Consolidated Statement of Partners' Capital for the Nine
Months Ended September 30, 2002 (Unaudited) 6
Notes to Consolidated Financial Statements 7
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 13
Item 3. Quantitative and Qualitative Disclosures about Market Risk 21
Item 4. Controls and Procedures 23
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 24
Item 6. Exhibits and Reports on Form 8-K 24
SIGNATURES 24
CERTIFICATIONS 25
3
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
September 30, December 31,
2002 2001
-------- --------
ASSETS (Unaudited)
CURRENT ASSETS
Cash and cash equivalents $ 4,939 $ 5,777
Accounts receivable:
Trade 72,115 160,734
Related party - 1,064
Inventories 3,326 3,737
Other 4,606 10,788
-------- --------
Total current assets 84,986 182,100
FIXED ASSETS, at cost 116,019 115,336
Less: Accumulated depreciation (73,089) (69,626)
-------- --------
Net fixed assets 42,930 45,710
OTHER ASSETS, net of amortization 463 2,303
-------- --------
TOTAL ASSETS $128,379 $230,113
======== ========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable -
Trade $ 79,518 $172,848
Related party 4,908 697
Accrued liabilities 7,906 10,144
-------- --------
Total current liabilities 92,332 183,689
LONG-TERM DEBT - 13,900
COMMITMENTS AND CONTINGENCIES (Note 10)
MINORITY INTERESTS 515 515
PARTNERS' CAPITAL
Common unitholders, 8,625 units issued
and outstanding 34,814 31,361
General partner 718 648
-------- --------
Total partners' capital 35,532 32,009
-------- --------
TOTAL LIABILITIES AND PARTNERS' CAPITAL $128,379 $230,113
======== ========
The accompanying notes are an integral part of these consolidated
financial statements.
4
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
-------- -------- -------- ----------
<s> <c> <c> <c> <c>
REVENUES:
Gathering and marketing revenues
Unrelated parties $209,916 $817,995 $677,697 $2,635,880
Related parties - - 3,036 25,900
Pipeline revenues 6,434 3,652 15,625 11,039
-------- -------- -------- ----------
Total revenues 216,350 821,647 696,358 2,672,819
COST OF SALES:
Crude costs unrelated parties 193,469 804,035 644,178 2,603,128
Crude costs related parties 9,181 4,735 13,566 33,435
Field operating costs 4,021 3,853 12,025 11,816
Pipeline operating costs 4,911 2,763 10,161 7,763
-------- -------- -------- ----------
Total cost of sales 211,582 815,386 679,930 2,656,142
-------- -------- -------- ----------
GROSS MARGIN 4,768 6,261 16,428 16,677
EXPENSES:
General and administrative 2,060 2,969 6,352 8,695
Depreciation and amortization 1,412 1,863 4,310 5,630
-------- -------- -------- ----------
OPERATING INCOME 1,296 1,429 5,766 2,352
OTHER INCOME (EXPENSE):
Interest income 30 34 45 153
Interest expense (209) (153) (892) (526)
Change in fair value of derivatives (1,037) (1,589) (2,094) 3,499
Gain on asset sales 23 12 698 160
-------- -------- -------- ----------
Income (loss) before minority interest and cumulative
effect of change in accounting principle 103 (267) 3,523 5,638
Minority interest - - - 1
-------- -------- -------- ----------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE 103 (267) 3,523 5,637
Cumulative effect of adoption of accounting principle,
net of minority interest effect - - - 467
-------- -------- -------- ----------
NET INCOME (LOSS) $ 103 $ (267) $ 3,523 $ 6,104
======== ======== ======== ==========
NET INCOME (LOSS) PER COMMON UNIT - BASIC AND DILUTED:
Income (loss) before cumulative effect of change in
accounting principle $ 0.01 $ (0.03) $ 0.40 $ 0.64
Cumulative effect of change in accounting principle,
net of minority interest effect - - - 0.05
-------- -------- -------- ----------
Net Income (loss) $ 0.01 $ (0.03) $ 0.40 $ 0.69
======== ======== ======== ==========
NUMBER OF COMMON UNITS OUTSTANDING 8,625 8,624 8,625 8,624
======== ======== ======== ==========
The accompanying notes are an integral part of these
consolidated financial statements.
5
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
Nine Months Ended
September 30,
2002 2001
-------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 3,523 $ 6,104
Adjustments to reconcile net income to net cash provided
by (used in) operating activities -
Depreciation 3,674 4,641
Amortization of intangible assets 636 989
Cumulative effect of adoption of accounting principle - (467)
Change in fair value of derivatives 2,094 (3,499)
Minority interest equity in earnings - 1
Gain on sales of fixed assets (698) (160)
Other noncash charges 1,500 45
Changes in components of working capital -
Accounts receivable 89,683 99,443
Inventories 1,967 (1,391)
Other current assets 6,182 (7,510)
Accounts payable (89,119) (93,596)
Accrued liabilities (5,832) 3,348
-------- --------
Net cash provided by operating activities 13,610 7,948
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (2,753) (745)
Change in other assets 1 (1)
Proceeds from sales of assets 2,204 446
-------- --------
Net cash used in investing activities (548) (300)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net (repayments) borrowings under Loan Agreement (13,900) 2,000
Distributions to common unitholders - (5,173)
Distributions to general partner - (105)
Distributions to minority interest owner - (1)
Purchase of treasury units - (6)
-------- --------
Net cash used in financing activities (13,900) (3,285)
-------- --------
Net increase (decrease) in cash and cash equivalents (838) 4,363
Cash and cash equivalents at beginning of period 5,777 5,508
-------- --------
Cash and cash equivalents at end of period $ 4,939 $ 9,871
======== ========
The accompanying notes are an integral part of these consolidated
financial statements.
6
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
(In thousands)
(Unaudited)
Partners' Capital
-----------------------------
Common General
Unitholders Partner Total
----------- ------ -------
Partners' capital at December 31, 2001 $ 31,361 $ 648 $32,009
Net income for the nine months ended
September 30, 2002 3,453 70 3,523
----------- ------ -------
Partners' capital at September 30, 2002 $ 34,814 $ 718 $35,532
=========== ====== =======
The accompanying notes are an integral part of these
consolidated financial statements.
7
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Formation and Offering
Genesis Energy, L.P. ("GELP" or the "Partnership") was formed in December
1996 as an initial public offering of 8.6 million Common Units, representing
limited partner interests in GELP of 98%. The general partner of GELP is
Genesis Energy, Inc. (the "General Partner") which owns a 2% general partner
interest in GELP. The General Partner is owned by Denbury Gathering &
Marketing, Inc., a wholly-owned subsidiary of Denbury Resources Inc.,
("Denbury"). Denbury acquired the General Partner from Salomon Smith Barney
Holdings Inc. ("Salomon") and Salomon Brothers Holding Company Inc. on May 14,
2002. On May 15, 2002, Denbury converted Genesis Energy, L.L.C., a limited
liability company, into Genesis Energy, Inc., a Delaware corporation.
Genesis Crude Oil, L.P. is the operating limited partnership and is owned
99.99% by GELP and 0.01% by the General Partner. Genesis Crude Oil, L.P. has
two subsidiary partnerships, Genesis Pipeline Texas, L.P. and Genesis Pipeline
USA, L.P. Genesis Crude Oil, L.P. and its subsidiary partnerships will be
referred to as GCOLP.
2. Basis of Presentation
The accompanying consolidated financial statements and related notes present
the financial position as of September 30, 2002 and December 31, 2001 for
GELP, the results of operations for the three and nine months ended September
30, 2002 and 2001, cash flows for the nine months ended September 30, 2002 and
2001 and changes in partners' capital for the nine months ended September 30,
2002.
The financial statements included herein have been prepared by the
Partnership without audit pursuant to the rules and regulations of the
Securities and Exchange Commission ("SEC"). Accordingly, they reflect all
adjustments (which consist solely of normal recurring adjustments) which are,
in the opinion of management, necessary for a fair presentation of the
financial results for interim periods. Certain information and notes normally
included in financial statements prepared in accordance with generally
accepted accounting principles have been condensed or omitted pursuant to such
rules and regulations. However, the Partnership believes that the disclosures
are adequate to make the information presented not misleading. These
financial statements should be read in conjunction with the financial
statements and notes thereto included in the Partnership's Annual Report on
Form 10-K for the year ended December 31, 2001 filed with the SEC.
