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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 June 30, 2001
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 23 pages
<page> 2
GENESIS ENERGY, L.P.
Form 10-Q
INDEX
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements Page
----
Consolidated Balance Sheets - June 30, 2001 and
December 31, 2000 3
Consolidated Statements of Operations for the Three and Six
Months Ended June 30, 2001 and 2000 4
Consolidated Statements of Cash Flows for the Six Months Ended
June 30, 2001 and 2000 5
Consolidated Statement of Partners' Capital for the Six Months
Ended June 30, 2001 6
Notes to Consolidated Financial Statements 7
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 14
Item 3. Quantitative and Qualitative Disclosures about Market Risk 21
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 22
Item 6. Exhibits and Reports on Form 8-K 22
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<page> 3
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
June 30, December 31,
2001 2000
-------- --------
ASSETS (Unaudited)
CURRENT ASSETS
Cash and cash equivalents $ 18,100 $ 5,508
Accounts receivable - trade 326,048 329,464
Inventories 115 994
Insurance receivable for pipeline spill costs 3,224 5,527
Other 12,269 9,111
-------- --------
Total current assets 359,756 350,604
FIXED ASSETS, at cost 114,011 113,715
Less: Accumulated depreciation (28,662) (25,609)
-------- --------
Net fixed assets 85,349 88,106
OTHER ASSETS, net of amortization 9,977 10,633
-------- --------
TOTAL ASSETS $455,082 $449,343
======== ========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Bank borrowings $ 21,000 $ 22,000
Accounts payable -
Trade 328,868 322,912
Related party 854 4,750
Accrued liabilities 18,372 16,546
-------- --------
Total current liabilities 369,094 366,208
COMMITMENTS AND CONTINGENCIES (Note 8)
MINORITY INTERESTS 521 520
PARTNERS' CAPITAL
Common unitholders, 8,624 units issued and
outstanding at June 30, 2001 and
December 31, 2000, respectively 83,755 80,960
General partner 1,718 1,661
-------- --------
Subtotal 85,473 82,621
Treasury Units, 1 units at June 30, 2001 and
December 31, 2000, respectively (6) (6)
-------- --------
Total partners' capital 85,467 82,615
-------- --------
TOTAL LIABILITIES AND PARTNERS' CAPITAL $455,082 $449,343
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
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<page> 4
<table>
GENESIS ENERGY, L.P.
STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
(Unaudited)
<caption>
Three Months Ended Six Months Ended
June 30, June 30,
2001 2000 2001 2000
-------- --------- ---------- ----------
REVENUES:
Gathering and marketing revenues
Unrelated parties $917,192 $1,161,271 $1,817,885 $2,159,701
Related parties - 29,820 25,900 29,820
Pipeline revenues 3,687 3,805 7,387 7,218
-------- --------- ---------- ----------
Total revenues 920,879 1,194,896 1,851,172 2,196,739
COST OF SALES:
Crude costs, unrelated parties 908,575 1,124,027 1,799,093 2,081,523
Crude costs, related parties - 60,598 28,700 95,379
Field operating costs 3,890 3,197 7,963 6,411
Pipeline operating costs 2,623 2,032 5,000 4,085
-------- --------- ---------- ----------
Total cost of sales 915,088 1,189,854 1,840,756 2,187,398
-------- --------- ---------- ----------
GROSS MARGIN 5,791 5,042 10,416 9,341
EXPENSES:
General and administrative 2,999 2,720 5,726 5,376
Depreciation and amortization 1,870 2,035 3,767 4,081
-------- --------- ---------- ----------
OPERATING INCOME (LOSS) 922 287 923 (116)
OTHER INCOME (EXPENSE):
Interest income 48 47 119 84
Interest expense (167) (354) (373) (702)
Change in fair value of derivatives 1,679 - 5,088 -
Gain on asset disposals 19 32 148 20
-------- --------- ---------- ----------
Income (loss) before minority interest
and cumulative effect of change in
accounting principle 2,501 12 5,905 (714)
Minority interest 1 2 1 (143)
-------- --------- ---------- ----------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT
OF CHANGE IN ACCOUNTING PRINCIPLE 2,500 10 5,904 (571)
Cumulative effect of adoption of
accounting principle, net of
minority interest effect - - 467 -
-------- --------- ---------- ----------
NET INCOME (LOSS) $ 2,500 $ 10 $ 6,371 $ (571)
======== ========= ========== ==========
NET INCOME (LOSS) PER COMMON
UNIT - BASIC AND DILUTED:
Income (loss) before cumulative
effect of change in accounting
principle $ 0.28 $ - $ 0.67 $ (0.06)
======== ========= ========== ==========
Cumulative effect of change in
accounting principle, net of
minority interest effect $ - $ - $ 0.05 $ -
======== ========= ========== ==========
Net Income (loss) $ 0.28 $ - $ 0.72 $ (0.06)
======== ========= ========== ==========
NUMBER OF COMMON UNITS
OUTSTANDING 8,624 8,623 8,624 8,623
======== ========= ========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
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5
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
Six Months Ended June 30,
2001 2000
-------- -------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ 6,371 $ (571)
Adjustments to reconcile net income to net cash
provided by (used in) operating activities -
Depreciation 3,108 3,422
Amortization of intangible assets 659 659
Cumulative effect of adoption of accounting
principle (467) -
Change in fair value of derivatives (5,088) -
Minority interests equity in earnings 1 (143)
Gain on sales of fixed assets (148) (20)
Other noncash charges 30 1,326
Changes in components of working capital -
Accounts receivable 3,416 (198,954)
Inventories 879 (111)
Other current assets (1,140) 1,401
Accounts payable 2,060 197,628
Accrued liabilities 7,351 (2,365)
-------- -------
Net cash provided by operating activities 17,032 2,272
-------- -------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (351) (365)
Change in other assets (3) 6
Proceeds from sales of assets 433 40
-------- -------
Net cash provided by (used in) investing activities 79 (319)
-------- -------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net (repayments) borrowings under Loan Agreement (1,000) 1,100
Distributions to common unitholders (3,449) (8,625)
Distributions to general partner (70) (176)
Issuance of additional partnership interests - 4,800
Purchase of treasury units - (42)
-------- -------
Net cash used in financing activities (4,519) (2,943)
-------- -------
Net increase (decrease) in cash and cash equivalents 12,592 (990)
Cash and cash equivalents at beginning of period 5,508 6,664
-------- -------
Cash and cash equivalents at end of period $ 18,100 $ 5,674
======== =======
The accompanying notes are an integral part of these consolidated financial
statements.
