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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-Q
[X] QUARTERLY REPORT UNDER SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 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 durin
g the preceding 12 months (or for such shorter period that the registrant was re
quired to file such reports), and (2) has been subject to such filing requiremen
ts for the past 90 days.
Yes X No
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This report contains 20 pages
GENESIS ENERGY, L.P.
Form 10-Q
INDEX
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements Page
----
Consolidated Balance Sheets - March 31, 2001 and
December 31, 2000 3
Consolidated Statements of Operations for the Three Months
Ended March 31, 2001 and 2000 4
Consolidated Statements of Cash Flows for the Three Months
Ended March 31, 2001 and 2000 5
Consolidated Statement of Partners' Capital for the Three
Months Ended March 31, 2001 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 18
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 20
Item 6. Exhibits and Reports on Form 8-K 20
-2-
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
March 31, December 31,
2001 2000
-------- --------
ASSETS (Unaudited)
CURRENT ASSETS
Cash and cash equivalents $ 10,842 $ 5,508
Accounts receivable - trade 227,676 329,464
Inventories 7,244 994
Insurance receivable for pipeline spill costs 3,224 5,527
Other 10,541 9,111
-------- --------
Total current assets 259,527 350,604
FIXED ASSETS, at cost 113,904 113,715
Less: Accumulated depreciation (27,166) (25,609)
-------- --------
Net fixed assets 86,738 88,106
OTHER ASSETS, net of amortization 10,303 10,633
-------- --------
TOTAL ASSETS $356,568 $449,343
======== ========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Bank borrowings $ 18,000 $ 22,000
Accounts payable -
Trade 233,763 322,912
Related party 1,111 4,750
Accrued liabilities 18,448 16,546
-------- --------
Total current liabilities 271,322 366,208
COMMITMENTS AND CONTINGENCIES (Note 8)
MINORITY INTERESTS 520 520
PARTNERS' CAPITAL
Common unitholders, 8,625 units issued, and 8,624
units outstanding 83,028 80,960
General partner 1,704 1,661
-------- --------
Subtotal 84,732 82,261
Treasury Units, 1 unit (6) (6)
-------- --------
Total partners' capital 84,726 82,615
-------- --------
TOTAL LIABILITIES AND PARTNERS' CAPITAL $356,568 $449,343
The accompanying notes are an integral part of these consolidated financial
statements.
-3-
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
(Unaudited)
Three Months Ended March 31,
2001 2000
---------- ----------
REVENUES:
Gathering and marketing revenues
Unrelated parties $ 900,693 $ 998,430
Related parties 25,900 -
Pipeline revenues 3,700 3,413
---------- ----------
Total revenues 930,293 1,001,843
COST OF SALES:
Crude costs, unrelated parties 890,518 957,496
Crude costs, related parties 28,700 34,781
Field operating costs 4,073 3,214
Pipeline operating costs 2,377 2,053
---------- ----------
Total cost of sales 925,668 997,544
---------- ----------
GROSS MARGIN 4,625 4,299
EXPENSES:
General and administrative 2,727 2,656
Depreciation and amortization 1,897 2,046
---------- ----------
OPERATING INCOME (LOSS) 1 (403)
OTHER INCOME (EXPENSE):
Interest income 71 37
Interest expense (206) (348)
Change in fair value of derivatives 3,409 -
Gain (loss) on asset disposals 129 (12)
---------- ----------
Income (loss) before minority interests and
cumulative effect of adoption of accounting
principle 3,404 (726)
Minority interests - (145)
---------- ----------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE 3,404 (581)
Cumulative effect of adoption of accounting
principle, net of minority interest effect 467 -
---------- ----------
NET INCOME (LOSS) $ 3,871 $ (581)
========== ==========
NET INCOME (LOSS) PER COMMON UNIT - BASIC AND DILUTED:
Income (loss) before cumulative effect of
adoption of accounting principle $ 0.39 $ (0.07)
========== ==========
Cumulative effect of adoption of accounting
principle, net of minority interest effect $ 0.05 $ -
========== ==========
Net income (loss) $ 0.44 $ (0.07)
========== ==========
NUMBER OF COMMON UNITS OUTSTANDING 8,624 8,624
========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
-4-
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
Three Months Ended March 31,
2001 2000
---------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ 3,871 $ (581)
Adjustments to reconcile net income to net
cash provided by (used in) operating activities -
Depreciation 1,566 1,716
Amortization of intangible assets 331 330
Cumulative effect of adoption of accounting
principle (467) -
Change in fair value of derivatives (3,409) -