Basic net income per Common Unit is calculated on the weighted average
number of outstanding Common Units. The weighted average number of Common
Units outstanding for the three months ended September 30, 2002 and 2001 was
8,625,000 and 8,624,000, respectively. For the 2002 and 2001 nine month
periods, the weighted average number of Common Units outstanding was 8,625,000
and 8,624,000, respectively. For this purpose, the 2% General Partner
interest is excluded from net income. Diluted net income per Common Unit did
not differ from basic net income per Common Unit for any period presented.
3. New Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for
Asset Retirement Obligations." This statement requires entities to record the
fair value of a liability for legal obligations associated with the retirement
obligations of tangible long-lived assets in the period in which it is
incurred. When the liability is initially recorded, a corresponding increase
in the carrying amount of the related long-lived asset would be recorded.
Over time, accretion of the liability is recognized each period, and the
capitalized cost is depreciated over the useful life of the related asset.
Upon settlement of the liability, an entity either settles the obligation for
its recorded amount or incurs a gain or loss on settlement. The standard is
effective for fiscal years beginning after June 15, 2002, with earlier
application encouraged. The Partnership is currently evaluating the effect on
its financial statements of adopting SFAS No. 143 and plans to adopt the
statement effective January 1, 2003.
SFAS No. 142, "Goodwill and Other Intangible Assets", and SFAS No. 144,
"Accounting for Impairment on Disposal of Long-Lived Assets", were adopted by
the Partnership effective January 1, 2002. These statements had
8
no effect on the consolidated financial statements of the Partnership as the
net book value of the Partnership's goodwill was zero at December 31, 2001.
In April 2002 the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." SFAS No. 145 rescinds SFAS No. 4, "Reporting Gains and Losses
from Extinguishment of Debt" and an amendment of that statement, SFAS No. 64,
"Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements." SFAS No.
145 also rescinds SFAS No. 44, "Accounting for Intangible Assets of Motor
Carriers." SFAS No. 145 also amends SFAS No. 13, "Accounting for Leases," to
eliminate an inconsistency between the required accounting for sale-leaseback
transactions and the required accounting for certain lease modifications that
have economic effects that are similar to sale-leaseback transactions. SFAS
No. 145 also amends other existing authoritative pronouncements to make
various technical corrections, clarify meanings, or describe their
applicability under changed conditions. The provisions related to the
rescission of SFAS No. 4 shall be applied in fiscal years beginning after May
15, 2002. The provisions related to SFAS No. 13 shall be effective for
transactions occurring after May 15, 2002. All other provisions shall be
effective for financial statements issued on or after May 15, 2002, with early
application encouraged. The Partnership does not believe that SFAS No. 145
will have a material effect on its results of operations.
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 Partnership will adopt 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 Partnership
has not completed its analysis of the impact that SFAS No. 146 will have on
its consolidated financial statements.
4. Business Segment and Customer Information
Based on its management approach, the Partnership believes that all of its
material operations revolve around the gathering and marketing of crude oil,
and it currently reports its operations, both internally and externally, as a
single business segment. ExxonMobil Corporation and Marathon Ashland
Petroleum LLC accounted for 14% and 17%, respectively, of revenues in the
first nine months of 2002. No customer accounted for more than 10% of the
Partnership's revenues in the same period in 2001.
5. Inventory Reduction
As a result of a change in the Partnership's operations to focus on its
gathering activities, and due to changes made in its gathering business as a
result of changes in its credit facilities, the Partnership determined that
the volume of crude oil needed to ensure efficient and uninterrupted operation
of its gathering business should be reduced. These crude oil volumes had been
carried at their weighted average cost and classified as fixed assets. In the
first nine months of 2002, the Partnership realized additional gross margin of
approximately $889,000 as a result of the sale of these volumes.
6. Credit Resources
In 2001, Genesis had a $300 million Master Credit Support Agreement
("Guaranty Facility") with Salomon and a $25 million working capital facility
("WC Facility") with BNP Paribas.
Effective December 19, 2001, GCOLP entered into a two-year $130 million
Senior Secured Revolving Credit Facility ("Credit Agreement") with Citicorp
North America, Inc. ("Citicorp"). Citicorp and Salomon, the former owner of
the Partnership's General Partner, are both wholly-owned subsidiaries of
Citigroup Inc. The Credit Agreement replaced the Guaranty Facility and the WC
Facility.
In May 2002, the Partnership elected, under the terms of the Credit
Agreement, to amend the Credit Agreement to reduce the maximum facility amount
to $80 million. The Credit Agreement has a $25 million sublimit for
9
working capital loans. Any amount not being used for working capital loans is
available for letters of credit to support crude oil purchases.
During the first four months of 2002, Salomon continued to provide
guaranties to the Partnership's counterparties under a transition arrangement
between Salomon, Citicorp and the Partnership. For crude oil purchases in
January 2002 through April 2002, a maximum of $100 million, respectively, in
guaranties were available to be issued under the Salomon guaranty facility.
Beginning with May 2002, Citicorp provided letters of credit to the
Partnership's counterparties.
The key terms of the amended Credit Agreement are as follows:
* Letter of credit fees are based on the Applicable Leverage Level ("ALL")
and will range from 1.50% to 4.50%. At September 30, 2002, the rate was
2.25%. The ALL is a function of GCOLP's average daily debt to its
earnings before interest, depreciation and amortization for the four
preceding quarters.
* The interest rate on working capital borrowings is also based on the ALL
and allows for loans based on the prime rate or the LIBOR rate at the
Partnership's option. The interest rate on prime rate loans can range
from the prime rate to the prime rate plus 1.25%. The interest rate for
LIBOR-based loans can range from the LIBOR rate plus 1.50% to the LIBOR
rate plus 4.50%. At June 30, 2002, the interest rate for the
Partnership's borrowings was 4.75%.
* The Partnership will pay a commitment fee on the unused portion of the
$80 million commitment. This commitment fee is also based on the ALL
and will range from 0.375% to 0.75%. At September 30, 2002, the
commitment fee was 0.375%.
* The amount that the Partnership may have outstanding cumulatively in
working capital borrowings and letters of credit is subject to a
Borrowing Base calculation. The Borrowing Base (as defined in the
Credit Agreement) generally includes the Partnership's cash balances,
net accounts receivable and inventory, less deductions for certain
accounts payable, and is calculated monthly.
* Collateral under the Credit Agreement consists of all of the
Partnership's accounts receivable, inventory, cash accounts, margin
accounts and property and equipment.
* The Credit Agreement contains covenants requiring a Current Ratio (as
defined in the Credit Agreement), a Leverage Ratio (as defined in the
Credit Agreement), an Interest Coverage Ratio (as defined in the Credit
Agreement) and limitations on distributions to Unitholders.
Distributions to Unitholders and the General Partner can only be made if the
Borrowing Base exceeds the usage (working capital borrowings plus outstanding
letters of credit) under the Credit Agreement for every day of the quarter by
at least $20 million. The Partnership did not meet this test in the first two
quarters of 2002; therefore, no distributions were paid for those quarters.
The Partnership met this test in the third quarter of 2002. However, no
distribution will be made for the third quarter of 2002. See additional
discussion below under "Distributions".
At September 30, 2002, the Partnership had no loans outstanding under the
Credit Agreement. Due to the revolving nature of loans under the Credit
Agreement, borrowings and periodic repayments and re-borrowings may be made
until the maturity date of December 31, 2003. At September 30, 2002, the
Partnership had letters of credit outstanding under the Credit Agreement of
$30.8 million, consisting of $15.7 million and $15.1 million related to
September 2002 and October 2002, respectively, for crude oil purchases.
Distributions
Generally, GCOLP will distribute 100% of its Available Cash within 45 days
after the end of each quarter to Unitholders of record and to the General
Partner. Available Cash consists generally of all of the cash receipts less
cash disbursements of GCOLP adjusted for net changes to reserves. As a result
of the restructuring approved by Unitholders in December 2000, the target
minimum quarterly distribution ("MQD") for each quarter was reduced to $0.20
per unit. The Partnership has not made distributions since the fourth quarter
of 2001.