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<page> 6
<table>
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
(In thousands)
(Unaudited)
<caption>
Partners' Capital
--------------------------------------
Common General Treasury
Unitholders Partner Units Total
--------- -------- ----- ---------
Partners' capital at December 31, 2000 $ 80,960 $ 1,661 $ (6) $ 82,615
Net income for the six months ended
June 30, 2001 6,244 127 - 6,371
Distributions during the six months
ended June 30, 2001 (3,449) (70) - (3,519)
--------- -------- ----- ---------
Partners' capital at June 30, 2001 $ 83,755 $ 1,718 $ (6) $ 85,467
========= ======== ===== =========
The accompanying notes are an integral part of these consolidated financial
statements.
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<page> 7
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Formation and Offering
In December 1996, Genesis Energy, L.P. ("GELP" or the "Partnership")
completed an initial public offering of 8.6 million Common Units at $20.625 per
unit, representing limited partner interests in GELP of 98%. Genesis Energy,
L.L.C. (the "General Partner") serves as general partner of GELP and its
operating limited partnership, Genesis Crude Oil, L.P. Genesis Crude Oil, L.P.
has two subsidiary limited 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 collectively as GCOLP. The General Partner
owns a 2% general partner interest in GELP.
Transactions at Formation
At the closing of the offering, GELP contributed the net proceeds of the
offering to GCOLP in exchange for an 80.01% general partner interest in GCOLP.
With the net proceeds of the offering, GCOLP purchased a portion of the crude
oil gathering, marketing and pipeline operations of Howell Corporation
("Howell") and made a distribution to Basis Petroleum, Inc. ("Basis") in
exchange for its conveyance of a portion of its crude oil gathering and
marketing operations. GCOLP issued an aggregate of 2.2 million subordinated
limited partner units ("Subordinated OLP Units") to Basis and Howell to obtain
the remaining operations.
Basis' Subordinated OLP Units and its interest in the General Partner
were transferred to its then parent, Salomon Smith Barney Holdings Inc.
("Salomon") in May 1997. In February 2000, Salomon acquired Howell's interest
in the General Partner. Salomon now owns 100% of the General Partner.
Restructuring
On December 7, 2000, the Partnership was restructured, resulting in the
reduction of the minimum quarterly distribution on Common Units to $0.20 per
unit; the reduction of the distribution thresholds before the General Partner
is entitled to incentive compensation payments; the elimination of the
Subordinated OLP Units in GCOLP; and the elimination of the outstanding
additional partnership interests, or APIs, issued to Salomon in exchange for
its distribution support.
2. Basis of Presentation
The accompanying consolidated financial statements and related notes
present the financial position as of June 30, 2001 and December 31, 2000 for
GELP, the results of operations for the three and six months ended June 30,
2001 and 2000, cash flows for the six months ended June 30, 2001 and 2000 and
changes in partners' capital for the six months ended June 30, 2001.
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, 2000 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 June 30, 2001 and 2000 was
8,624,000 and 8,623,000, respectively. For the 2001 and 2000 six month
periods, the weighted average number of Common Units outstanding was 8,624,000
and 8,623,000, 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.
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<page> 8
3. New Accounting Pronouncement
In July 2001, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards (SFAS) No. 142, "Goodwill and Other Intangible
Assets." This statement requires that goodwill no longer be amortized to
earnings, but instead be reviewed for impairment. The standard is effective
for fiscal years beginning on January 1, 2002. The Partnership is currently
evaluating the effect on its financial statements of adopting SFAS No. 142.
The Partnership currently records amortization of its goodwill of $0.5 million
annually.
4. Business Segment and Customer Information
Based on its management approach, the Partnership believes that all of its
material operations revolve around the gathering, transportation and marketing
of crude oil, and it currently reports its operations, both internally and
externally, as a single business segment. No customer accounted for more than
10% of the Partnership's revenues in any period.
5. Credit Resources
GCOLP entered into credit facilities with Salomon (collectively, the
"Credit Facilities"), pursuant to a Master Credit Support Agreement. GCOLP's
obligations under the Credit Facilities are secured by its receivables,
inventories, general intangibles and cash.
Guaranty Facility
Salomon is providing a Guaranty Facility through December 31, 2001 in
connection with the purchase, sale and exchange of crude oil by GCOLP. The
aggregate amount of the Guaranty Facility is limited to $300 million for the
year ending December 31, 2001 (to be reduced in each case by the amount of any
obligation to a third party to the extent that such third party has a prior
security interest in the collateral). GCOLP pays a guarantee fee to Salomon.