Minority interests equity in earnings (losses) - (145)
(Gain) loss on asset disposals (129) 12
Other noncash charges 15 333
Changes in components of working capital -
Accounts receivable 101,788 (174,247)
Inventories (6,250) (2,005)
Other current assets 588 9,636
Accounts payable (92,788) 168,454
Accrued liabilities 5,763 (7,895)
---------- ----------
Net cash provided by (used in) operating activities 10,879 (4,392)
---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (198) (99)
Change in other assets (1) 2
Proceeds from sale of assets 414 -
---------- ----------
Net cash provided by (used in) investing activities 215 (97)
---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings (repayments) under Loan Agreement (4,000) 2,000
Distributions:
To common unitholders (1,725) (4,312)
To General Partner (35) (88)
Issuance of additional partnership interests - 2,200
---------- ----------
Net cash used in financing activities (5,760) (200)
---------- ----------
Net increase (decrease) in cash and cash equivalents 5,334 (4,689)
Cash and cash equivalents at beginning of period 5,508 6,664
---------- ----------
Cash and cash equivalents at end of period $ 10,842 $ 1,975
========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
-5-
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
(In thousands)
(Unaudited)
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 three months ended
March 31, 2001 3,793 78 - 3,871
Cash distributions for the three months
ended March 31, 2001 (1,725) (35) - (1,760)
--------- ------- ----- ---------
Partners' capital at March 31, 2001 $ 83,028 $ 1,704 $ (6) $ 84,727
========= ======= ===== =========
The accompanying notes are an integral part of these consolidated financial
statements.
-6-
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 elimination of the outstanding additional partnership
interests, or APIs, issued to Salomon in exchange for its distribution support.
2. Basis of Presentation
The accompanying financial statements and related notes present the
consolidated financial position as of March 31, 2001 and December 31, 2000 for
GELP, its results of operations and cash flows for the three months ended March
31, 2001 and 2000, and changes in its partners' capital for the three months
ended March 31, 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 March 31, 2001 and 2000 was 8,623,916 and
8,624,324, 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 either period presented.
-7-
3. 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. No customer accounted for more than 10% of the Partnership's
revenues in any period.
4. Credit Resources and Liquidity
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 March 31, 2001, the aggregate amount of obligations covered by guarantees was
$199 million, including $101 million in payable obligations and $98 million of
estimated crude oil purchase obligations for April 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 is currently in compliance with the provisions of
this agreement.
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.
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).
-8-
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 March
31, 2001.
At March 31, 2001, the Partnership had $18.0 million of loans outstanding
under the Credit Agreement. The Partnership had no letters of credit
outstanding at March 31, 2001. At March 31, 2001, $7.0 million was available to
be borrowed under the Credit Agreement.
Credit Availability
At March 31, 2001, the Partnership's consolidated balance sheet reflected
a working capital deficit of $11.8 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 at least $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
possible 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.
-9-
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.
5. 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).
Three Months Three Months
Ended Ended
March 31, March 31,
2001 2000
--------- ---------
Sales to affiliates $ 25,900 $ -
Purchases from affiliates $ 28,700 $ 34,781
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 $4,939,000 and $3,969,000 for the three months ended March 31,
2001 and 2000, respectively.
Credit Facilities
As discussed in Note 4, Salomon provides Credit Facilities to the
Partnership. For the three months ended March 31, 2001 and 2000, the
Partnership paid Salomon $423,000 and $319,000, respectively, for guarantee fees
under the Credit Facilities.
6. Supplemental Cash Flow Information
Cash received by the Partnership for interest was $87,000 and $43,000 for
the three months ended March 31, 2001 and 2000, respectively. Payments of
interest were $159,000 and $335,000 for the three months ended March 31, 2001
and 2000, respectively.