10
Under the terms of the Credit Agreement, the Partnership may not pay a
distribution for any quarter unless the Borrowing Base exceeded the usage
under the Credit Agreement (working capital loans plus outstanding letters of
credit) for every day of the quarter by at least $20 million. For the first
and second quarters of 2002, the Partnership did not pay a distribution as the
excess of the Borrowing Base over usage did not exceed $20 million for every
day in the quarter. During the third quarter of 2002, the Partnership met the
$20 million restrictive covenant under the Credit Agreement and was thus not
restricted from making a distribution. However, the Partnership did not make
a distribution for the third quarter of 2002 because of a reserve established
for future needs of the Partnership. These reserves exceeded Available Cash
for the third quarter of 2002. Such future needs of the Partnership include,
but are not limited to, potential fines that may be imposed under the Clean
Water Act in connection with the crude oil spill that occurred on the
Mississippi System in December 1999 and future expenditures that will be
required for pipeline integrity management programs required by federal
regulations.
Although no distributions have been made by the Partnership in 2002, some
of the Partnership's Unitholders will be allocated taxable income for 2002.
The amount of taxable income allocated to each unitholder will vary, depending
on the timing of unit purchases and the amount of each unitholder's tax basis
in their units. In order to mitigate the burden of incurring a tax liability
without receiving a cash distribution, the Partnership will make a special
distribution in the amount of $0.20 per unit on December 16, 2002, to
Unitholders of record as of December 2, 2002.
The Partnership Agreement authorizes the General Partner to cause GCOLP to
issue additional limited partner interests and other equity securities, the
proceeds from which could be used to provide additional funds for acquisitions
or other GCOLP needs.
7. Transactions with Related Parties
Sales, purchases and other transactions with affiliated companies, in the
opinion of management, are conducted under terms no more or less favorable
than those conducted with unaffiliated parties. Salomon was a related party
during 2001 and through May 14, 2002. Denbury became a related party on May
14, 2002, when it acquired the General Partner. The amounts below include
transactions during the periods when Salomon and Denbury were related parties.
Sales and Purchases of Crude Oil
A summary of sales to and purchases from related parties of crude oil is
as follows (in thousands).
Nine Months Nine Months
Ended Ended
September 30, September 30,
2002 2001
------------- -------------
Sales to Salomon affiliates $ 3,036 $ 25,900
Purchases from Salomon affiliates $ - $ 33,435
Purchases from Denbury affiliates $ 13,566
Purchases from Denbury are secured by letters of credit.
General and Administrative Services
The Partnership does not directly employ any persons to manage or operate
its business. Those functions are provided by the General Partner. The
Partnership reimburses the General Partner for all direct and indirect costs
of these services. Total costs reimbursed to the General Partner by the
Partnership were $12,854,000 and $13,877,000 for the nine months ended
September 30, 2002 and 2001, respectively.
Credit Facilities
As discussed in Note 6, Citicorp provides a Credit Agreement to the
Partnership. During the first four months of 2002, Salomon provided
guaranties under a transition arrangement. For the nine months ended
September 30, 2002 and 2001, the Partnership incurred $61,000 and $1,049,000,
respectively, for guarantee fees under the Guaranty Facility. From January 1,
2002, until May 14, 2002, when Citicorp ceased to be a related party,
11
the Partnership incurred letter of credit fees, interest and commitment fees
totaling $396,000 under the Credit Agreement.
8. Supplemental Cash Flow Information
Cash received by the Partnership for interest was $46,000 and $179,000 for
the nine months ended September 30, 2002 and 2001, respectively. Payments of
interest were $453,000 and $390,000 for the nine months ended September 30,
2002 and 2001, respectively.
9. Derivatives
The Partnership utilizes crude oil futures contracts and other financial
derivatives to reduce its exposure to unfavorable changes in crude oil prices.
On January 1, 2001, the Partnership adopted the provisions of SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" (as amended and
interpreted), which established new accounting and reporting guidelines for
derivative instruments and hedging activities. SFAS No. 133 established
accounting and reporting standards requiring that every derivative instrument
(including certain derivative instruments embedded in other contracts) be
recorded in the balance sheet as either an asset or liability measured at its
fair value. SFAS No. 133 requires that changes in the derivative's fair value
be recognized currently in earnings unless specific hedge accounting criteria
are met. Special accounting for qualifying hedges allows a derivative's gains
and losses to offset related results on the hedged item in the income
statement. Companies must formally document, designate and assess the
effectiveness of transactions that receive hedge accounting. In 2002 and
2001, the Partnership did not designate any of its derivatives as hedging
instruments under SFAS No. 133.
Under SFAS No. 133, the Partnership marks to fair value all of its
derivative instruments at each period end with changes in fair value being
recorded as unrealized gains or losses. Such unrealized gains or losses will
change, based on prevailing market prices, at each balance sheet date prior to
the period in which the transaction actually occurs. The initial adoption of
SFAS No. 133 required that the difference between the fair value of derivative
instruments and the previous carrying amount of those derivatives be recorded
in net income or other comprehensive income, as appropriate, as the cumulative
effect of a change in accounting principle.
On January 1, 2001, the Partnership recorded a cumulative gain for the
effect of the adoption of SFAS No. 133, net of minority interest, of $0.5
million.
The Partnership regularly reviews its contracts to determine if the
contracts qualify for treatment as derivatives in accordance with SFAS No.
133. At September 30, 2002, the Partnership determined that none of its
contracts qualified as derivatives under SFAS No. 133, so the fair value of
the Partnership's net asset for derivatives decreased to zero. This decrease
in fair value of $2.1 million for the nine months ended September 30, 2002, is
recorded as a loss in the consolidated statement of operations under the
caption "Change in fair value of derivatives."
10. Contingencies
Unitholder Litigation
On June 7, 2000, Bruce E. Zoren, a holder of units of limited partner
interests in the partnership, filed a putative class action complaint in the
Delaware Court of Chancery, No. 18096-NC, seeking to enjoin the restructuring
and seeking damages. Defendants named in the complaint include the
Partnership, Genesis Energy L.L.C., members of the board of directors of
Genesis Energy, L.L.C., and Salomon Smith Barney Holdings Inc. The plaintiff
alleges numerous breaches of fiduciary duty loyalty owed by the defendants to
the purported class in connection with making a proposal for restructuring.
In November 2000, the plaintiff amended its complaint. In response, the
defendants removed the amended complaint to federal court. On March 27, 2002,
the federal court dismissed the suit; however, the plaintiff filed a motion to
alter or amend the judgment. On May 15, 2002, the federal court denied the
motion to alter or amend. The time for an appeal to be taken expired without
an appeal being filed. On June 11, 2002, the plaintiff refiled the original
complaint in the Delaware Court of Chancery, No. 19694-NC. On July 19, 2002,
the defendants moved to dismiss the complaint for failure to state a claim
upon which
12
relief can be granted. The court has not ruled on that motion. Management of
the General Partner believes that the complaint is without merit and intends
to vigorously defend the action.
Pennzoil Lawsuit
The Partnership has been named one of the defendants in a complaint filed
by Thomas Richard Brown on January 11, 2001, in the 125th District Court of
Harris County, cause No. 2001-01176. Mr. Brown, an employee of Pennzoil-
Quaker State Company ("PQS"), was seeking damages for burns and other injuries
suffered as a result of a fire and explosion that occurred at the Pennzoil
Quaker State refinery in Shreveport, Louisiana, on January 18, 2000. During
the third quarter of 2002, Genesis reached a settlement agreement with Mr.
Brown to withdraw his complaint. The amount of the settlement was undisclosed
and was covered entirely by insurance.
On January 17, 2001, PQS filed a Plea in Intervention in the cause filed
by Mr. Brown. PQS seeks property damages, loss of use and business
interruption. PQS claims the fire and explosion was caused, in part, by
Genesis selling to PQS crude oil that was contaminated with organic chlorides.
Management of the Partnership believes that the suit is without merit and
intends to vigorously defend itself in this matter. Management of the
Partnership believes that any potential liability will be covered by
insurance.