At June 30, 2001, the aggregate amount of obligations covered by guarantees was
$171 million, including $104 million in payable obligations and $67 million of
estimated crude oil purchase obligations for July 2001.
The Master Credit Support Agreement contains various restrictive and
affirmative covenants including (i) restrictions on indebtedness other than (a)
pre-existing indebtedness, (b) indebtedness pursuant to Hedging Agreements (as
defined in the Master Credit Support Agreement) entered into in the ordinary
course of business and (c) indebtedness incurred in the ordinary course of
business by acquiring and holding receivables to be collected in accordance
with customary trade terms, (ii) restrictions on certain liens, investments,
guarantees, loans, advances, lines of business, acquisitions, mergers,
consolidations and sales of assets and (iii) compliance with certain risk
management policies, audit and receivable risk exposure practices and cash
management practices as may from time to time be revised or altered by Salomon
in its sole discretion.
Pursuant to the Master Credit Support Agreement, GCOLP is required to
maintain (a) Consolidated Tangible Net Worth of not less than $50 million, (b)
Consolidated Working Capital of not less than $1 million, (c) a ratio of its
Consolidated Current Liabilities to Consolidated Working Capital plus net
property, plant and equipment of not more than 7.5 to 1, and (d) a ratio of
Consolidated Total Liabilities to Consolidated Tangible Net Worth of not more
than 10.0 to 1 (as such terms are defined in the Master Credit Support
Agreement). The Partnership was in compliance with the provisions of this
agreement at June 30, 2001.
An Event of Default could result in the termination of the Credit
Facilities at the discretion of Salomon. Significant Events of Default include
(a) a default in the payment of (i) any principal on any payment obligation
under the Credit Facilities when due or (ii) interest or fees or other amounts
within two business days of the due date, (b) the guaranty exposure amount
exceeding the maximum credit support amount for two consecutive calendar
months, (c) failure to perform or otherwise comply with any covenants contained
in the Master Credit Support Agreement if such failure continues unremedied for
a period of 30 days after written notice thereof and (d) a material
misrepresentation in connection with any loan, letter of credit or guarantee
issued under the Credit Facilities. Removal of the General Partner will result
in the termination of the Credit Facilities and the release of all of Salomon's
obligations thereunder.
-8-
<page> 9
Working Capital Facility
Prior to June 2000, GCOLP had a revolving credit/loan agreement ("Loan
Agreement") with Bank One, Texas, N.A. In June 2000, the Loan Agreement was
replaced with a secured revolving credit facility ("Credit Agreement") with BNP
Paribas. The Credit Agreement provides for loans or letters of credit in the
aggregate not to exceed the greater of $25 million or the Borrowing Base (as
defined in the Credit Agreement).
During 2000, loans bore interest at a rate chosen by GCOLP which would be
one or more of the following: (a) a rate based on LIBOR plus 1.4% or (b) BNP
Paribas' prime rate minus 1.0%. In 2001, the Credit Agreement was amended to
change the interest rates to LIBOR plus 2.25% or BNP Paribas prime rate minus
0.875%.
The Credit Agreement expires on the earlier of (a) February 28, 2003 or
(b) 30 days prior to the termination of the Master Credit Support Agreement
with Salomon. As the Master Credit Support Agreement terminates on December
31, 2001, the Credit Agreement with BNP Paribas is currently scheduled to
expire on November 30, 2001.
The Credit Agreement is collateralized by the accounts receivable,
inventory, cash accounts and margin accounts of GCOLP, subject to the terms of
an Intercreditor Agreement between BNP Paribas and Salomon. There is no
compensating balance requirement under the Credit Agreement. A commitment fee
of 0.35% on the available portion of the commitment is provided for in the
agreement. Material covenants and restrictions include the following: (a)
maintain a Current Ratio (calculated after the exclusion of debt under the
Credit Agreement from current liabilities) of 1.0 to 1.0; (b) maintain a
Tangible Capital Base (as defined in the Credit Agreement) in GCOLP of not less
than $65 million; and (c) maintain a Maximum Leverage Ratio (as defined in the
Credit Agreement) of not more than 7.5 to 1.0. Additionally, the Credit
Agreement imposes restrictions on the ability of GCOLP to sell its assets,
incur other indebtedness, create liens and engage in mergers and acquisitions.
The Partnership was in compliance with the ratios of the Credit Agreement at
June 30, 2001.
At June 30, 2001, the Partnership had $21.0 million of loans outstanding
under the Credit Agreement. The Partnership had no letters of credit
outstanding at June 30, 2001. At June 30, 2001, $4.0 million was available to
be borrowed under the Credit Agreement.
Credit Availability
At June 30, 2001, the Partnership's consolidated balance sheet reflected
a working capital deficit of $9.3 million. This working capital deficit
combined with the short-term nature of both the Guaranty Facility with Salomon
and the Credit Agreement with BNP Paribas could have a negative impact on the
Partnership. Some counterparties use the balance sheet and the nature of
available credit support as a basis for determining the level of credit support
demanded from the Partnership as a condition of doing business. Increased
demands for credit support beyond the maximum credit limitations and higher
credit costs may 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 for
distributions.
There can be no assurance of the availability or the terms of credit for
the Partnership. At this time, Salomon does not intend to provide guarantees
or other credit support after the credit support period expires in December
2001. In addition, if the General Partner is removed without its consent,
Salomon's credit support obligations will terminate. Further, Salomon's
obligations under the Master Credit Support Agreement may be transferred or
terminated early subject to certain conditions.
