UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------------
FORM 10-Q
[X] QUARTERLY REPORT UNDER SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2000
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
2
GENESIS ENERGY, L.P.
Form 10-Q
INDEX
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements Page
----
Consolidated Balance Sheets - September 30, 2000 and
December 31, 1999 3
Consolidated Statements of Operations for the Three and Nine
Months Ended September 30, 2000 and 1999 4
Consolidated Statements of Cash Flows for the Nine Months
Ended September 30, 2000 and 1999 5
Consolidated Statement of Partners' Capital for the Nine
Months Ended September 30, 2000 6
Notes to Consolidated Financial Statements 7
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 15
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 22
Item 6. Exhibits and Reports on Form 8-K 23
3
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
September 30, December 31,
2000 1999
-------- --------
ASSETS (Unaudited)
CURRENT ASSETS
Cash and cash equivalents $ 14,872 $ 6,664
Accounts receivable -
Trade 383,903 241,529
Related party - 7,030
Inventories 414 404
Insurance receivable for pipeline spill costs 4,126 16,586
Other 6,361 2,504
-------- --------
Total current assets 409,676 274,717
FIXED ASSETS, at cost 117,639 116,332
Less: Accumulated depreciation (27,507) (22,419)
-------- --------
Net fixed assets 90,132 93,913
OTHER ASSETS, net of amortization 10,963 11,962
-------- --------
TOTAL ASSETS $510,771 $380,592
======== ========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Short-term debt $ 19,900 $ 19,900
Accounts payable -
Trade 373,675 251,742
Related party 12,089 1,604
Accrued liabilities 21,611 19,290
-------- --------
Total current liabilities 427,275 292,536
COMMITMENTS AND CONTINGENCIES (Note 8)
ADDITIONAL PARTNERSHIP INTERESTS 11,300 3,900
MINORITY INTERESTS 30,808 30,571
PARTNERS' CAPITAL
Common unitholders, 8,625 units issued and
8,617 units and 8,620 units outstanding at
September 30, 2000 and December 31, 1999,
respectively 40,625 52,574
General partner 806 1,051
-------- --------
Subtotal 41,431 53,625
Treasury Units, 8 units and 5 units at
September 30, 2000 and December 31, 1999,
respectively (43) (40)
-------- --------
Total partners' capital 41,388 53,585
-------- --------
TOTAL LIABILITIES AND PARTNERS' CAPITAL $510,771 $380,592
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
4
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
---------- -------- ---------- ----------
REVENUES:
Gathering and marketing revenues
Unrelated parties $1,088,892 $575,381 $3,248,593 $1,429,158
Related parties - 14,229 29,820 49,121
Pipeline revenues 4,140 4,207 11,358 12,649
---------- -------- ---------- ----------
Total revenues 1,093,032 593,817 3,289,771 1,490,928
COST OF SALES:
Crude costs unrelated parties 1,053,505 573,383 3,135,028 1,406,587
Crude costs related parties 26,898 10,028 122,277 52,301
Field operating costs 3,399 2,845 9,810 8,455
Pipeline operating costs 2,326 2,100 6,411 6,034
---------- -------- ---------- ----------
Total cost of sales 1,086,128 588,356 3,273,526 1,473,377
---------- -------- ---------- ----------
GROSS MARGIN 6,904 5,461 16,245 17,551
EXPENSES:
General and administrative 2,785 2,740 8,161 8,779
Depreciation and amortization 2,048 2,054 6,129 6,166
---------- -------- ---------- ----------
OPERATING INCOME 2,071 667 1,955 2,606
OTHER INCOME (EXPENSE):
Interest income 55 38 139 107
Interest expense (242) (333) (944) (849)
Gain (loss) on asset sales 16 (55) 36 845
---------- -------- ---------- ----------
NET INCOME BEFORE MINORITY INTERESTS 1,900 317 1,186 2,709
Minority interests 380 63 237 542
---------- -------- ---------- ----------
NET INCOME $ 1,520 $ 254 $ 949 $ 2,167
========== ======== ========== ==========
NET INCOME PER COMMON UNIT - BASIC AND DILUTED $ 0.17 $ 0.03 $ 0.11 $ 0.25
========== ======== ========== ==========
NUMBER OF COMMON UNITS OUTSTANDING 8,617 8,604 8,621 8,604
========== ======== ========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
5
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
Nine Months Ended September 30,
2000 1999
--------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 949 $ 2,167
Adjustments to reconcile net income to net cash
provided by (used in) operating activities -
Depreciation 5,140 5,114
Amortization of intangible assets 989 1,052
Minority interests equity in earnings 237 542
Gain on disposals of fixed assets (36) (845)
Other noncash charges 649 1,119
Changes in components of working capital -
Accounts receivable (135,344) (76,068)
Inventories (10) 655
Other current assets 8,603 (3,874)
Accounts payable 132,418 72,177
Accrued liabilities 1,766 (1,481)
--------- --------
Net cash provided by operating activities 15,361 558
--------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (1,378) (2,086)
Change in other assets 10 415
Proceeds from sales of assets 55 1,008
--------- --------
Net cash used in investing activities (1,313) (663)
--------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net borrowings under Credit/Loan Agreement - 6,300
Distributions:
To common unitholders (12,934) (12,905)
To general partner (264) (264)
Issuance of additional partnership interests 7,400 1,700
Purchase of treasury units (42) -
--------- --------
Net cash used in financing activities (5,840) (5,169)
--------- --------
Net increase (decrease) in cash and cash equivalents 8,208 (5,274)
Cash and cash equivalents at beginning of period 6,664 7,710
--------- --------
Cash and cash equivalents at end of period $ 14,872 $ 2,436
========= ========
The accompanying notes are an integral part of these consolidated financial
statements.