Other Matters
On December 20, 1999, the Partnership had a spill of crude oil from its
Mississippi System. Approximately 8,000 barrels of oil spilled from the
pipeline near Summerland, Mississippi, and entered a creek nearby. A portion
of the oil then flowed into the Leaf River. The oil spill is covered by
insurance, and the financial impact to the Partnership for the cost of the
clean-up has not been material. As a result of this crude oil spill, certain
federal and state regulatory agencies will likely impose fines and penalties
that would not be covered by insurance.
The Partnership is subject to various environmental laws and regulations.
Policies and procedures are in place to monitor compliance. The Partnership's
management has made an assessment of its potential environmental exposure, and
primarily as a result of the spill from the Mississippi System, an accrual of
$1.5 million was recorded for the year ended December 31, 2001. In the third
quarter of 2002, the Partnership increased this accrual by $1.5 million,
primarily as a result of discussions with regulatory agencies regarding the
Mississippi spill.
The Partnership is subject to lawsuits in the normal course of business
and examination by tax and other regulatory authorities. Such matters
presently pending are not expected to have a material adverse effect on the
consolidated financial position, results of operations or cash flows of the
Partnership.
13
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Genesis Energy, L.P., operates crude oil common carrier pipelines and is an
independent gatherer and marketer of crude oil in North America, with
operations concentrated in Texas, Louisiana, Alabama, Florida and Mississippi.
The following review of the results of operations and financial condition
should be read in conjunction with the Condensed Consolidated Financial
Statements and Notes thereto.
Results of Operations
Selected financial data for this discussion of the results of operations
follows, in thousands, except barrels per day.
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
------- -------- ------- --------
Gross margin
Gathering and marketing $ 3,245 $ 5,372 $10,964 $ 13,401
Pipeline $ 1,523 $ 889 $ 5,464 $ 3,276
General and administrative expenses $ 2,060 $ 2,969 $ 6,352 $ 8,695
Depreciation and amortization $ 1,412 $ 1,863 $ 4,310 $ 5,630
Operating income $ 1,296 $ 1,429 $ 5,766 $ 2,352
Interest income (expense), net $ (179) $ (119) $ (847) $ (373)
Change in fair value of derivatives $(1,037) $ (1,589) $(2,094) $ 3,499
Gain on asset disposals $ 23 $ 12 $ 698 $ 160
Barrels per day
Wellhead 60,044 82,280 64,308 86,390
Bulk and exchange 23,243 260,292 42,738 274,074
Pipeline 75,172 81,829 75,385 86,106
The profitability of Genesis depends to a significant extent upon its
ability to maximize gross margin. Gross margins from gathering and marketing
operations are a function of volumes purchased and the difference between the
price of crude oil at the point of purchase and the price of crude oil at the
point of sale, minus the associated costs of aggregation and transportation.
The absolute price levels for crude oil do not necessarily bear a relationship
to gross margin as absolute price levels normally impact revenues and cost of
sales by equivalent amounts. Because period-to-period variations in revenues
and cost of sales are not generally meaningful in analyzing the variation in
gross margin for gathering and marketing operations, such changes are not
addressed in the following discussion.
In our gathering and marketing business, Genesis seeks to purchase and sell
crude oil at points along the Distribution Chain where we can achieve positive
gross margins. Genesis generally purchases crude oil at prevailing prices
from producers at the wellhead under short-term contracts. Genesis then
transports the crude along the Distribution Chain for sale to or exchange with
customers. Additionally, Genesis enters into exchange transactions with third
parties. Genesis generally enters into exchange transactions only when the
cost of the exchange is less than the alternate cost we would incur in
transporting or storing the crude oil. In addition, Genesis often exchanges
one grade of crude oil for another to maximize margins or meet contract
delivery requirements. Prior to the first quarter of 2002, Genesis purchased
crude oil in bulk at major pipeline terminal points. These bulk and exchange
transactions are characterized by large volumes and narrow profit margins on
purchases and sales.
Generally, as Genesis purchases crude oil, it simultaneously establishes a
margin by selling crude oil for physical delivery to third party users, such
as independent refiners or major oil companies. Through these transactions,
Genesis seeks to maintain a position that is substantially balanced between
crude oil purchases, on the one hand, and sales or future delivery
obligations, on the other hand. It is the policy of Genesis not to hold crude
oil, futures contracts or other derivative products for the purpose of
speculating on crude oil price changes.
14
Pipeline revenues and gross margins are primarily a function of the level of
throughput and storage activity and are generated by the difference between
the regulated published tariff and the fixed and variable costs of operating
the pipeline. Changes in revenues, volumes and pipeline operating costs,
therefore, are relevant to the analysis of financial results of Genesis'
pipeline operations and are addressed in the following discussion of pipeline
operations of Genesis.
Nine Months Ended September 30, 2002 Compared with Nine Months Ended
September 30, 2001
Gross margin from gathering and marketing operations was $11.0 million for
the nine months ended September 30, 2002, as compared to $13.4 million for the
nine months ended September 30, 2001.
The factors affecting gross margin were:
* a 70 percent decline in wellhead, bulk and exchange purchase volumes
between the nine month periods in 2002 and 2001, resulting in a
decrease in gross margin of $18.5 million;
* an increase in the gross margin of $14.6 million due to an increase in
the average difference between the price of crude oil at the point of
purchase and the price of crude oil at the point of sale;
* a decrease of $0.7 million in credit costs primarily due to the
reduction in bulk and exchange transactions;
* a $0.9 million increase in gross margin in the 2002 period as a result
of the sale of crude oil that is no longer needed to ensure efficient
and uninterrupted operations; and
* an increase of $0.2 million in field operating costs, primarily from
increased insurance and vehicle accident repair costs.
Pipeline gross margin was $5.5 million for the nine months ended September
30, 2002, as compared to $3.3 million for the nine months in 2001. The
factors affecting pipeline gross margin were:
* an increase in revenues from sales of pipeline loss allowance barrels
of $2.4 million primarily as a result of revising pipeline tariffs to
increase the amount of the pipeline loss allowance imposed on shippers,
the recognition of pipeline loss allowance volumes, measurement gains
net of measurement losses, and crude quality deductions as inventory;
* an increase of 39 percent in the average tariff on shipments resulting
in an increase in revenue of $3.4 million;
* a decrease in throughput of 12 percent between the two periods,
resulting in a revenue decrease of $1.2 million;
* an increase in pipeline operating costs of $0.9 million in the 2002
period primarily due to increased insurance costs of $0.4 million,
increases in contract service costs totaling $0.4 million and $0.1
million in other operating costs, offset by reduced power costs of $0.2
million due to electricity deregulation in Texas; and
* an increase of $1.5 million in the environmental accrual primarily as a
result of an updated assessment of the Company's environmental exposure
resulting from the spill from the Mississippi System in 1999.
General and administrative expenses were $6.4 million for the nine months
ended September 30, 2002, as compared to $8.6 million for the 2001 period.
The decrease of $2.2 million is attributable to changes in personnel costs
totaling $1.3 million, primarily due to the elimination of bulk and exchange
activities, and a change to the Partnership's bonus program to eliminate
bonuses unless distributions are being paid, which resulted in no accrual in
the 2002 period. An accrual of $0.9 million was recorded for bonus expense in
the 2001 period.
Depreciation and amortization declined $1.3 million between the nine month
periods. As a result of the impairment of the pipeline assets in 2001, the
value to be depreciated was reduced.
Interest expense increased $0.5 million due to an increase in commitment
fees. In 2001, the Partnership paid commitment fees on the unused portion of
its $25 million facility with BNP Paribas. In the 2002 period, the
Partnership paid commitment fees on the unused portion of the Credit Agreement
with Citicorp. From January 1,
15
2002, until May 3, 2002, that facility maximum was $130 million. At May 3,
2002, the Credit Agreement was reduced to a maximum of $80 million.
With the significant reduction in the Partnership's bulk and exchange
activities at December 31, 2001, combined with a review of contracts existing
at September 30, 2002, the Partnership determined that it had no contracts
meeting the requirement for treatment as derivative contracts under SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities" (as
amended and interpreted). As a result, the fair value of the Partnership's
net asset for derivatives decreased by $2.1 million to zero for the nine
months ended September 30, 2002.