Management of the Partnership intends to replace the Guaranty Facility
and the Credit Agreement with a working capital/letter of credit facility with
one or more lenders prior to November 30, 2001. Due to changes in the credit
market resulting from consolidation of the banking industry and weakness in the
overall economy, reduced availability of credit to the crude gathering and
marketing segment of the energy industry, and the anticipated cost of a third-
party credit facility, management of the General Partner believes that
replacement of its $300 million Master Credit Support Agreement is highly
unlikely. Management expects to replace the $300 million Master Credit Support
Agreement and the $25 million Credit Agreement with a facility totaling
approximately $100 million
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<page> 10
with third-party financial institutions providing for letters of credit and
working capital borrowings. As a result, management of the Partnership is
making changes to its business operations as the Partnership transitions from
the existing credit support to the use of letters of credit from third-party
financial institutions. Any changes to the Partnership's operations made for
this purpose may result in decreased total gross margins and less Available
Cash for distribution to its unitholders. No assurance can be made that the
Partnership will be able to replace the existing facilities with a third-party
credit facility. Additionally, no assurance can be made that the Partnership
will be able to generate Available Cash at a level that will meet its current
Minimum Quarterly Distribution target.
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 on December 7, 2000, the
minimum quarterly distribution ("MQD") for each quarter has been reduced to
$0.20 per unit beginning with the distribution for the fourth quarter of 2000,
which was paid in February 2001.
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.
6. 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.
Sales and Purchases of Crude Oil
A summary of sales to and purchases from related parties of crude oil is
as follows (in thousands).
Six Months Six Months
Ended Ended
June 30, June 30,
2001 2000
--------- ---------
Sales to affiliates $ 25,900 $ 29,820
Purchases from affiliates $ 28,700 $ 95,379
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 $9,422,000 and $8,408,000 for the six months ended June 30,
2001 and 2000, respectively.
Guaranty Facility
As discussed in Note 5, Salomon provides a Guaranty Facility to the
Partnership. For the six months ended June 30, 2001 and 2000, the Partnership
paid Salomon $813,000 and $749,000, respectively, for guarantee fees under the
Guaranty Facility.
7. Supplemental Cash Flow Information
Cash received by the Partnership for interest was $140,000 and $76,000 for
the six months ended June 30, 2001 and 2000, respectively. Payments of
interest were $283,000 and $835,000 for the six months ended June 30, 2001 and
2000, respectively.
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<page> 11
8. 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", 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.
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. In general, SFAS No. 133
requires that at the date of initial adoption, 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, recognition of the Partnership's derivatives resulted
in a gain of $0.5 million, which has been recognized in the consolidated
statement of operations as the cumulative effect of adopting SFAS No. 133. The
actual cumulative effect adjustment differs from the estimate reported in the
Partnership's Form 10-K for the year ended December 31, 2000 due to a
refinement in the manner in which the fair value of the Partnership's
derivatives was determined.
The fair value of the Partnership's net asset for derivatives had increased
by $5.1 million for the six months ended June 30, 2001, which is reported as a
gain in the consolidated statement of operations under the caption "Change in
fair value of derivatives". The consolidated balance sheet includes $10.7
million in other current assets and $5.1 million in accrued liabilities as a
result of recording the fair value of derivatives. The Partnership has not
designated any of its derivatives as hedging instruments.
9. Contingencies
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
determined that such exposure is not material to its consolidated financial
position, results of operations or cash flows.
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 the duties of care and loyalty owed by the
defendants to the purported class in connection with making a proposal for
restructuring. Management of the General Partner believes that the complaint
is without merit and intends to vigorously defend the action.
Crude Oil Contamination and Pennzoil Lawsuit
In the first quarter of 2000, the Partnership purchased crude oil from a
third party that was subsequently determined to contain organic chlorides.
These barrels were delivered into the Partnership's Texas pipeline system and
potentially contaminated 24,000 barrels of oil held in storage and 44,000
barrels of oil in the pipeline. The
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<page> 12
Partnership has disposed of all contaminated crude. The Partnership incurred
costs associated with transportation, testing and consulting in the amount of
$230,000 as of June 30, 2001.
The Partnership has recorded a receivable for $230,000 to reflect the
expected recovery of the accrued costs from the third party. The third party
has provided the Partnership with evidence that it has sufficient resources to
cover the total expected damages incurred by the Partnership. Management of
the Partnership believes that it will recover any damages incurred from the
third party.
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"), seeks 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. 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. Both plaintiffs claim
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.
Pipeline 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 Partnership responded to this incident immediately, deploying crews
to evaluate, clean up and monitor the spilled oil. The spill was cleaned up,
with ongoing monitoring and reduced clean-up activity expected to continue for
an undetermined period of time. 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.
The estimated cost of the spill clean-up is expected to be $19.5 million.
This amount includes actual clean-up costs and estimates for ongoing
maintenance and settlement of potential liabilities to landowners in connection
with the spill. The incident was reported to insurers. At June 30, 2001,
$18.2 million had been paid to vendors and claimants for spill costs, and $1.3
million was included in accrued liabilities for estimated future expenditures.
Current assets included $1.2 million of expenditures submitted and approved by
insurers but not yet reimbursed, $0.7 million for expenditures not yet
submitted to insurers and $1.3 million for expenditures not yet incurred or
billed to the Partnership. At June 30, 2001, $16.3 million in reimbursements
had been received from insurers.
As a result of this crude oil spill, certain federal and state regulatory
agencies may impose fines and penalties that would not be covered by insurance.
At this time, it is not possible to predict whether the Partnership will be
fined, the amount of such fines or whether such governmental agencies will
prevail in imposing such fines.