6
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
(In thousands)
(Unaudited)
Partners' Capital
-------------------------------------
Common General Treasury
Unitholders Partner Units Total
------- ------ ---- -------
Partners' capital at December 31, 1999 $52,574 $1,051 $(40) $53,585
Net income for the nine months ended
September 30, 2000 930 19 - 949
Distributions during the nine months ended
September 30, 2000 (12,934) (264) - (13,198)
Purchase of treasury units - - (42) (42)
Issuance of treasury units to Restricted Unit Plan
participants - - 39 39
Excess of expense over cost of treasury units issued
for Restricted Unit Plan 55 - - 55
------- ------ ---- -------
Partners' capital at September 30, 2000 $40,625 $ 806 $(43) $41,388
======= ====== ==== =======
The accompanying notes are an integral part of these consolidated financial
statements.
7
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Formation and Offering
In December 1996, Genesis Energy, L.P. ("GELP") 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.
Unless the context otherwise requires, the term "the Partnership" hereafter
refers to GELP and its operating limited partnership.
2. Basis of Presentation
The accompanying consolidated financial statements and related notes present
the financial position as of September 30, 2000 and December 31, 1999 for GELP,
the results of operations for the three and nine months ended September 30, 2000
and 1999, cash flows for the nine months ended September 30, 2000 and 1999 and
changes in partners' capital for the nine months ended September 30, 2000.
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/A for the year
ended December 31, 1999 filed with the SEC.
Basic net income per Common Unit is calculated on the weighted average number
of outstanding Common Units. The weighted average number of Common Units
outstanding for the three months ended September 30, 2000 and 1999 was 8,617,000
and 8,604,000, respectively. For the 2000 and 1999 nine month periods, the
weighted average number of Common Units outstanding was 8,621,000 and 8,604,000,
respectively. For this purpose, the 2% General Partner interest is excluded
from net income. Diluted net income per Common Unit did not differ from basic
net income per Common Unit for any period presented.
3. New Accounting Pronouncements
In November 1998, the Emerging Issues Task Force (EITF) reached a consensus
on EITF Issue 98-10, "Accounting for Energy Trading and Risk Management
Activities". This consensus, effective in the first quarter of 1999, requires
that "energy trading" contracts be marked-to-market, with gains or losses
recognized in current earnings. The Partnership has determined that its
activities do not meet the definition in EITF Issue 98-10 of "energy trading"
activities and, therefore, is not required to make any change in its accounting,
except as
8
EITF 98-10 relates to written option contracts. EITF 98-10 requires that all
written option contracts be marked-to-market. For the three and nine months
ended September 30, 2000, the Partnership recorded unrealized gains of $0.9
million and $0.3 million, respectively, as a result of marking these contracts
to market. These amounts are included in cost of crude in the statement of
operations.
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities",
was issued in June 1998. This standard was subsequently amended by SFAS 137 and
SFAS 138. This new standard, as amended, which the Partnership will be required
to adopt for its fiscal year 2001, will change the method of accounting for
changes in the fair value of derivative instruments by requiring that an entity
recognize the derivative at fair value as an asset or liability on its balance
sheet. Depending on the purpose of the derivative and the item it is hedging,
the changes in fair value of the derivative will be recognized in current
earnings or as a component of other comprehensive income in partners' capital.
The Partnership is in the process of evaluating the impact that this statement
will have on its business processes, results of operations and financial
position. The Partnership is currently reviewing its contracts to determine the
effects of volumetric commitments, pricing arrangements and liquidation
terminology under the new standard and will complete that review during the
fourth quarter of 2000. The review thus far has indicated that a majority of
the Partnership's crude oil contracts will qualify as derivative instruments
under the standard which could increase volatility in net income and
comprehensive income when the contracts are valued at fair value.
SAB No. 101 provides interpretive guidance on the proper recognition,
presentation and disclosure of revenues in financial statements. The Company
has reviewed its revenue, recognition policies and determined that they are in
compliance with generally accepted accounting principles and the related
interpretive guidance set forth in SAB No. 101.
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 has a Guaranty Facility with Salomon, pursuant to a Master Credit
Support Agreement, and a Working Capital Facility with BNP Paribas. GCOLP's
obligations under these facilities are secured by its receivables, inventories,
general intangibles and cash.
Guaranty Facility
Salomon is providing a Guaranty Facility through March 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 (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 of 0.75% of the utilized amount of
outstanding guarantees. An additional fee of 1.00% is paid on any amounts in
excess of the $300 million commitment. At September 30, 2000, the aggregate
amount of obligations covered by guarantees was $260 million, including $141
million in payable obligations and $119 million of estimated crude oil purchase
obligations for October 2000.
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.
9
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 after exclusion of bank
debt from current liabilities, (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, (d) a ratio of Consolidated Earnings before
Interest, Taxes, Depreciation and Amortization to Consolidated Fixed Charges of
at least 1.75 to 1 as of the last day of each fiscal quarter prior to December
31, 1999 and (e) 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).
An Event of Default could result in the termination of the Guaranty
Facility 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 Guaranty Facility 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 on the first day of the month 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 Guaranty Facility. Removal of the General Partner
will result in the termination of the Guaranty Facility and the release of all
of Salomon's obligations thereunder. The Partnership exceeded the $300 million
maximum credit limitation under the Guaranty Facility on May 1 and June 1, 2000,
due primarily to the rise in crude oil prices and additional outstanding
guarantees. A waiver of the resulting Event of Default was obtained from
Salomon. The General Partner has taken steps to reduce or restrict the
Partnership's gathering and marketing activities due to the $300 million limit
of the Guaranty Facility.
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 on March 31, 2001.