The gain on asset disposals in the 2002 period resulted primarily from the
sale of the Partnership's memberships in the New York Mercantile Exchange
("NYMEX") and the sale of excess land and a building. The gain on asset
disposals in the 2001 period included a gain of $0.1 million as a result of
the sale of excess tractors.
Three Months Ended September 30, 2002 Compared with Three Months Ended
September 30, 2001
Gross margin from gathering and marketing operations was $3.2 million for
the three months ended September 30, 2002, as compared to $5.4 million for the
three months ended September 30, 2001.
The factors affecting gross margin were:
* a decrease of 76 percent in wellhead, bulk and exchange purchase
volumes between 2001 and 2002, resulting in a decrease in gross margin
of $7.2 million;
* an increase in gross margin of $4.6 million due to an increase in the
average difference between the price of crude oil at the point of
purchase and the price of crude oil at the point of sale;
* a decrease of $0.1 million in credit costs primarily due to the
reduction in bulk and exchange transactions;
* a $0.5 million increase in gross margin in the 2002 quarter as a
result of the sale of crude oil that is no longer needed to ensure
efficient and uninterrupted operations; and
* an increase of $0.2 million in field operating costs, primarily from
small increases in several areas including repairs to truck unload
stations and insurance costs.
Pipeline gross margin was $1.5 million for the quarter ended September 30,
2002, as compared to $0.9 million for the third quarter of 2001. The factors
affecting pipeline gross margin were:
* a decrease in throughput of 8 percent between the two periods,
resulting in a revenue decrease of $0.3 million;
* an increase in revenues from sales of pipeline loss allowance barrels
of $1.3 million primarily as a result of revising pipeline tariffs to
increase the amount of the pipeline loss allowance imposed on shippers,
the recognition of pipeline loss allowance volumes, measurement gains
net of measurement losses and crude quality deductions as inventory;
* an increase of 59 percent in the average tariff on shipments resulting
in an increase of $1.8 million in revenue;
* an increase in pipeline operating costs of $0.7 million in the 2002
period primarily due to increased maintenance and contract service
costs totaling $0.4 million and increased insurance costs, safety costs
and general operating costs of $0.1 million each; and
* an increase of $1.5 million in the environmental accrual primarily as a
result of an updated assessment of the Company's environmental exposure
resulting from the spill from the Mississippi System in 1999.
General and administrative expenses decreased $0.9 million during the
three months ended September 30, 2002, as compared to the same period in 2001.
The primary factors in this decrease were the elimination of personnel and
costs involved in bulk and exchange activities and the change to the
Partnership's bonus program.
Net interest expense increased by $0.1 million in the 2002 third quarter
due primarily to the increased commitment under credit facilities for which
commitment fees were owed.
16
As discussed, a review of the Partnership's contracts at September 30,
2002, resulted in a determination that none of its contracts met the
requirements for treatment as derivatives under SFAS 133 at September 30,
2002. The fair value of the Partnership's net asset for derivatives decreased
by $1.0 million for the quarter.
Liquidity and Capital Resources
Cash Flows
Cash flows from operating activities were $13.6 million for the nine
months ended September 30, 2002. Operating activities in the prior year
period generated cash of $7.9 million. The change between the two periods is
primarily due to the timing of payment for NYMEX transactions and related
margin calls in 2001.
For the nine months ended September 30, 2002, cash flows utilized in
investing activities were $0.6 million and $0.3 million, respectively. In
2002, the Partnership received cash totaling $2.2 million from the sale of the
NYMEX seats and a surplus building and land. The Partnership expended $2.8
million for property additions, primarily on its pipeline systems. In 2001,
the Partnership received $0.4 million from the sale of surplus assets and
expended $0.7 million on additions to property.
Cash flows utilized in financing activities by the Partnership during the
first nine months of 2002 totaled $13.9 million due to the use of funds to
eliminate the outstanding debt. In the prior year period, the Partnership
paid distributions to the common unitholders and the general partner totaling
$5.3 million. The Partnership borrowed $2.0 million under its working capital
facility in the 2001 period.
Working Capital and Credit Resources
Effective December 19, 2001, GCOLP entered into a two-year $130 million
Senior Secured Revolving Credit Facility ("Credit Agreement") with Citicorp.
Citicorp and Salomon, the former owner of the Partnership's General Partner,
are both wholly-owned subsidiaries of Citigroup Inc.
In May 2002, Genesis elected, under the terms of the Credit Agreement, to
amend the Credit Agreement to reduce the maximum facility amount to $80
million. The Credit Agreement has a $25 million sublimit for working capital
loans. Any amount not being used for working capital loans is available for
letters of credit to support crude oil purchases.
During the first four months of 2002, Salomon continued to provide
guaranties to the Partnership's counterparties under a transition arrangement
between Salomon, Citicorp and the Partnership. For crude oil purchases in
January 2002 through April 2002, a maximum of $100 million in guaranties were
available to be issued under the Salomon Guaranty Facility. Beginning with
May 2002, Citicorp provided letters of credit to the Partnership's
counterparties.
The key terms of the amended Credit Agreement are as follows:
* Letter of credit fees are based on the Applicable Leverage Level
("ALL") and will range from 1.50% to 4.50%. At September 30, 2002, the
rate was 2.25%. The ALL is a function of GCOLP's average daily debt to
its earnings before interest, depreciation and amortization for the
four preceding quarters.
* The interest rate on working capital borrowings is also based on the
ALL and allows for loans based on the prime rate or the LIBOR rate at
the Partnership's option. The interest rate on prime rate loans can
range from the prime rate to the prime rate plus 1.25%. The interest
rate for LIBOR-based loans can range from the LIBOR rate plus 1.50% to
the LIBOR rate plus 4.50%. At September 30, 2002, the interest rate
for the Partnership's borrowings was 4.75%.
* The Partnership will pay a commitment fee on the unused portion of the
$80 million commitment. This commitment fee is also based on the ALL
and will range from 0.375% to 0.75%. At September 30, 2002, the
commitment fee was 0.375%.
* The amount that the Partnership may have outstanding cumulatively in
working capital borrowings and letters of credit is subject to a
Borrowing Base calculation. The Borrowing Base (as defined in the
Credit Agreement) generally includes the Partnership's cash balances,
net accounts receivable and inventory, less deductions for certain
accounts payable, and is calculated monthly.
17
* Collateral under the Credit Agreement consists of all of the
Partnership's accounts receivable, inventory, cash accounts, margin
accounts and property and equipment.
* The Credit Agreement contains covenants requiring a Current Ratio (as
defined in the Credit Agreement), a Leverage Ratio (as defined in the
Credit Agreement), an Interest Coverage Ratio (as defined in the Credit
Agreement) and limitations on distributions to Unitholders.
Distributions to Unitholders and the General Partner can only be made if
the Borrowing Base exceeds the usage (working capital borrowings plus
outstanding letters of credit) under the Credit Agreement for every day of the
quarter by at least $20 million. See additional discussion below under
"Distributions".
At September 30, 2002, the Partnership had no loans outstanding under the
Credit Agreement. Due to the revolving nature of loans under the Credit
Agreement, additional borrowings and periodic repayments and re-borrowings may
be made until the maturity date of December 31, 2003. At September 30, 2002,
the Partnership had letters of credit outstanding under the Credit Agreement
totaling $30.8 million, comprised of $15.7 million and $15.1 million for crude
oil purchases related to September 2002 and October 2002, respectively.
As a result of the Partnership's decision to reduce its level of bulk and
exchange transactions, the Partnership's need for credit support in the form
of letters of credit has been less in 2002 than it was in 2001. However, any
significant decrease in the Partnership's financial strength, regardless of
the reason for such decrease, may increase the number of transactions
requiring letters of credit, which could restrict the Partnership's gathering
and marketing activities due to the limitations of the Credit Agreement and
Borrowing Base. This situation could in turn adversely affect the
Partnership's ability to maintain or increase the level of its purchasing and
marketing activities or otherwise adversely affect the Partnership's
profitability and Available Cash.
No assurance can be made that the Partnership will be able to replace the
existing facilities.
Contractual Obligation and Commercial Commitments
In addition to the Credit Agreement discussed above, the Partnership has
contractual obligations under operating leases as well as commitments to
purchase crude oil. The table below summarizes these obligations and
commitments at September 30, 2002 (in thousands).