7. 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
-10-
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 will mark 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 $3.4 million for the three months ended March 31, 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 $8.3
million in other current assets and $4.4 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.
8. 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. As part of the formation of the
Partnership, Basis and Howell agreed to be responsible for certain environmental
conditions related to their ownership and operation of their respective assets
contributed to the Partnership and for any environmental liabilities which Basis
or Howell may have assumed from prior owners of these assets.
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 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 March 31,
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
-11-
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 March 31, 2001, $18.0 million
had been paid to vendors and claimants for spill costs, and $1.5 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, $0.5 million for expenditures not yet submitted to
insurers and $1.5 million for expenditures not yet incurred or billed to the
Partnership. At March 31, 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 latter half of 2001.
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.
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.
9. Distributions
On April 16, 2001, the Board of Directors of the General Partner declared a cash
distribution of $0.20 per Unit for the three months ended March 31, 2001. This
distribution will be paid on May 15, 2001, to the General Partner and all Common
Unitholders of record as of the close of business on April 30, 2001.
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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 Condensed
Consolidated Financial Statements and Notes thereto.
Results of Operations - Three Months Ended March 31, 2001 Compared with Three
Months Ended March 31, 2000
Selected financial data for this discussion of the results of operations
follows, in thousands, except volumes per day.
Three Months Ended March 31,
2001 2000
-------- --------
Gross margin
Gathering and marketing $ 3,302 $ 2,939
Pipeline $ 1,323 $ 1,360
General and administrative expenses $ 2,727 $ 2,656
Depreciation and amortization $ 1,897 $ 2,046
Operating income (loss) $ 1 $ (403)
Interest income (expense), net $ (135 $ (311)
Change in fair value of derivatives $ 3,409 $ -
Gain (loss) on asset disposals $ 129 $ (12)
Volumes per day
Wellhead 93,146 102,481
Bulk and exchange 268,367 289,652
Pipeline 89,459 85,866
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.
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
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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.
Gross margin from gathering and marketing operations was $3.3 million for
the quarter ended March 31, 2001, as compared to $2.9 million for the quarter
ended March 31, 2000.
The factors affecting gross margin were:
* a decrease of 9 percent in wellhead, bulk and exchange purchase volumes
between 2000 and 2001, resulting in a decrease in gross margin of $0.5
million;
* a 37 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 $2.1 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 $0.9 million in field operating costs, primarily from a
$0.2 million increase in payroll and benefits costs, $0.1 million
increase in fuel costs, and $0.6 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 12% increase in the number of
barrels transported by the Partnership in trucks, and
* an unrealized gain recorded in the 2000 period of $0.2 million related to
written option contracts.
Pipeline gross margin was $1.3 million for the quarter ended March 31, 2001,
as compared to $1.4 million for the first quarter of 2000. The factors
affecting pipeline gross margin were:
* an increase in throughput of 4 percent between the two periods, resulting
in a revenue increase of $0.1 million;
* an increase in revenues from sales of pipeline loss allowance barrels of
$0.2 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 2% in the average tariff on shipments resulting in a slight
decrease in revenue; and
* an increase of pipeline operating costs of $0.3 million in the 2001
period primarily due to increased expenditures in areas of spill
prevention.
General and administrative expenses were $2.7 million for the three months
ended March 31, 2001, which was flat with the 2000 period.
Depreciation and amortization in the 2001 quarter decreased when compared to
the 2000 period. This $0.1 million reduction is attributable primarily to the
Partnerships' change in late 2000 from owning its tractor/trailer fleet to
leasing the vehicles.
Interest expense decreased $0.1 million due to lower average debt
outstanding, offset by higher market interest rates. The average interest rate
increased 29%, resulting in an increase of $0.1 million of interest, while the
average debt outstanding declined by $10 million, resulting in a decrease in
interest expense of $0.2 million. Interest income increased primarily as a
result of an increase in interest earned on deposits of excess cash during the
quarter.
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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.