Upon approval of a proposed restructuring discussed in Note 10, Salomon will
extend the expiration date of its credit support obligation to the Partnership
from March 31, 2001, to December 31, 2001, on the current terms and conditions.
If the General Partner is removed without its consent, Salomon's credit support
obligations will terminate. In addition, Salomon's obligations under the Master
Credit Support Agreement may be transferred or terminated early subject to
certain conditions. If the proposed restructuring discussed in Note 10 is not
approved, management of the Partnership intends to replace the Guaranty Facility
with a letter of credit facility with one or more third party lenders prior to
March 2001 and has had preliminary discussions with banks about a replacement
letter of credit facility. The General Partner may be required to reduce or
restrict the Partnership's gathering and marketing activities because of
limitations on its ability to obtain credit support and financing for its
working capital needs. The General Partner expects that the overall cost of a
replacement facility may be substantially greater than what the Partnership is
incurring under its existing Master Credit Support Agreement. Any significant
decrease in the Partnership's financial strength, regardless of the reason for
such decrease, may increase the number of transactions requiring letters of
credit or other financial support, make it more difficult for the Partnership to
obtain such letters of credit, and/or may increase the cost of obtaining them.
This situation could in turn adversely affect the Partnership's ability to
maintain or increase the level of its purchasing and marketing activities or
otherwise adversely affect the Partnership's profitability and Available Cash.
Working Capital Facility
On June 6, 2000, GCOLP entered into a credit agreement ("Credit Agreement")
with BNP Paribas to replace the Loan Agreement with Bank One. The Credit
Agreement provides for loans or letters of credit in the aggregate not to exceed
the lesser of $25 million or the Borrowing Base (as defined in the Credit
Agreement).If BNP Paribas obtains loan commitments for an additional $10
million, the amount available under the Credit Agreement would increase to $35
million. As of September 30, 2000, BNP Paribas had not obtained loan
commitments for the additional $10 million. Interest is calculated, at the
Partnership's option, by using either LIBOR plus 1.4% or BNP Paribas' prime rate
minus 1%.
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 March 31, 2001,
the Credit Agreement with BNP Paribas is currently scheduled to expire on
February 28, 2001. If the proposed restructuring is approved on December 7,
2000, Salomon will extend the Master Credit Support
10
Agreement. See Note 10. The Credit Agreement with BNP Paribas would, as a
result, automatically extend to 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 5.0 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 not in compliance with the Maximum Leverage Ratio covenant at
the end of each month since June 30, 2000, and is likely to be in violation
for future periods until an amendment to the Credit Agreement is obtained.
A waiver for each period has been obtained from BNP Paribas. No assurance can
be given, however, that BNP Paribas will continue to provide waivers of this
covenant in the future or agree to amend the Credit Agreement.
At December 31, 1999, and September 30, 2000, the Partnership had $19.9
million of debt outstanding under the Credit Agreement. The Partnership had no
letters of credit outstanding at September 30, 2000. At September 30, 2000,
$5.1 million was available to be borrowed under the Credit Agreement. The
current average interest rate is 10.5 percent.
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.
Distributions of Available Cash to the holders of Subordinated OLP Units are
subject to the prior rights of holders of Common Units to receive the minimum
quarterly distribution ("MQD") for each quarter during the subordination period
(which will not end earlier than December 31, 2001) and to receive any
arrearages in the distribution of the MQD on the Common Units for prior quarters
during the subordination period. MQD is $0.50 per unit.
Salomon has committed, subject to certain limitations, to provide total
cash distribution support with respect to quarters ending on or before December
31, 2001, in an amount up to an aggregate of $17.6 million in exchange for
Additional Partnership Interests ("APIs"). Salomon's obligation to provide
distribution support will end no later than December 31, 2001 or until the $17.6
million is fully utilized, whichever comes first.
Through September 30, 2000, the Partnership utilized $11.3 million of the
distribution support from Salomon. On November 14, 2000, the Partnership will
utilize an additional $2.5 million of distribution support for the distribution
related to the third quarter. After the distribution in November 2000, $13.8
million of distribution support will have been utilized and $3.8 million will
remain available through December 31, 2001, or until such amount is fully
utilized, whichever comes first. Upon approval of a proposed restructuring on
December 7, 2000, Salomon will contribute the remaining balance of its
distribution support commitment to GCOLP. See Note 10. After payment of
transaction costs associated with the restructuring, the Partnership will then
declare a special distribution of the remaining cash.
APIs purchased by Salomon are not entitled to cash distributions or voting
rights. The APIs will be redeemed if and to the extent that Available Cash for
any future quarter exceeds the amount necessary to distribute the MQD on all
Common Units and Subordinated OLP Units and to eliminate any arrearages in the
MQD on Common Units for prior periods.
In addition, 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.
11
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).
Nine Months Ended September 30,
2000 1999
-------- -------
Sales to affiliates $ 29,820 $49,121
Purchases from affiliates $122,277 $52,301
General and Administrative Services
The Partnership does not directly employ any persons to manage or operate
its business. Those functions are provided by the General Partner. The
Partnership reimburses the General Partner for all direct and indirect costs of
these services. Total costs reimbursed to the General Partner by the
Partnership were $12,519,000 and $12,262,000 for the nine months ended September
30, 2000 and 1999, respectively.
Credit Facilities
As discussed in Note 5, Salomon provides a Guaranty Facility to the
Partnership. For the nine months ended September 30, 2000 and 1999, the
Partnership paid Salomon $1,234,000 and $483,000, respectively, for guarantee
fees under the Credit Facilities.
7. Supplemental Cash Flow Information
Cash received by the Partnership for interest was $133,000 and $103,000 for
the nine months ended September 30, 2000 and 1999, respectively. Payments of
interest were $1,029,000 and $820,000 for the nine months ended September 30,
2000 and 1999, respectively.