Payments Due by Period
----------------------------------------------
Less than 1 - 3 4 - 5 After 5
Contractual Cash Obligations Total 1 Year Years Years Years
- ---------------------------- -------- ------- ------- ------ ------
<s> <c> <c> <c> <c> <c>
Operating Leases $ 20,671 $ 5,552 $10,184 $2,861 $2,074
Unconditional Purchase Obligations <F1> 94,225 94,225 - - -
-------- ------- ------- ------ ------
Total Contractual Cash Obligations $114,896 $99,777 $10,184 $2,861 $2,074
======== ======= ======= ====== ======
<FN>
<F1>
The unconditional purchase obligations included above are contracts to purchase crude oil,
generally at market-based prices. For purposes of this table, market prices at September 30, 2002,
were used to value the obligations, such that actual obligations may differ from the amounts
included above.
</FN>
Distributions
Generally, GCOLP will distribute 100% of its Available Cash within 45 days
after the end of each quarter to Unitholders of record and to the General
Partner. Available Cash consists generally of all of the cash receipts less
cash disbursements of GCOLP adjusted for net changes to reserves. (A full
definition of Available Cash is set forth in the Partnership Agreement.) As a
result of the restructuring approved by Unitholders in December 2000, the
target minimum quarterly distribution ("MQD") for each quarter was reduced to
$0.20 per unit beginning with the distribution for the fourth quarter of 2000,
which was paid in February 2001.
Under the terms of the Credit Agreement, the Partnership may not pay a
distribution for any quarter unless the Borrowing Base exceeded the usage
under the Credit Agreement (working capital loans plus outstanding letters of
credit) for every day of the quarter by at least $20 million plus the total
amount of the distribution.
18
For the first and second quarters of 2002, the Partnership did not pay a
distribution as the excess of the Borrowing Base over the usage dropped below
the required total. During the third quarter of 2002, the Partnership met
this test and was thus not restricted from making a distribution under the
Credit Agreement. However, the Partnership did not make a distribution for
the third quarter of 2002 because of a reserve established for future needs of
the Partnership. These reserves exceeded Available Cash for the third quarter
of 2002. Such future needs of the Partnership include, but are not limited
to, potential fines that may be imposed under the Clean Water Act in
connection with the crude oil spill that occurred on the Mississippi System in
December 1999 and future expenditures that will be required for pipeline
integrity management programs required by federal regulations.
Available cash before reserves for the quarter ended September 30, 2002,
is as follows (in thousands):
Net income $ 103
Depreciation and amortization 1,412
Increase to environmental accrual 1,500
Change in fair value of derivatives 1,037
Net loss from asset sales (1)
Maintenance capital expenditures (1,541)
-------
Available Cash before reserves $ 2,510
=======
The Partnership is still evaluating plans to restore the distribution
during 2003. Any decision to restore the distribution will take into account
the ability of the Partnership to sustain the distribution on an ongoing basis
with cash generated by its existing asset base, capital requirements needed to
maintain and optimize the performance of its asset base, and its ability to
finance its existing capital requirements and accretive acquisitions. If
distributions are resumed, such distributions may be for less than the minimum
quarterly distribution target of $0.20 per unit.
For each of the first three quarters of 2001, the Partnership paid a
distribution to the Common Unitholders and the General Partner of $0.20 per
unit.
Some of the Partnership's Unitholders will be allocated taxable income for
2002. The amount of taxable income allocated to each unitholder will vary,
depending on the timing of unit purchases and the amount of each unitholder's
tax basis in their units. In order to mitigate the burden of incurring a tax
liability without receiving a cash distribution, the Partnership will make a
special distribution in the amount of $0.20 per unit on December 16, 2002 to
Unitholders of record as of December 2, 2002.
Industry Credit Market Disruptions
Over the last nine months there have been an unusual number of business
failures and large financial restatements by small as well as large companies
in the energy industry. Because the energy industry is very credit intensive,
these failures and restatements have focused attention on the credit risks of
companies in the energy industry by credit rating agencies, producers and
counterparties.
This focus on credit has affected the Partnership in two ways - requests
for credit from producers and extension of credit to counterparties. While
the Partnership has seen some increase in requests for credit support from
producers (primarily in the first quarter of 2002), the Partnership has been
relatively successful in obtaining open credit from most producers.
Because the Partnership is an aggregator of crude oil, sales of crude oil
tend to be large volume transactions. In transacting business with the
Partnership's counterparties, management of the General Partner must decide
how much credit to extend to each counterparty, as well as the form and amount
of financial assurance to obtain from counterparties when credit is not
extended. The Partnership has modified its credit arrangements with certain
counterparties that have been adversely affected by recent financial
difficulties in the energy industry.
The Partnership's accounts receivable settle monthly and collection delays
generally relate only to discrepancies or disputes as to the appropriate
price, volume or quality of crude oil delivered. Of the $72.1 million
aggregate receivables on the Partnership's consolidated balance sheet at
September 30, 2002, approximately $71.9 million, or 99.7%, were less than 30
days past the invoice date.
19
FERC Notice of Proposed Rulemaking
On August 1, 2002, the Federal Energy Regulatory Commission ("FERC")
issued a Notice of Proposed Rulemaking that, if adopted, would amend its
Uniform System of Accounts for public utilities, natural gas companies and oil
pipeline companies by requiring specific written documentation concerning the
management of funds from a FERC-regulated subsidiary by a non-FERC-regulated
parent. Under the proposed rule, as a condition for participating in a cash
management or money pool arrangement, the FERC-regulated entity would be
required to maintain a minimum proprietary capital balance (stockholder's
equity) of 30 percent, and the FERC-reglated entity and its parent would be
required to maintain investment grade credit ratings. If either of these
conditions is not met, the FERC-regulated entity would not be eligible to
participate in the cash management or money pool arrangement. This proposed
rule was subject to a comment period of 15 days after its publication in the
Federal Register. A significant number of comments were received by the FERC.
Hearings have been held by the FERC and industry organizations have submitted
suggestions of changes to the proposed rule. At this time, it is unclear when
or if the rule will be enacted. Management of the Partnership believes that,
if enacted as proposed, this rule may affect the manner in which it manages it
cash; however, management is unable to predict the full impact of this
proposed regulation on the Partnership's business.
Other Matters
Crude Oil Contamination
The Partnership has been named one of the defendants in a complaint filed
by Thomas Richard Brown on January 11, 2001, in the 125th District Court of
Harris County, cause No. 2001-01176. Mr. Brown, an employee of Pennzoil-
Quaker State Company ("PQS"), was seeking damages for burns and other injuries
suffered as a result of a fire and explosion that occurred at the Pennzoil
Quaker State refinery in Shreveport, Louisiana, on January 18, 2000. During
the third quarter of 2002, Genesis reached a settlement agreement with Mr.
Brown to withdraw his complaint. The amount of the settlement was undisclosed
and was covered entirely by insurance.
On January 17, 2001, PQS filed a Plea in Intervention in the cause filed
by Mr. Brown. PQS seeks property damages, loss of use and business
interruption. PQS claims the fire and explosion was caused, in part, by
Genesis selling to PQS crude oil that was contaminated with organic chlorides.
Management of the Partnership believes that the suit is without merit and
intends to vigorously defend itself in this matter. Management of the
Partnership believes that any potential liability will be covered by
insurance.
Crude Oil Spill
On December 20, 1999, the Partnership had a spill of crude oil from its
Mississippi System. Approximately 8,000 barrels of oil spilled from the
pipeline near Summerland, Mississippi, and entered a creek nearby. A portion
of the oil then flowed into the Leaf River. The oil spill is covered by
insurance, and the financial impact to the Partnership for the cost of the
clean-up has not been material. As a result of this crude oil spill, certain
federal and state regulatory agencies will likely impose fines and penalties
that would not be covered by insurance. The Partnership's management has made
an assessment of its potential environmental exposure, and primarily as a
result of the spill from the Mississippi System, an accrual of $1.5 million
was recorded for the year ended December 31, 2001. In the third quarter of
2002, the Partnership increased this accrual by $1.5 million, primarily as a
result of discussions with regulatory agencies regarding the Mississippi
spill.