The segment of the Mississippi System where the spill occurred has been
shut down and will not be restarted until regulators give their approval. In
2001, the Partnership has started to perform testing of the affected segment of
the pipeline at an estimated cost of $0.2 million to determine a course of
action to restart the system. Regulatory authorities may require specific
testing or changes to the pipeline before allowing the Partnership to restart
the system. At this time, it is unknown whether there will be any required
testing or changes and the related cost of that testing or changes. Subject to
the results of testing and regulatory approval, the Partnership intends to
restart this segment of the Mississippi System during the early part of 2002.
If Management of the Partnership determines that the costs of additional
testing or changes are too high, that segment of the system may not be
restarted. If this part of the Mississippi System is taken out of service,
annual tariff revenues would be reduced by approximately $0.3 million from the
2000 level and the net book value of that portion of the pipeline would be
written down to its net realizable value, resulting in a non-cash write-off of
approximately $5.7 million.
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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
financial position, results of operations or cash flows of the Partnership.
10. Distributions
On July 10, 2001, the Board of Directors of the General Partner declared a
cash distribution of $0.20 per Unit for the quarter ended June 30, 2001. The
distribution will be paid August 14, 2001, to the General Partner and all
Common Unitholders of record as of the close of business on July 31, 2001.
11. Subsequent Event
On August 10, 2001, the Partnership announced that Salomon has entered into
an agreement to sell its ownership of the General Partner to GEL Acquisition
Partnership. The transaction is expected to close during the fourth quarter of
2001.
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GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
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, Mississippi, New
Mexico, Kansas and Oklahoma. The following review of the results of operations
and financial condition should be read in conjunction with the 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 Six Months Ended
June 30, June 30,
2001 2000 2001 2000
-------- -------- -------- --------
Gross margin
Gathering and marketing $ 4,727 $ 3,269 $ 8,029 $ 6,208
Pipeline $ 1,064 $ 1,773 $ 2,387 $ 3,133
General and administrative expenses $ 2,999 $ 2,720 $ 5,726 $ 5,376
Depreciation and amortization $ 1,870 $ 2,035 $ 3,767 $ 4,081
Operating income (loss) $ 922 $ 287 $ 923 $ (116)
Interest income (expense), net $ (119) $ (307) $ (254) $ (618)
Change in fair value of derivatives $ 1,679 $ - $ 5,088 $ -
Gain on asset disposals $ 19 $ 32 $ 148 $ 20
Barrels per day
Wellhead 83,916 101,702 88,480 101,977
Bulk and exchange 293,589 361,973 281,085 325,775
Pipeline 87,114 92,493 88,280 90,333
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, we seek to purchase and sell crude
oil at points along the Distribution Chain where we can achieve positive gross
margins. We generally purchase crude oil at prevailing prices from producers
at the wellhead under short-term contracts. We then transport the crude along
the Distribution Chain for sale to or exchange with customers. In addition to
purchasing crude at the wellhead, Genesis purchases crude oil in bulk at major
pipeline terminal points and enters into exchange transactions with third
parties. We generally enter 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, we often exchange one grade of crude oil
for another to maximize our margins or meet our contract delivery requirements.
These bulk and exchange transactions are characterized by large volumes and
narrow profit margins on purchases and sales.
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<page> 15
Generally, as we purchase crude oil, we simultaneously establish a margin
by selling crude oil for physical delivery to third party users, such as
independent refiners or major oil companies, or by entering into a future
delivery obligation with respect to futures contracts on the NYMEX. Through
these transactions, we seek 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 our policy not to hold crude
oil, futures contracts or other derivative products for the purpose of
speculating on crude oil price changes.
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.
Six Months Ended June 30, 2001 Compared with Six Months Ended June 30, 2000
Gross margin from gathering and marketing operations was $8.0 million for
the six months ended June 30, 2001, as compared to $6.2 million for the six
months ended June 30, 2000.
The factors affecting gross margin were:
* a decrease of 14 percent in wellhead, bulk and exchange purchase
volumes between 2000 and 2001, resulting in a decrease in gross margin
of $2.0 million;
* a 40 percent 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, which increased gross margin by $4.8 million;
* an increase of $0.1 million in credit costs due primarily to an
increase in July 2000 in the guaranty fee;
* an increase of $1.6 million in field operating costs, primarily from a
$0.3 million increase in payroll and benefits costs, $0.2 million
increase in fuel costs, $0.3 million decrease in repair costs and $1.4
million increase in rental costs due to the replacement of the
tractor/trailer fleet with a leased fleet in the fourth quarter of
2000. The increased payroll-related costs and fuel costs can be
attributed to an approximate 8% increase in the number of barrels
transported by the Partnership in trucks, and
* an unrealized loss recorded in the 2000 period of $0.6 million related
to written option contracts.
Pipeline gross margin was $2.4 million for the six months ended June 30,
2001, as compared to $3.1 million for the six months in 2000. The factors
affecting pipeline gross margin were:
* an increase in revenues from sales of pipeline loss allowance barrels
of $0.4 million as a result of an increase in the amount of pipeline
loss allowance that the Partnership is allowed to collect under the
terms of its tariffs and higher crude prices;
* a decrease of 3 percent in the average tariff on shipments resulting
in a decrease in revenue of $0.2 million; and
* an increase in pipeline operating costs of $0.9 million in the 2001
period primarily due to increased expenditures in areas of spill
prevention.