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.
The Partnership is subject to lawsuits in the normal course of business and
examination by tax and other regulatory authorities. Additionally, litigation
involving the Partnership has been filed related to the proposed restructuring.
See Note 10. 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.
As part of the formation of the Partnership, Basis and Howell agreed to each
retain liability and responsibility for the defense of any future lawsuits
arising out of activities conducted by Basis and Howell prior to the formation
of the Partnership and have also agreed to cooperate in the defense of such
lawsuits.
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. Some of the
oil then flowed into the Leaf River.
12
The Partnership responded to this incident immediately, deploying crews to
evaluate, clean up and monitor the spilled oil. At February 1, 2000, the spill
had been substantially cleaned up, with ongoing maintenance and reduced clean-up
activity expected to continue for an undetermined period of time.
The estimated cost of the spill clean-up is expected to be $18 million.
This amount includes estimates for clean-up costs, ongoing maintenance and
settlement of potential liabilities to landowners in connection with the spill.
The incident was reported to insurers. At September 30, 2000, $16.8 million had
been paid to vendors and claimants for spill related costs, and $1.2 million was
included in accrued liabilities for estimated future expenditures. Current
assets included $0.3 million of expenditures submitted and approved by insurers
but not yet reimbursed, $2.6 million for expenditures not yet submitted to
insurers and $1.2 million for expenditures not yet incurred or billed to the
Partnership. At September 30, 2000, $13.9 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 reimbursed by
insurance. At this time, it is not possible to predict whether the Partnership
will be fined, the amounts of such fines or whether the governmental agencies
would prevail in imposing such fines.
The segment of the Mississippi System where the spill occurred has been
temporarily shut down and will not be returned to service until regulators give
their approval. Regulatory authorities may require specific testing or changes
to the pipeline before allowing the Partnership to restart that segment of 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.
If Management of the Partnership determines that the costs of 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, 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 $6.0 million. Tariff
revenues for this segment of the system in the year 1999 were $0.6 million.
The Partnership has been named as one of the defendants in a complaint
filed by Garner Environmental Services, Inc. ("Garner") on October 12, 2000 in
the 265th District Court of Harris County, Cause No. 200019833. Garner, who
participated in the pipeline oil spill clean-up, has sued the Partnership and
the firm hired by the Partnership to provide cost control services in connection
with the oil spill clean-up for libel and slander. Garner has also sued the
Partnership for suit on account and breach of contract. Management of the
Partnership believes that the suit is without merit and intends to vigorously
defend itself in this matter. However, the Partnership cannot guarantee that a
potential claim will not result in a liability to it, nor can the Partnership
provide assurance that any potential liability would be covered by Genesis'
insurance carrier.
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. As of September 30, 2000, the estimated volume
of crude that was potentially contaminated was 7,500 barrels.
The Partnership has accrued costs associated with transportation, testing
and consulting in the amount of $188,000, of which $157,000 has been paid at
September 30, 2000. The potentially contaminated barrels are reflected in
inventory at their cost of approximately $0.2 million.
The Partnership has recorded a receivable for $188,000 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.
In a separate matter, on August 17, 2000, Pennzoil-Quaker State Company
filed a petition in the 61st District Court of Harris County, Texas, requesting
the court's authority to take depositions and subpoena documents in connection
with the investigation of a potential claim or suit against several parties,
including GCOLP. In its petition, Pennzoil-Quaker State alleges that tainted
crude oil supplied by GCOLP may have caused a fire and explosion at Pennzoil-
Quaker State's Shreveport refinery in January 2000. GCOLP does not possess
sufficient
13
information at this time to determine whether the fire at the refinery was
caused by crude oil supplied by GCOLP. If Pennzoil-Quaker State were to file a
lawsuit against the partnership, we intend to vigorously defend any claim filed
against us. However, we cannot guarantee that a potential claim will not result
in liability to us, nor can management of the Partnership provide assurance that
any potential liability would be covered by GCOLP's insurance carrier.
9. Distributions
On October 11, 2000, the Board of Directors of the General Partner declared a
cash distribution of $0.50 per Unit for the quarter ended September 30, 2000.
The distribution will be paid November 14, 2000, to the General Partner and all
Common Unitholders of record as of the close of business on October 31, 2000.
The Subordinated OLP Unitholders will not receive a distribution for the
quarter.
The distribution will be paid utilizing approximately $1.9 million of cash
available from the Partnership and $2.5 million of cash provided by Salomon
pursuant to Salomon's Distribution Support Agreement.
10. Proposed Restructuring
On October 23, 2000 the Partnership announced that it has scheduled a Special
Meeting of the Partnership's common unitholders at 8:30 a.m. Houston, Texas time
on December 7, 2000, for purposes of voting on the proposed restructuring of
Genesis as announced on May 10, 2000. The Proxy Statement for this Special
Meeting, which describes the proposed financial restructuring, was mailed on
October 23, 2000, to unitholders of record as of October 18, 2000. The Special
Meeting will take place at the executive offices of Genesis at One Allen Center,
Suite 2500, 500 Dallas, in Houston, Texas.
The restructuring includes amendments to the partnership agreement of our
subsidiary operating partnership that will:
* reduce the minimum quarterly distribution on the common units from the
current $0.50 per unit to $0.20 per unit;
* reduce correspondingly the respective per unit dollar distribution
thresholds that must be achieved before the general partner is entitled to
incentive compensation payments from the current threshold levels of $0.55,
$0.635 and $0.825 per unit to the new threshold levels of $0.25, $0.28 and
$0.33 per unit;
* eliminate all of the outstanding subordinated limited partner units in our
operating partnership and, as a result, provide that the common units will
no longer accrue arrearages if the minimum quarterly distribution is not
paid in full in any quarter; and
* eliminate, without the payment of any consideration, all of the outstanding
additional partnership interests, or APIs, issued to Salomon in exchange
for its distribution support and, as a result, eliminate our obligation to
redeem the APIs issued to Salomon in exchange for its distribution support
if quarterly cash available for distribution exceeds specified levels.