Insurance
The Partnership maintains insurance of various types that management
considers adequate to cover its operations and properties. The insurance
policies are subject to deductibles that management considers reasonable. The
policies do not cover every potential risk associated with operating its
assets, including the potential for a loss of significant revenues.
Consistent with the coverage available in the industry, its policies provide
limited pollution coverage, with broader coverage for sudden and accidental
pollution events. Additionally, as a result of the events of September 11,
the cost of insurance available to the industry has risen significantly, and
insurers have excluded or reduced coverage for losses due to acts of terrorism
and sabotage.
Since September 11, 2001, warnings have been issued by various agencies of
the United States Government to advise owners and operators of energy assets
that those assets may be a future target of terrorist organizations.
20
Any future terrorist attacks on the Partnership's assets, or assets of its
customers or competitors could have a material adverse affect on the
Partnership's business.
Management of the Partnership believes that Genesis is adequately insured
for public liability and property damage to others as a result of its
operations. However, no assurances can be given that an event not fully
insured or indemnified against will not materially and adversely affect the
Partnership's operations and financial condition. Additionally, no assurance
can be given that the Partnership will be able to maintain insurance in the
future at rates that management considers reasonable.
Sale of the General Partner by Salomon
On May 14, 2002, Salomon sold its 100% ownership interest in the General
Partner to a subsidiary of Denbury Resources, Inc. ("Denbury"). Denbury is an
independent oil and gas company.
Amendment to Partnership Agreement
On July 31, 2002, Genesis Energy, Inc. ("Genesis") amended Section 11.2 of
the Second Amended and Restated Agreement of Limited Partnership of Genesis
Energy, L.P. ("the Partnership Agreement") to broaden the right of the Common
Unitholders to remove the general partner of Genesis Energy, L.P. ("GELP").
Prior to this amendment, the general partner could only be removed for cause
and with approval by holders of two-thirds or more of the outstanding limited
partner interests in GELP. As amended, the Partnership Agreement provides
that, with the approval of at least a majority of the limited partners in
GELP, the general partner also may be removed without cause. Any limited
partner interests held by the general partner and its affiliates are to be
excluded from such a vote.
The amendment further provides that if it is proposed that the removal is
without cause and an affiliate of Denbury is the general partner to be removed
and not proposed as a successor, then any action for removal must also provide
for Denbury to be granted an option effective upon its removal to purchase
GELP's Mississippi pipeline system at a price that is 110 percent of its fair
market value at that time. Fair value is to be determined by agreement of two
independent appraisers, one chosen by the successor general partner and the
other by Denbury or if they are unable to agree, the mid-point of the values
determined by them.
The amendment was negotiated on behalf of GELP by the audit committee of
the board of directors of Genesis. Upon determination of its fairness,
including obtaining an opinion from the investment banking firm of the
GulfStar Group as to the amendment's fairness to the Common Unitholders of
GELP, and an opinion from Delaware legal counsel as to the form of the
amendment, the audit committee recommended approval of the amendment to the
board of directors of Genesis.
New Accounting Standards
In June 2001, the FASB issued FAS No. 143, "Accounting for Asset
Retirement Obligations." This statement requires entities to record the fair
value of a liability for legal obligations associated with the retirement
obligations of tangible long-lived assets in the period in which it is
incurred. When the liability is initially recorded, a corresponding increase
in the carrying amount of the related long-lived asset would be recorded.
Over time, accretion of the liability is recognized each period, and the
capitalized cost is depreciated over the useful life of the related asset.
Upon settlement of the liability, an entity either settles the obligation for
its recorded amount or incurs a gain or loss on settlement. The standard is
effective for fiscal years beginning after June 15, 2002, with earlier
application encouraged. The Partnership is currently evaluating the effect on
its financial statements of adopting FAS No. 143 and plans to adopt the
statement effective January 1, 2003.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and
Technical Corrections." SFAS No. 145 rescinds SFAS No. 4, "Reporting Gains
and Losses from Extinguishment of Debt" and an amendment of that statement,
SFAS No. 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund
Requirements." SFAS No. 145 also rescinds SFAS No. 44, "Accounting for
Intangible Assets of Motor Carriers." SFAS No. 145 also amends SFAS No. 13,
"Accounting for Leases," to eliminate an inconsistency between the required
accounting for sale-leaseback transactions and the required accounting for
certain lease modifications that have economic effects that are similar to
sale-leaseback transactions. SFAS No. 145 also amends other existing
authoritative pronouncements to make various technical corrections, clarify
meanings, or describe their applicability under changed conditions. The
provisions related to the rescission of SFAS No. 4 shall be applied in fiscal
years beginning after May 15, 2002. The provisions related to
21
SFAS No. 13 shall be effective for transactions occurring after May 15, 2002.
All other provisions shall be effective for financial statements issued on or
after May 15, 2002, with early application encouraged. The Partnership does
not believe that SFAS No. 145 will have a material effect on its results of
operations.
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 Partnership will adopt 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 Partnership
has not completed its analysis of the impact that SFAS No. 146 will have on
its consolidated financial statements.
Outlook
Historically, the crude oil gathering and marketing business has been very
competitive with thin and volatile profit margins. The ability to generate
margin in the crude oil gathering and marketing business is not directly
related to the absolute level of crude oil prices, but is generated by the
difference between the price at which crude oil is sold and the price paid and
other costs incurred in the purchase and transportation of the crude oil, as
well as the volume of crude oil available for purchase. In order to maximize
gross margin, management has been and will continue to analyze all aspects of
its gathering and marketing business in order to make decisions associated
with managing its marketing operations, field operations and administrative
support.
Another factor affecting crude oil gathering and marketing gross margins is
changes in the domestic production of crude oil. Short-term and long-term
crude oil price trends impact the amount of capital that producers have
available to maintain existing production and to invest in developing crude
reserves, which in turn impacts the amount of crude oil that is available to
be gathered and marketed by Genesis and its competitors. During the period
from 1999 through 2001, crude oil prices were marked by significant volatility
which made it very difficult to estimate the amount of crude oil available to
purchase. Management expects to continue to be subject to volatility and
long-term declines in the availability of crude oil production for purchase by
Genesis.
Genesis' gathering and marketing operations are also impacted by credit
support costs in the form of letters of credit. As stated above, gathering
and marketing gross margins are not tied to the absolute prices of crude oil.
In contrast, the per barrel cost of credit is a function of the absolute price
of crude oil, such that, as crude oil prices rise, credit costs increase. In
anticipation of the change to a smaller credit facility during the first
quarter of 2002, management began making changes to its business model in the
latter half of 2001 in order to be able to operate with a much smaller
revolving credit facility with a higher per barrel cost. These changes
resulted in a substantial decrease in the Partnership's bulk and exchange
activity by the end of 2001. Had the Partnership continued to engage in its
bulk and exchange activity, management believes that increases in the related
cost of credit would have substantially offset the gross margin provided by
that activity. Additionally, the Partnership began reviewing its wellhead
purchase contracts to determine whether margins under those contracts would
support higher credit costs per barrel. In some cases where contract terms
could not be renegotiated to improve margins after considering the higher cost
of credit, contracts were cancelled.
The cost of credit is impacted by the extent to which trade counterparties
require credit support. In the aftermath of the Enron collapse, the
Partnership experienced increased demand for credit from producers. Genesis
then initiated a program to reduce the credit support provided to
counterparties. As a result, demand for credit support decreased. No
assurances can be made that such credit requirements will decrease further or
that such credit support requirements will not increase over time.
Like the gathering and marketing operations, prospects for Genesis' pipeline
operations also are impacted by production declines. Declining production in
the areas surrounding Genesis' pipelines have reduced tariff revenues while
costs are expected either to remain fixed or to increase due to various
conditions, including increasing insurance costs, new pipeline integrity
management regulations and commercial and residential development over our
pipeline right of ways. Consequently, pipeline gross margins are expected to
decline unless Genesis obtains substantial increases in its tariff rates.
Genesis increased tariffs beginning in May 2002 in some areas and in the third
quarter of 2002 in other areas. It is uncertain whether the increases that
were made will be sufficient to offset
22
production declines in the pipeline operating areas and any increased
maintenance and operating costs related to its pipelines.