General and administrative expenses increased $0.4 million between the
2001 and 2000 six month periods. This increase is attributable to increases in
the following areas: $0.7 million in salary and benefits and $0.3 million in
professional services, offset by a decrease of $0.6 million in restricted unit
expense.
Depreciation and amortization expense declined $0.3 million between the
six month periods. This decrease is attributable primarily to the
Partnership's change in late 2000 from owning its tractor/trailer fleet to
leasing the vehicles.
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<page> 16
Interest expense decreased $0.3 million due to lower average debt
outstanding, offset by higher interest rates under the Paribas facility in 2001
than the Bank One facility in 2000. The average interest rate increased 1.49%,
resulting in an increase of $0.1 million of interest, while the average debt
outstanding declined by $10.9 million, resulting in a decrease in interest
expense of $0.4 million. .
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 June 30, 2001 Compared with Three Months Ended June 30,
2000
Gross margin from gathering and marketing operations was $4.7 million for
the quarter ended June 30, 2001, as compared to $3.3 million for the quarter
ended June 30, 2000.
The factors affecting gross margin were:
* a decrease of 19 percent in wellhead, bulk and exchange purchase
volumes between 2000 and 2001, resulting in a decrease in gross margin
of $1.4 million;
* a 43 percent 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, which increased gross margin by $2.7 million;
* an increase of $0.7 million in field operating costs, primarily from a
$0.1 million increase in payroll and benefits costs, and $0.7 million
increase in rental costs due to the replacement of the tractor/trailer
fleet with a leased fleet in the fourth quarter of 2000, offset by a
decrease of $0.2 million in repairs due to the new fleet. The
increased payroll-related costs can be attributed to an approximate 4%
increase in the number of barrels transported by the Partnership in
trucks, and
* an unrealized loss recorded in the 2000 period of $0.8 million related
to written option contracts.
Pipeline gross margin was $1.1 million for the quarter ended June 30,
2001, as compared to $1.8 million for the second quarter of 2000. The factors
affecting pipeline gross margin were:
* a decrease in throughput of 4 percent between the two periods,
resulting in a revenue decrease of $0.1 million;
* an increase in revenues from sales of pipeline loss allowance barrels
of $0.1 million as a result of an increase in the amount of pipeline
loss allowance that the Partnership is allowed to collect under the
terms of its tariffs and higher crude prices;
* a decrease of 4 percent in the average tariff on shipments resulting
in a decrease of $0.1 million in revenue; and
* an increase in pipeline operating costs of $0.6 million in the 2001
period primarily due to increased expenditures in areas of spill
prevention.
General and administrative expenses increased $0.3 million during the
three months ended June 30, 2001 as compared to the same period in 2000. The
primary factors in this increase were an increase in salaries and benefits of
$0.4 million and an increase in professional fees of $0.2 million, offset by a
reduction in restricted unit expense of $0.3 million.
Interest costs were $0.2 million lower in the 2001 quarter due primarily
to lower average debt outstanding. The average debt outstanding decreased by
$9.7 million between the two periods.
Liquidity and Capital Resources
Cash Flows
Cash flows provided by operating activities were $17.0 million for the
six months ended June 30, 2001. In the 2000 six-month period, cash flows
provided by operating activities were $2.3 million. The change between the
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<page> 17
two periods results primarily from decreased amounts held by brokers as margin
deposits and variations in the timing of payments for the Mississippi crude oil
spill clean-up and the related reimbursements by insurers.
For the six months ended June 30, 2001 and 2000, cash flows provided by
investing activities were $0.1 million. In 2001, the Partnership received $0.4
million from the sale of surplus assets, most of which was used for property
and equipment additions related primarily to pipeline operations. In 2000, the
Partnership added $0.3 million of assets, primarily for pipeline operations.
Cash flows used in financing activities by the Partnership during the
first six months of 2001 totaled $4.5 million. Distributions paid to the
common unitholders and the general partner totaled $3.5 million. The
Partnership borrowed $1.0 million under its Working Capital Facility. In the
2000 period, cash flows used in financing activities totaled $2.9 million. The
Partnership obtained funds by borrowing $1.1 million and received $4.8 million
from the issuance of APIs to Salomon. Distributions to the common unitholders
and the general partner totaled $8.8 million.
Working Capital and Credit Resources
As discussed in Note 4 of the Notes to Condensed Consolidated Financial
Statements, the Partnership has a Guaranty Facility with Salomon through
December 31, 2001, and a $25 million Credit Agreement with BNP Paribas for
working capital purposes. The Credit Agreement expires on the earlier of (a)
February 28, 2003 or (b) 30 days prior to the termination of the Master Credit
Support Agreement with Salomon. As the Master Credit Support Agreement
terminates on December 31, 2001, the Credit Agreement with BNP Paribas is
currently scheduled to expire on November 30, 2001.
At June 30, 2001, the Partnership's consolidated balance sheet reflected
a working capital deficit of $9.3 million. This working capital deficit
combined with the short-term nature of both the Guaranty Facility with Salomon
and the Credit Agreement with BNP Paribas could have a negative impact on the
Partnership. Some counterparties use the balance sheet and the nature of
available credit support as a basis for determining credit support demanded
from the Partnership as a condition of doing business. Increased demands for
credit support beyond the maximum credit limitations may 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.