If the proposal is approved:
* Salomon will contribute to the operating partnership in cash the remaining
distribution support, expected to be $3.7 million. After payment of
transaction costs associated with the restructuring estimated at $1.3
million, we will then declare a special distribution of the remaining cash,
estimated at $2.4 million, or $0.28 per unit.
* Salomon will extend the expiration date of its $300 million credit support
obligation to the partnership from March 31, 2001, to December 31, 2001, on
the current terms and conditions. This extension will eliminate an
estimated $2.5 million increase in trade credit costs for the last nine
months of 2001.
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
14
the board of directors of Genesis Energy, L.L.C., and the owner of Genesis
Energy L.L.C. 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 Partnership believes that the
complaint is without merit and intends to vigorously defend the action.
On May 24, 2000, Richard Dollinger, a holder of units of limited partner
interests in the Partnership, filed a putative class action complaint in the
Chancery Division, Camden County, Superior Court of New Jersey, seeking to
enjoin Salomon from taking any steps to accomplish or implement the proposed
restructuring without adequate safeguards for the interests of the class of
common unitholders. The plaintiff alleges breach of fiduciary duty, breach of
contract and duty of good faith and fair dealing and a violation of the New
Jersey Consumer Fraud Act by the defendant in connection with the restructuring.
Salomon believes that the complaint is without merit and intends to vigorously
defend the action.
Management of the Partnership believes that these pending matters will not
have a material adverse effect on the financial position, results of operations
or cash flows of the Partnership.
14
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 Condensed
Consolidated Financial Statements and Notes thereto.
Results of Operations
Selected financial data for this discussion of the results of operations
follows, in thousands, except barrels per day.
Three Months Ended September 30, Nine Months Ended September 30,
2000 1999 2000 1999
-------- -------- -------- --------
Gross margin
Gathering and marketing $ 5,090 $ 3,354 $ 11,298 $ 10,936
Pipeline $ 1,814 $ 2,107 $ 4,947 $ 6,615
General and administrative expenses $ 2,785 $ 2,740 $ 8,161 $ 8,779
Depreciation and amortization $ 2,048 $ 2,054 $ 6,129 $ 6,166
Operating income $ 2,071 $ 667 $ 1,955 $ 2,606
Interest income (expense), net $ (187) $ (295) $ (805) $ (742)
Barrels per day
Wellhead 98,601 97,357 100,852 91,572
Bulk and exchange 286,031 224,957 312,367 253,504
Pipeline 87,889 100,383 89,512 94,951
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
of crude oil do not necessarily bear a relationship to gross margin because
absolute price levels normally impact revenues and cost of sales by equivalent
amounts. As a result, the impact of period-to-period price variations on
revenues and cost of sales generally are not meaningful in analyzing the
variations in gross margins, and such changes are not addressed in the following
discussion.
Pipeline 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 the Partnership's pipeline
operations.
The price level of crude oil impacts 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 supply that is available to be gathered and
marketed by the Partnership and its competitors.
Nine Months Ended September 30, 2000 Compared with Nine Months Ended
September 30, 1999
Gross margin from gathering and marketing operations was $11.3 million for
the nine months ended September 30, 2000, as compared to $11.0 million for the
nine months ended September 30, 1999.
The increase of $0.3 million can be attributed to an unrealized gain of
$0.3 million on written option contracts and several other factors that netted
to a zero effect.
16
The other factors affecting gross margin were:
* an increase of 20 percent in wellhead, bulk and exchange purchase
volumes between the nine month periods in 1999 and 2000, resulting in
an increase in gross margin of $4.0 million;
* an 8 percent decline 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 reduced gross margin by $1.8 million;
* an increase of $0.8 million in credit costs due to the increase in
purchase volumes and an 86 percent increase in the absolute price level
of crude oil; and
* an increase of $1.4 million in field operating costs, primarily from a
$0.5 million increase in payroll and benefits costs and a $0.6 million
increase in fuel costs.
Pipeline gross margin was $4.9 million for the nine months ended September
30, 2000, as compared to pipeline gross margin of $6.6 million for the first
nine months of 1999, a decline of $1.7 million. Pipeline revenues declined $1.3
million as a result of declines in throughput and average tariff. Throughput
declined 6 percent between the nine-month periods 1999 and 2000, resulting in a
revenue decrease of $0.7 million. The average tariff collected on shipments was
down 8%, resulting in a revenue decrease of $0.8 million. Revenues from sales
of pipeline loss allowance increased $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. Pipeline operating
costs were $0.4 million higher in the 2000 period primarily due to $0.2 million
increased expenditures in areas of spill prevention.
General and administrative expenses were $8.2 million for the nine months
ended September 30, 2000, as compared to $8.8 million for the 1999 period. The
decline of $0.6 million is primarily attributable to decreases in the following
areas: $0.1 million in salary and benefits and $0.2 million in restricted unit
expense. Additionally, the 1999 nine month period included costs related to the
Year 2000 remediation totaling $0.3 million.
Net interest expense for the nine months ended September 30, 2000 was $0.8
million. In the 1999 period, the Partnership incurred net interest expense of
$0.7 million. This slight increase in interest cost in 2000 can be attributed
primarily to higher interest rates.
In the 1999 period, the Partnership sold excess trucking assets, resulting
in the recognition of a gain on those sales of $0.9 million.