Liquidity and Capital Resources
Cash Flows
Cash flows provided by operating activities were $10.9 million for the
three months ended March 31, 2001. Operating activities in the prior year
period utilized cash of $4.4 million primarily due to the timing of payment for
NYMEX transactions and related margin calls combined with fluctuations in the
timing of payment of costs related to the Mississippi oil spill and the
collection of the related receivable from insurance companies.
For the three months ended March 31, 2001, cash flows provided by
investing activities was $0.2 million. In the 2000 first quarter, investing
activities utilized cash flows of $0.1 million. The Partnership received cash of
$0.4 million from the sale of excess equipment and expended $0.2 million for
additions in property and equipment, primarily related to pipeline operations in
the 2001 period.
Cash flows used in financing activities were $5.8 million in the quarter
ended March 31, 2001. The Partnership reduced its borrowings under its Credit
Agreement by $4.0 million. The Partnership also paid a distribution to common
unitholders and the General Partner totaling $1.8 million. Additionally, the
Partnership will pay a distribution of $0.20 per Unit for the three months ended
March 31, 2001 on May 15, 2001 to the General Partner and all Common Unitholders
of record as of the close of business on April 30, 2001.
Working Capital and Credit Resources
As discussed in Note 4 of the Notes to Consolidated Financial Statements,
the Partnership has a $300 million 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 March 31, 2001, the Partnership's consolidated balance sheet reflected
a working capital deficit of $11.8 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. 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.
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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 increased from $12 per barrel in January 1999 to
more than $29 per barrel in the first quarter of 2001, U.S. onshore crude oil
production volumes have not improved. Further, producers appear to be
responding cautiously to the oil price increase and are focusing more on
drilling for natural gas.
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 at least $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 possible 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.
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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.
Under SFAS No. 133, the Partnership will mark 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 $3.4 million for the three months ended March 31, 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.
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 March 31, 2001, $18.0 million
had been paid to vendors and claimants for spill costs, and $1.5 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, $0.5 million for expenditures not yet submitted to
insurers and $1.5 million for expenditures not yet incurred or billed to the
Partnership. At March 31, 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.
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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 latter half of 2001.
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 March 31,
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.
Forward Looking Statements
The statements in this Annual Report on Form 10-K 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;
* 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 at least the
minimum quarterly distribution;
-18-
* 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 March
31, 2001, the Partnership used futures, forward and option 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.
Sell (Short) Buy (Long)
Contracts Contracts
---------- ----------
Crude Oil Inventory:
Volume (1,000 bbls) 280
Carrying value (in thousands) $ 7,141
Fair value (in thousands) $ 7,324
Commodity Futures Contracts:
Contract volumes (1,000 bbls) 14,655 15,388
Weighted average price per bbl $ 27.41 $ 27.40
Contract value (in thousands) $ 401,710 $ 421,700
Fair value (in thousands) $ 385,643 $ 404,188
Commodity Forward Contracts:
Contract volumes (1,000 bbls) 3,921 3,551
Weighted average price per bbl $ 26.16 $ 26.57
Contract value (in thousands) $ 102,533 $ 94,374
Fair value (in thousands) $ 104,161 $ 96,642
Commodity Option Contracts:
Contract volumes (1,000 bbls) 10,420 9,720
Weighted average strike price per bbl $ 2.42 $ 3.31
Contract value (in thousands) $ 3,249 $ 3,990
Fair value (in thousands) $ 2,461 $ 2,928
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 March 31, 2001 closing prices of the
applicable NYMEX futures contract adjusted for location and grade differentials,
as necessary.
-19-
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.
10.1 Severance Agreement between Genesis Energy, L.L.C. and
Mark J. Gorman
10.2 Severance Agreement between Genesis Energy, L.L.C. and
John M. Fetzer
10.3 Severance Agreement between Genesis Energy, L.L.C. and
Ross A. Benavides
10.4 Severance Agreement between Genesis Energy, L.L.C. and
Kerry W. Mazoch
(b) Reports on Form 8-K.
A Form 8-K was filed on January 30, 2001, announcing the listing of
the Partnership's Common Units on the American Stock Exchange and the
discontinued listing on the New York Stock Exchange.
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: May 14, 2001 By: /s/ Ross A. Benavides
---------------------------------
Ross A. Benavides
Chief Financial Officer
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