There can be no assurance of the availability or the terms of credit for
the Partnership. At this time, Salomon does not intend to provide guarantees
or other credit support after the credit support period expires in December
2001. In addition, if the General Partner is removed without its consent,
Salomon's credit support obligations will terminate. Further, Salomon's
obligations under the Master Credit Support Agreement may be transferred or
terminated early subject to certain conditions. Management of the Partnership
intends to replace the Guaranty Facility and the Credit Agreement with a
working capital/letter of credit facility with one or more lenders prior to
November 30, 2001. Based on the marketplace for credit facilities, the
Partnership's financial performance and the anticipated cost of replacing the
Master Credit Support Agreement, management of the General Partner expects to
obtain a replacement facility totaling approximately $100 million, providing
for letters of credit and working capital borrowings. See the discussion below
on "Other Matters - Current Business Conditions and Outlook" regarding the
potential effects of a smaller credit facility on the Partnership's business
activities.
Other Matters
Current Business Conditions and Outlook
Changes in the price of crude oil impact gathering and marketing and
pipeline gross margins to the extent that oil producers adjust production
levels. Short-term and long-term price trends impact the amount of cash flow
that producers have available to maintain existing production and to invest in
new reserves, which in turn impacts the amount of crude oil that is available
to be gathered and marketed by the Partnership and its competitors.
Although crude oil prices have increased significantly from the $12 per
barrel in January 1999, U.S. onshore crude oil production volumes have not
improved. Producers have been focused on drilling for natural gas.
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<page> 18
Based on the limited improvement in the number of rigs drilling for oil,
management of the General Partner believes that oil production in its primary
areas of operation is likely to continue to decrease. Although there has been
some increase since 1999 in the number of drilling and workover rigs being
utilized in the Partnership's primary areas of operation, management of the
General Partner believes that this activity is more likely to have the effect
of reducing the rate of decline rather than meaningfully increasing wellhead
volumes in its operating areas for the remainder of 2001 and 2002.
The Partnership's improved volumes in 2000 and 2001 compared to 1999 were
primarily due to obtaining existing production by paying higher prices for the
production than the previous purchaser. Increased volumes obtained through
competition based on price for existing production generally result in
incrementally lower margins per barrel.
As crude oil prices rise, the Partnership's utilization of, and cost of
credit under, the Guaranty Facility increases with respect to the same volume
of business. Additionally, as prices rise, the Partnership may have to
increase the amount of its Credit Agreement in order to have funds available to
meet margin calls on the NYMEX and to fund inventory purchases.
Due to changes in the credit market resulting from consolidation of the
banking industry and weakness in the overall economy, reduced availability of
credit to the crude gathering and marketing segment of the energy industry, and
the anticipated cost of a third-party credit facility, management of the
General Partner believes that replacement of its $300 million Master Credit
Support Agreement is highly unlikely. Management expects to replace the $300
million Master Credit Support Agreement and the $25 million Credit Agreement
with a facility totaling approximately $100 million with third-party financial
institutions providing for letters of credit and working capital borrowings.
As a result, management of the Partnership is reviewing making changes to its
business operations as the Partnership transitions from the existing credit
support to the use of letters of credit from third-party financial
institutions. Any changes to the Partnership's operations made for this
purpose may result in decreased total gross margins and less Available Cash for
distribution to its unitholders. No assurance can be made that the Partnership
will be able to replace the existing facilities with a third-party credit
facility. Additionally, no assurance can be made that the Partnership will be
able to generate Available Cash at a level that will meet its current Minimum
Quarterly Distribution target.
Management of the General Partner is continuing its efforts to explore
strategic opportunities to grow the asset base of the Partnership in order to
increase distributions to the unitholders. Management believes that one of the
most effective ways to achieve that goal would be to enter into transactions
with a strategic partner who could contribute assets to the Partnership.
Management intends to continue its efforts to implement strategic transactions
to grow the Partnership's asset base taking into account the potential for and
timing of reductions in Available Cash that may result from the Partnership's
transition to the use of letters of credit from third-party financial
institutions. No assurance can be made that the Partnership will be able to
grow the Partnership's asset base to offset reductions in gross margin and
Available Cash that may result from the Partnership's transition to a credit
facility with third party financial institutions.
Adoption of FAS 133
On January 1, 2001, the Partnership adopted the provisions of SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities", 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.
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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. In general, SFAS No. 133
requires that at the date of initial adoption, 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, recognition of the Partnership's derivatives resulted
in a gain of $0.5 million, which has been recognized in the consolidated
statement of operations as the cumulative effect of adopting SFAS No. 133. The
actual cumulative effect adjustment differs from the estimate reported in the
Partnership's Form 10-K for the year ended December 31, 2000 due to a
refinement in the manner in which the fair value of the Partnership's
derivatives was determined.
The fair value of the Partnership's net asset for derivatives had
increased by $5.1 million for the six months ended June 30, 2001, which is
reported as a gain in the consolidated statement of operations under the
caption "Change in fair value of derivatives". The Partnership has not
designated any of its derivatives as hedging instruments.
New Accounting Standard
In July 2001, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards (SFAS) No. 142, "Goodwill and Other
Intangible Assets." This statement requires that goodwill no longer be
amortized to earnings, but instead be reviewed for impairment. The standard is
effective for fiscal years beginning on January 1, 2002. The Partnership is
currently evaluating the effect on its financial statements of adopting SFAS
No. 142. The Partnership currently records amortization of its goodwill of
$0.5 million annually.
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 Partnership responded to this incident immediately, deploying crews
to evaluate, clean up and monitor the spilled oil. The spill was cleaned up,
with ongoing monitoring and reduced clean-up activity expected to continue for
an undetermined period of time. 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.
The estimated cost of the spill clean-up is expected to be $19.5 million.