On May 14, 2002, Salomon sold its 100% ownership interest in the General
Partner to a subsidiary of Denbury. Genesis owns and operates a 261-mile
pipeline system in Mississippi adjacent to several of Denbury's existing and
prospective oil fields. Denbury is the largest oil and natural gas operator
in the state of Mississippi. There may be mutual benefits to Denbury and
Genesis due to this common production and transportation area. Because of the
new relationship, Genesis may obtain certain commitments for increased crude
oil volumes, while Denbury may obtain the certainty of transportation for its
oil production at competitive market rates. As Denbury continues to acquire
and develop old oil fields using carbon dioxide (CO2) based tertiary recovery
operations, Denbury would expect to add crude oil gathering and CO2 supply
infrastructure to these fields. Genesis may be able to provide or acquire
this infrastructure and provide support to Denbury's development of these
fields. Further, as the fields are developed over time, it may create
increased demand for Genesis' crude oil transportation services.
In order to increase the effectiveness of the Denbury related strategic
opportunities, the Partnership continues to evaluate opportunities to dispose
of underperforming assets and increase operating income by reducing
nonessential expenditures. Since management believes that its most
significant growth opportunities will revolve around the Mississippi System
due to Denbury's ownership of its general partner, most of the asset
optimization analysis is currently focused on the Texas System and the Jay
System.
Management is reviewing strategic opportunities for the Texas System. While
recent tariff increases have improved the outlook for this system, management
continues to examine opportunities for every part of the system to determine
if each segment should be sold, abandoned, or invested in for further growth.
Management believes that the highest and best use of the Jay system in
Florida/Alabama would be to convert it to natural gas service. Genesis has
entered into a strategic alliance with parties in the region to explore this
opportunity. Part of the process will involve finding alternative methods for
Genesis to continue to provide crude oil transportation services in the area.
While management believes this initiative has long-term potential, it is not
expected to have a substantial impact on the Partnership during 2002 or 2003.
The financial performance of the Partnership exceeded expectations for the
first nine months of 2002. Although the Partnership met the $20 million
restrictive covenant regarding cash distributions under the Credit Agreement
in the third quarter, the Partnership did not make a distribution because of a
reserve established for future needs of the Partnership. These reserves
exceeded the Available Cash for the third quarter of 2002. Such future needs
of the Partnership include, but are not limited to, potential fines that may
be imposed under the Clean Water Act in connection with the crude oil spill
that occurred on the Mississippi System in 1999 and future expenditures that
will be required for pipeline integrity management programs required by
federal regulations.
Management of the Partnership believes that the Partnership will be able to
meet the $20 million Credit Agreement covenant on an ongoing basis.
Management is evaluating the ability of the Partnership to generate Available
Cash in amounts sufficient to restore the distribution during 2003.
Management is not yet able to provide guidance as to when the distribution
will be restored or at what level it will be restored, but is hopeful that it
will be able to provide such guidance during the first quarter of 2003. Any
decision to restore the distribution will take into account the ability of the
Partnership to sustain the distribution on an ongoing basis with cash
generated by the existing asset base, capital requirements needed to maintain
and optimize the performance of the asset base, and the ability to finance
existing capital requirements and accretive acquisitions. If distributions
are resumed, such distributions may be for less than the minimum quarterly
distribution target of $0.20 per unit.
Although no distributions have been made by the Partnership in 2002, some of
the Partnership's Unitholders will be allocated taxable income for 2002. The
amount of taxable income allocated to each unitholder will vary, depending on
the timing of unit purchases and the amount of each unitholder's tax basis in
their units. In order to mitigate the burden of incurring a tax liability
without receiving a cash distribution, the Partnership will make a special
distribution in the amount of $0.20 per unit on December 16, 2002 to
Unitholders of record as of December 2, 2002.
Forward Looking Statements
The statements in this Form 10-Q that are not historical information may be
forward looking statements within the meaning of Section 27a of the Securities
Act of 1933 and Section 21E of the Securities Exchange Act of 1934.
23
Although management of the General Partner believes that its expectations
regarding future events are based on reasonable assumptions, no assurance can
be made that the Partnership's goals will be achieved or that expectations
regarding future developments will prove to be correct. Important factors
that could cause actual results to differ materially from the expectations
reflected in the forward looking statements herein include, but are not
limited to, the following:
* changes in regulations;
* the Partnership's success in obtaining additional lease barrels;
* changes in crude oil production volumes (both world-wide and in areas in
which the Partnership has operations);
* developments relating to possible acquisitions or business combination
opportunities;
* volatility of crude oil prices and grade differentials;
* the success of the risk management activities;
* credit requirements by the counterparties;
* the cost of obtaining liability and property insurance at a reasonable
cost;
* the Partnership's ability in the future to generate sufficient amounts of
Available Cash to permit the distribution to unitholders of at least the
minimum quarterly distribution;
* any requirements for testing or changes in the Mississippi pipeline
system as a result of the oil spill that occurred there in December 1999;
* any fines and penalties federal and state regulatory agencies may impose
in connection with the oil spill that would not be reimbursed by
insurance;
* the costs of testing under the Integrity Management Program and any
repairs required as a result of that testing;
* the Partnership's success in increasing tariff rates on its common
carrier pipelines and retaining the volumes shipped;
* the results of the Partnership's exploration of opportunities to convert
the Jay pipeline system to natural gas service and finding alternative
methods to continue crude oil service in the area;
* results of current or threatened litigation; and
* conditions of capital markets and equity markets during the periods
covered by the forward looking statements.
All subsequent written or oral forward-looking statements attributable to
the Partnership, or persons acting on the Partnership's behalf, are expressly
qualified in their entirety by the foregoing cautionary statements.
Item 3. Qualitative and Quantitative Disclosures about Market Risk
Price Risk Management and Financial Instruments
The Partnership's primary price risk relates to the effect of crude oil
price fluctuations on its inventories and the fluctuations each month in grade
and location differentials and their effects on future contractual
commitments. Historically, the Partnership has utilized New York Mercantile
Exchange ("NYMEX") commodity based futures contracts, forward contracts, swap
agreements and option contracts to hedge its exposure to market price
fluctuations, however, at September 30, 2002, no contracts were outstanding.
Information about inventory at September 30, 2002, is contained in the table
set forth below.
Crude Oil Inventory:
Volume (1,000 bbls) 73
Carrying value (in thousands) $2,070
Fair value (in thousands) $2,179
Fair values were determined by using the notional amount in barrels
multiplied by published market closing prices for the applicable crude oil
type at September 30, 2002.
Item 4. Controls and Procedures
The Partnership has evaluated the effectiveness of the design and operation
of its disclosure controls and procedures as of a date within 90 days prior to
the filing of this quarterly report on Form 10-Q (the "Evaluation Date").
Such evaluation was conducted under the supervision and with the participation
of the Partnership's Chief
24
Executive Officer ("CEO") and its Chief Financial Officer ("CFO"). Based upon
such evaluation, the Partnership's CEO and CFO have concluded that, as of the
Evaluation Date, the Partnership's disclosure controls and procedures were
effective. There have been no significant changes in the Partnership's
internal controls or other factors that could significantly affect these
controls subsequent to the date of their most recent evaluation.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
See Part I. Item 1. Note 10 to the Condensed Consolidated Financial
Statements entitled "Contingencies", which is incorporated herein by
reference.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits.
Exhibit 99.1 Certification by Chief Executive Officer Pursuant to 18
U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002
Exhibit 99.2 Certification by Chief Financial Officer Pursuant to 18
U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002
(b) Reports on Form 8-K.
None.
SIGNATURES
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.
GENESIS ENERGY, L.P.
(A Delaware Limited Partnership)
By: GENESIS ENERGY, INC., as
General Partner
Date: November 12, 2002 By: /s/ Ross A. Benavides
------------------------------
Ross A. Benavides
Chief Financial Officer
25
CERTIFICATIONS PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
CERTIFICATION
I, Mark J. Gorman, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Genesis Energy,
L.P.;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: November 12, 2002
-----------------------------
/s/ Mark J. Gorman
---------------------------
Mark J. Gorman
President & Chief Executive Officer
26
CERTIFICATION
I, Ross A. Benavides, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Genesis Energy,
L.P.;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: November 12, 2002
-----------------------------
/s/ Ross A. Benavides
---------------------------
Ross A. Benavides
Chief Financial Officer