Three Months Ended September 30, 2000 Compared with Three Months Ended
September 30, 1999
Gross margin from gathering and marketing operations was $5.1 million for
the three months ended September 30, 2000, as compared to $3.4 million for the
three months ended September 30, 1999. The increase of $1.7 million represents
the net effect of several factors.
Wellhead bulk and exchange volumes for the three months ended September 30,
2000, increased 19 percent from the same period in 1999. This rise resulted in
a $1.2 million increase in gathering and marketing gross margins. 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 increased 6 percent, which increased gross
margin by $0.5 million. Additionally, the Partnership recorded an unrealized
gain of $0.9 million in the 2000 third quarter on written option contracts.
Contributing to reduce gross margins were a $0.3 increase in credit costs and a
$0.6 increase in field operating costs. The $0.3 increase in credit costs is a
function of the increase in purchase volumes and a 55 percent increase in the
absolute price level of crude oil. The increase in field operating costs was
primarily from increases in payroll and benefits and fuel costs.
Pipeline gross margin decreased $0.3 million between the 1999 and 2000
third quarters. Throughput declined 12 percent resulting in a $0.5 million
decrease in pipeline revenue. The average tariff collected on shipments was
also 5 percent less, resulting in a revenue decrease of $0.2 million Offsetting
these declines was a $0.6 million increase in revenues of pipeline loss
allowance 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 oil prices. Pipeline
17
operating costs increased were $0.2 million higher in 2000 primarily to
increased expenditures for spill prevention measures.
Net interest expense decreased by $0.1 million in the 2000 third quarter
due to lower debt levels offset by higher interest rates.
Hedging Activities
Genesis routinely utilizes forward contracts, swaps, options and futures
contracts in an effort to minimize the impact of market fluctuations on
inventories and contractual commitments. Gains and losses on forward contracts,
swaps and future contracts used to hedge future contract purchases of unpriced
crude oil, where firm commitments to sell are required prior to establishment of
the purchase price, are deferred until the margin from the hedged item is
recognized. The Partnership recognized net losses of $1.6 million and $0.1
million for the nine months and three months ended September 30, 2000,
respectively, and a net gain of $0.7 million and a net loss of $1.3 million for
the nine and three months ended September 30, 1999, respectively, related to its
hedging activity.
Liquidity and Capital Resources
Cash Flows
Cash flows from operating activities were $15.4 million for the nine months
ended September 30, 2000. Operating activities in the prior year period
generated cash of $0.6 million. The increase in 2000 can be attributed to
differences in the timing of payment for current assets and liabilities.
For the nine months ended September 30, 2000, cash flows utilized in
investing activities were $1.3 million resulting from additions to property and
equipment. In the 1999 period, the Partnership expended $0.7 million on asset
acquisitions, offset by the proceeds from the sale of excess trucking equipment.
Cash flows utilized in financing activities by the Partnership during the
first nine months of 2000 totaled $5.8 million. Distributions paid to the
common unitholders and the general partner totaling $13.2 million utilized cash
flows. Cash totaling $7.4 million was provided by the issuance of Additional
Partnership Interests (APIs) to Salomon under the terms of the Distribution
Support Agreement. Cash flows provided by financing activities of $5.2 million
in the 1999 period represented distributions to the common unitholders and the
general partner, offset by increased borrowings under the Loan Agreement
totaling to $6.3 million and the issuance of $1.7 million of APIs to Salomon.
Working Capital and Credit Resources
As discussed in Note 5 of the Notes to Condensed Consolidated Financial
Statements, the Partnership has a Guaranty Facility with Salomon through March
31, 2001, and a Credit Agreement with BNP Paribas for working capital purposes
that extends through February 28, 2001. Both of these agreements will be
extended if the proposed restructuring is approved on December 7, 2000. See
"Proposed Restructuring". If the General Partner is removed without its
consent, Salomon's credit support obligations will terminate. In addition,
Salomon's obligations under the Master Credit Support Agreement may be
transferred or terminated early subject to certain conditions.
At September 30, 2000, the Partnership's consolidated balance sheet
reflected a working capital deficit of $17.6 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.
Management of the Partnership intends to replace the Guaranty Facility and
Credit Agreement with a working capital letter of credit facility with one or
more third party lenders prior to February 2001 if the proposed restructuring
discussed below under "Proposed Restructuring" is not approved. The General
Partner expects that a replacement facility would increase its annual credit
costs by approximately $3.3 million.
18
Increased credit needs and higher credit costs could adversely affect the
Partnership's ability to maintain or increase the level of its purchasing and
marketing activities. Profitability and Available Cash for distributions could
be adversely impacted as well.
The Partnership will pay a distribution of $0.50 per Unit for the three
months ended September 30, 2000, on November 14, 2000 to the General Partner and
all Common Unitholders of record as of the close of business on October 31,
2000. The subordinated OLP Unitholders will not receive a distribution for that
period.
This distribution will be paid utilizing approximately $1.9 million, or
$0.22 per Common Unit, of cash available from the Partnership and $2.5 million,
or $0.28 per Common Unit, of cash provided by Salomon, pursuant to Salomon's
distribution support obligation.
Under the Distribution Support Agreement, Salomon has committed, subject to
certain limitations, to provide cash distribution support, with respect to
quarters ending on or before December 31, 2001, in an amount up to an aggregate
of $17.6 million in exchange for APIs. Salomon's obligation to purchase APIs
will end no later than December 31, 2001, or when the distribution support will
have been fully utilized, whichever comes first. After the distribution in
November 2000, $13.8 million of distribution support has been utilized and $3.8
million will remain available through December 31, 2001, or until such amount is
fully utilized, whichever comes first. The Distribution Support Agreement will
be terminated and Salomon will make a one-time payment of its then remaining
distribution support obligation if the proposed restructuring discussed below is
approved by a majority of the Partnership's unitholders.