This amount includes actual clean-up costs and estimates for ongoing
maintenance and settlement of potential liabilities to landowners in connection
with the spill. The incident was reported to insurers. At June 30, 2001,
$18.2 million had been paid to vendors and claimants for spill costs, and $1.3
million was included in accrued liabilities for estimated future expenditures.
Current assets included $1.2 million of expenditures submitted and approved by
insurers but not yet reimbursed, $0.7 million for expenditures not yet
submitted to insurers and $1.3 million for expenditures not yet incurred or
billed to the Partnership. At June 30, 2001, $16.3 million in reimbursements
had been received from insurers.
As a result of this crude oil spill, certain federal and state regulatory
agencies may impose fines and penalties that would not be covered by insurance.
At this time, it is not possible to predict whether the Partnership will be
fined, the amount of such fines or whether such governmental agencies will
prevail in imposing such fines. See Note 19 of Notes to Consolidated Financial
Statement.
The segment of the Mississippi System where the spill occurred has been
shut down and will not be restarted until regulators give their approval. In
2001, the Partnership has started to perform testing of the affected segment of
the pipeline at an estimated cost of $0.2 million to determine a course of
action to restart the system. Regulatory authorities may require specific
testing or changes to the pipeline before allowing the Partnership to restart
the system. At this time, it is unknown whether there will be any required
testing or changes and the related cost of that
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<page> 20
testing or changes. Subject to the results of testing and regulatory approval,
the Partnership intends to restart this segment of the Mississippi System
during the early part of 2002.
If Management of the Partnership determines that the costs of additional
testing or changes are too high, that segment of the system may not be
restarted. If this part of the Mississippi System is taken out of service,
annual tariff revenues would be reduced by approximately $0.3 million from the
2000 level and the net book value of that portion of the pipeline would be
written down to its net realizable value, resulting in a non-cash write-off of
approximately $5.7 million.
Crude Oil Contamination
In the first quarter of 2000, the Partnership purchased crude oil from a
third party that was subsequently determined to contain organic chlorides.
These barrels were delivered into the Partnership's Texas pipeline system and
potentially contaminated 24,000 barrels of oil held in storage and 44,000
barrels of oil in the pipeline. The Partnership has disposed of all
contaminated crude. The Partnership incurred costs associated with
transportation, testing and consulting in the amount of $230,000 as of June 30,
2001.
The Partnership has recorded a receivable of $230,000 to reflect the
expected recovery of the accrued costs from the third party. The third party
has provided the Partnership with evidence that it has sufficient resources to
cover the total expected damages incurred by the Partnership. Management of
the Partnership believes that it will recover any damages incurred from the
third party.
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"), seeks 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. 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. Both plaintiffs claim
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.
Subsequent Event
On August 10, 2001, the Partnership announced that Salomon has entered
into an agreement to sell its ownership of the General Partner to GEL
Acquisition Partnership. The transaction is expected to close during the
fourth quarter of 2001.
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. 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;
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<page> 21
* credit requirements by the counterparties;
* the Partnership's ability to replace the credit support from Salomon and
the working capital facility with BNP Paribas with another facility;
* 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;
* 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. Quantitative and Qualitative 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.
The Partnership utilizes New York Mercantile Exchange ("NYMEX") commodity based
futures contracts, forward contracts, swap agreements and option contracts to
hedge its exposure to these market price fluctuations. Management believes the
hedging program has been effective in minimizing overall price risk. At June
30, 2001, the Partnership used futures and forward contracts in its hedging
program with the latest contract being settled in July 2002. Information about
these contracts is contained in the table set forth below.
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<page> 22
Sell (Short) Buy (Long)
Contracts Contracts
---------- ----------
<s> <c> <c>
Crude Oil Inventory:
Volume (1,000 bbls) 120
Carrying value (in thousands) $ 3,347
Fair value (in thousands) $ 3,202
Commodity Futures Contracts
Contract volumes (1,000 bbls) 14,606 14,181
Weighted average price per bbl $ 27.32 $ 27.22
Contract value (in thousands) $ 399,001 $ 385,970
Fair value (in thousands) $ 381,810 $ 370,159
Commodity Forward Contracts:
Contract volumes (1,000 bbls) 4,404 5,004
Weighted average price per bbl $ 27.13 $ 27.42
Contract value (in thousands) $ 119,474 $ 137,214
Fair value (in thousands) $ 112,878 $ 130,109
Commodity Option Contracts:
Contract volumes (1,000 bbls) 9,980 <F1> 5,580 <F1>
Weighted average strike price per bbl $ 1.03 $ 2.89
Contract value (in thousands) $ 2,774 $ 1,656
Fair value (in thousands) $ 1,666 $ 1,196
<FN>
<F1>
Based on market prices as of June 30, 2001, for option contracts, 3.3 million
barrels attributable to sale contracts and 3.6 million barrels attributable to
buy contracts would have been exercisable.
</FN>
The table above presents notional amounts in barrels, the weighted
average contract price, total contract amount in U.S. dollars and total fair
value amount in U.S. dollars. Fair values were determined by using the
notional amount in barrels multiplied by the June 30, 2001 closing prices of
the applicable NYMEX futures contract adjusted for location and grade
differentials, as necessary.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
See Part I. Item 1. Note 8 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 10.1 Fourteenth Amendment dated May 24, 2001 to the Master
Credit Support Agreement
Exhibit 10.2 Severance Agreement between Genesis Energy, L.L.C. and
John P. vonBerg
(b) Reports on Form 8-K.
None.
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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, L.L.C., as
General Partner
Date: August 13, 2001 By: /s/ Ross A. Benavides
-----------------------------
Ross A. Benavides
Chief Financial Officer
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