Proposed Restructuring
On October 23, 2000 the Partnership announced that it has scheduled a
Special Meeting of the Partnership's common unitholders at 8:30 a.m. Houston,
Texas time on December 7, 2000, for purposes of voting on the proposed
restructuring of Genesis as announced on May 10, 2000. The Proxy Statement for
this Special Meeting, which describes the proposed financial restructuring, was
mailed on October 23, 2000, to unitholders of record as of October 18, 2000.
The Special Meeting will take place at the executive offices of Genesis at One
Allen Center, Suite 2500, 500 Dallas, in Houston, Texas.
The restructuring includes amendments to the partnership agreement of our
subsidiary operating partnership that will:
* reduce the minimum quarterly distribution on the common units from the
current $0.50 per unit to $0.20 per unit;
* reduce correspondingly the respective per unit dollar distribution
thresholds that must be achieved before the general partner is entitled
to incentive compensation payments from the current threshold levels of
$0.55, $0.635 and $0.825 per unit to the new threshold levels of $0.25,
$0.28 and $0.33 per unit;
* eliminate all of the outstanding subordinated limited partner units in
our operating partnership and, as a result, provide that the common
units will no longer accrue arrearages if the minimum quarterly
distribution is not paid in full in any quarter; and
* eliminate, without the payment of any consideration, all of the
outstanding additional partnership interests, or APIs, issued to Salomon
in exchange for its distribution support and, as a result, eliminate our
obligation to redeem the APIs issued to Salomon in exchange for its
distribution support if quarterly cash available for distribution
exceeds specified levels.
If the proposal is approved:
* Salomon will contribute to the operating partnership in cash the
remaining distribution support, expected to be $3.7 million. After
payment of transaction costs associated with the restructuring estimated
at $1.3 million, we will then declare a special distribution of the
remaining cash, estimated at $2.4 million, or $0.28 per unit.
19
* Salomon will extend the expiration date of its $300 million credit
support obligation to the partnership from March 31, 2001, to December
31, 2001, on the current terms and conditions. This extension will
eliminate an estimated $2.5 million increase in trade credit costs for
the last nine months of 2001.
New Accounting Standard
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities",
was issued in June 1998. This standard was subsequently amended by SFAS 137 and
SFAS 138. This new standard, as amended, which the Partnership will be required
to adopt for its fiscal year 2001, will change the method of accounting for
changes in the fair value of derivative instruments by requiring that an entity
recognize the derivative at fair value as an asset or liability on its balance
sheet. Depending on the purpose of the derivative and the item it is hedging,
the changes in fair value of the derivative will be recognized in current
earnings or as a component of other comprehensive income in partners' capital.
The Partnership is in the process of evaluating the impact that this statement
will have on its business processes, results of operations and financial
position. The Partnership is currently reviewing its contracts to determine the
effects of volumetric commitments, pricing arrangements and liquidation
terminology under the new standard and will complete that review during the
fourth quarter of 2000. The review thus far has indicated that a majority of
the Partnership's crude oil contracts will qualify as derivative instruments
under the standard which could increase volatility in net income and
comprehensive income when the contracts are valued at fair value.
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. Some 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. At February 1, 2000, the spill
had been substantially cleaned up, with ongoing maintenance and reduced clean-up
activity expected to continue for an undetermined period of time.
The estimated cost of the spill clean-up is expected to be $18.0 million.
This amount includes estimates for clean-up costs, ongoing maintenance and
settlement of potential liabilities to landowners in connection with the spill.
The incident was reported to insurers. At September 30, 2000, $16.8 million had
been paid to vendors and claimants for spill related costs, and $1.2 million was
included in accrued liabilities for estimated future expenditures. Current
assets included $0.3 million of expenditures submitted and approved by insurers
but not yet reimbursed, $2.6 million for expenditures not yet submitted to
insurers and $1.2 million for expenditures not yet incurred or billed to the
Partnership. At September 30, 2000, $13.9 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 reimbursed by
insurance. At this time, it is not possible to predict whether the Partnership
will be fined, the amounts of such fines or whether the governmental agencies
would prevail in imposing such fines.
The segment of the Mississippi System where the spill occurred has been
temporarily shut down and will not be returned to service until regulators give
their approval. Regulatory authorities may require specific testing or changes
to the pipeline before allowing the Partnership to restart that segment of 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.
If Management of the Partnership determines that the costs of 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, 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 $6.0 million. Tariff
revenues for this segment of the system in the year 1999 were $0.6 million.
The Partnership has been named as one of the defendants in a complaint
filed by Garner Environmental Services, Inc. ("Garner") on October 12, 2000 in
the 265th District Court of Harris County, Cause No. 200019833. Garner, who
participated in the pipeline oil spill clean-up, has sued the Partnership and
the firm hired by the Partnership to provide cost control services in connection
with the oil spill clean-up for libel and slander. Garner has also sued the
Partnership for suit on account and breach of contract. Management of the
Partnership believes
20
that the suit is without merit and intends to vigorously defend itself in
this matter. However, the Partnership cannot guarantee that a potential claim
will not result in a liability to it, nor can the Partnership provide assurance
that any potential liability would be covered by Genesis' insurance carrier.
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. As of September 30, 2000, the estimated volume
of crude that was potentially contaminated was 7,500 barrels.
The Partnership has accrued costs associated with transportation, testing
and consulting in the amount of $188,000, of which $157,000 has been paid at
September 30, 2000. The potentially contaminated barrels are reflected in
inventory at their cost of approximately $0.2 million.
The Partnership has recorded a receivable for $188,000 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.
In a separate matter, on August 17, 2000, Pennzoil-Quaker State Company
filed a petition in the 61st District Court of Harris County, Texas, requesting
the court's authority to take depositions and subpoena documents in connection
with the investigation of a potential claim or suit against several parties,
including GCOLP. In its petition, Pennzoil-Quaker State alleges that tainted
crude oil supplied by GCOLP may have caused a fire and explosion at Pennzoil-
Quaker State's Shreveport refinery in January 2000. GCOLP does not possess
sufficient information at this time to determine whether the fire at the
refinery was caused by crude oil supplied by GCOLP. If Pennzoil-Quaker State
were to file a lawsuit against the partnership, we intend to vigorously defend
any claim filed against us. However, we cannot guarantee that a potential claim
will not result in liability to us, nor can management of the Partnership
provide assurance that any potential liability would be covered by GCOLP's
insurance carrier.
Potential Delisting from the New York Stock Exchange.
The common units of Genesis are traded on the New York Stock Exchange. The
NYSE rules provide that if a listed company has a global market capitalization
of less than $50 million and total stockholders' equity of less than $50
million, the NYSE will evaluate the continued listing of the company's
securities on the NYSE. The partnership's total partners' capital was $41.4
million as of September 30, 2000, and total market capitalization had dropped
below $50 million during the second quarter of 2000 and again since the end of
the third quarter of 2000. We cannot assure you that the NYSE will not notify
us by letter of our status. This notification would provide us with an
opportunity to provide the NYSE with a plan advising the NYSE of definitive
action we have taken, or are taking, that would bring the partnership into
conformity with continued listing standards within 18 months of receipt of the
notice. We cannot assure you that the NYSE will not provide notice of delisting,
and if so, whether we would be able to present a plan to the NYSE that would
assure the continued listing of our common units on the NYSE. We believe that
the proposed restructuring meets the NYSE requirement of a plan that would
assure the continued listing of our common units. On a pro forma basis,
assuming the restructuring had been approved by the unitholders and became
effective as of October 1, 2000, total partners' capital would be $83.5 million
as a result of the amounts on the balance sheet under "additional partnership
interests" and "minority interests" being contributed to partners' capital.
Current Business Conditions
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.
21
Although crude oil prices have increased from $12 per barrel in January
1999 to nearly $31 per barrel in September 2000, 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.
This change is clearly demonstrated by the Baker Hughes North American
Rotary Rig Count for 1997 to 2000.
Baker Hughes North American Rotary Rig Count
Average Number of Rigs Drilling For Crude Oil
Year Oil Gas Price per bbl*
---- --- --- --------------
1997 376 566 $20.60
1998 264 560 $14.40
1999 128 496 $19.25
2000 186 679 $29.70
* Annual average price for 1997 through 1999 and nine month average
for 2000 for West Texas Intermediate at Cushing, Oklahoma
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 January 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 in 2000 and 2001.
The Partnership's improved volumes in the first nine months of 2000
compared to the same period of 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. The General Partner has taken steps to reduce or restrict the
Partnership's gathering and marketing activities due to the $300 million limit
of the Guaranty Facility.
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. No assurances can be made
that the Partnership would be able to increase the size of its Credit Agreement
or that changes to the terms of such increased Credit Agreement would not have a
material impact on the results of operations or cash flows of the Partnership.
Forward Looking Statements
The statements in this Report on Form 10-Q that are not historical
information are 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 the Partnership believes that its expectations regarding future
events are based on reasonable assumptions, it can give no assurance that its
goals will be achieved or that its expectations regarding future developments
will prove to be correct. Important factors that could cause actual results to
differ materially from those in the forward looking statements herein include,
but are not limited to, changes in regulations, the Partnership's success in
obtaining additional lease barrels, changes in crude oil production volumes
(both world-wide as well as 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 Partnership's risk management activities, credit requirements by
counterparties of the Partnership, the Partnership's ability to replace its
credit support from Salomon with a bank facility and to replace the working
capital facility from Paribas with another facility, any requirements for
testing or changes to the Mississippi System as a result of the oil spill that
occurred there in December 1999 and conditions of the capital markets and equity
markets during
22
the periods covered by the forward looking statements. All subsequent
written or oral forward looking statements attributable to the Partnership or
persons acting on behalf of the Partnership are expressly qualified in their
entirety by the foregoing cautionary statements.
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
September 30, 2000, 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.
Sell (Short) Buy (Long)
Contracts Contracts
-------- --------
Crude Oil Inventory:
Volume (1,000 bbls) 67
Carrying value (in thousands) $ 2,168
Fair value (in thousands) $ 2,168
Commodity Futures Contracts
Contract volumes (1,000 bbls) 13,159 12,563
Weighted average price per bbl $ 30.69 $ 29.56
Contract value (in thousands) $403,910 $371,317
Fair value (in thousands) $400,547 $377,726
Commodity Forward Contracts:
Contract volumes (1,000 bbls) 3,693 4,315
Weighted average price per bbl $ 32.77 $ 32.73
Contract value (in thousands) $121,049 $141,208
Fair value (in thousands) $110,786 $132,419
Commodity Option Contracts:
Contract volumes (1,000 bbls) 17,938
Weighted average strike price per bbl $ 2.46
Contract value (in thousands) $ 5,897
Fair value (in thousands) $ 5,800
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 September 30, 2000 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.
23
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits.
Exhibit 10.1 Twelfth Amendment dated October 9, 2000 to the
Master Credit Support Agreement
Exhibit 27 Financial Data Schedule
(b) Reports on Form 8-K.
None
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
GENESIS ENERGY, L.P.
(A Delaware Limited Partnership)
By: GENESIS ENERGY, L.L.C., as
General Partner
Date: November 10, 2000 By: /s/ Ross A. Benavides
------------------------------
Ross A. Benavides
Chief Financial Officer