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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
--------------------------------
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2004
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 [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined by Rule 12b-2 of the Exchange Act.)
Yes [ ] No [X]
This report contains 29 pages
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GENESIS ENERGY, L.P.
FORM 10-Q
INDEX
Page
----
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets - March 31, 2004 and December 31, 2003 ................................. 3
Consolidated Statements of Operations for the Three Months Ended March 31, 2004 and 2003 ........... 4
Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2004 and 2003.. 5
Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2004 and 2003 ........... 6
Consolidated Statement of Partners' Capital for the Three Months Ended March 31, 2004 .............. 6
Notes to Consolidated Financial Statements ......................................................... 7
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations .............. 15
Item 3. Quantitative and Qualitative Disclosures about Market Risk ......................................... 28
Item 4. Controls and Procedures ............................................................................ 28
PART II. OTHER INFORMATION
Item 1. Legal Proceedings .................................................................................. 28
Item 6. Exhibits and Reports on Form 8-K ................................................................... 28
SIGNATURES .................................................................................................. 29
-2-
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
(Unaudited)
March 31, December 31,
2004 2003
--------- ------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents ............................... $ 340 $ 2,869
Accounts receivable-trade ............................... 74,406 66,732
Inventories ............................................. 1,240 1,546
Insurance receivable .................................... 8,937 15,524
Other ................................................... 1,309 1,540
--------- ---------
Total current assets ................................. 86,232 88,211
FIXED ASSETS, at cost ...................................... 71,095 70,695
Less: Accumulated depreciation ......................... (37,748) (36,724)
--------- ---------
Net fixed assets ..................................... 33,347 33,971
CO2 ASSETS, net of amortization ............................ 23,550 24,073
OTHER ASSETS, net of amortization .......................... 767 860
--------- ---------
TOTAL ASSETS ............................................... $ 143,896 $ 147,115
========= =========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable -
Trade ................................................ $ 66,184 $ 60,108
Related party ........................................ 8,718 7,067
Accrued liabilities ..................................... 8,654 20,069
--------- ---------
Total current liabilities ............................ 83,556 87,244
LONG-TERM DEBT ............................................. 9,900 7,000
COMMITMENTS AND CONTINGENCIES (Note 11)
MINORITY INTERESTS ......................................... 517 517
PARTNERS' CAPITAL
Common unitholders, 9,314 units issued and outstanding .. 48,917 51,299
General partner ......................................... 1,006 1,055
--------- ---------
Total partners' capital .............................. 49,923 52,354
--------- ---------
TOTAL LIABILITIES AND PARTNERS' CAPITAL .................... $ 143,896 $ 147,115
========= =========
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,
2004 2003
------------ ------------
REVENUES:
Crude oil gathering and marketing............................................ $ 192,996 $ 171,693
Crude oil pipeline........................................................... 4,085 3,989
CO2 revenues................................................................. 1,831 -
------------ ------------
Total revenues......................................................... 198,912 175,682
COST AND EXPENSES:
Crude oil costs:
Unrelated parties......................................................... 165,972 150,879
Related parties........................................................... 22,975 15,182
Field operating........................................................... 3,043 2,842
Crude oil pipeline operating costs........................................... 2,232 2,478
CO2 transportation costs - related party..................................... 591 -
General and administrative................................................... 3,164 2,277
Depreciation and amortization................................................ 1,547 1,144
Net gain on disposal of surplus assets....................................... - (44)
------------ ------------
OPERATING (LOSS) INCOME......................................................... (612) 924
OTHER INCOME (EXPENSE):
Interest income.............................................................. 24 8
Interest expense............................................................. (194) (550)
------------ ------------
(LOSS) INCOME FROM CONTINUING OPERATIONS........................................ (782) 382
(Loss) income from operations of discontinued Texas System...................... (223) 497
------------ ------------
NET (LOSS) INCOME............................................................... $ (1,005) $ 879
============ ============
NET INCOME PER COMMON UNIT - BASIC AND DILUTED:
(Loss) income from continuing operations..................................... $ (0.09) $ 0.04
(Loss) income from discontinued operations................................... (0.02) 0.06
------------ ------------
NET (LOSS) INCOME............................................................ $ (0.11) $ 0.10
============ ============
WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING............................. 9,314 8,625
============ ============
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
(Unaudited)
Three Months Ended March 31,
2004 2003
------------ ------------
NET (LOSS) INCOME............................................................... $ (1,005) $ 879
OTHER COMPREHENSIVE INCOME:
Change in fair value of derivatives used for hedging purposes............. - 39
------------ ------------
COMPREHENSIVE (LOSS) INCOME..................................................... $ (1,005) $ 918
============ ============
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,
2004 2003
-------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income ...................................................................... $ (1,005) $ 879
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation ........................................................................ 1,024 1,309
Amortization of CO2 contracts and covenant not-to-compete ........................... 523 206
Amortization and write-off of credit facility issuance costs ........................ 93 750
Change in fair value of derivatives ................................................. - 39
Gain on asset disposals ............................................................. - (44)
Other noncash charges ............................................................... 1,104 -
Changes in components of working capital -
Accounts receivable .............................................................. (7,674) (7,997)
Inventories ...................................................................... 306 3,550
Other current assets ............................................................. 6,818 226
Accounts payable ................................................................. 7,726 7,332
Accrued liabilities .............................................................. (12,518) (194)
-------- --------
Net cash (used in) provided by operating activities ...................................... (3,603) 6,056
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment .................................................... (400) (2,195)
Proceeds from sale of assets ........................................................... - 84
-------- --------
Net cash used in investing activities .................................................... (400) (2,111)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net borrowings (repayments) of debt .................................................... 2,900 (2,000)
Credit facility issuance fees .......................................................... - (1,093)
Distributions to common unitholders .................................................... (1,397) -
Distributions to General Partner ....................................................... (29) -
-------- --------
Net cash provided by (used in) financing activities ...................................... 1,474 (3,093)
-------- --------
Net (decrease) increase in cash and cash equivalents ..................................... (2,529) 852
Cash and cash equivalents at beginning of year ........................................... 2,869 1,071
-------- --------
Cash and cash equivalents at end of period ............................................... $ 340 $ 1,923
======== ========
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
-----------------------------------------------
Number of
Common Common General
Units Unitholders Partner Total
--------- ----------- ---------- ----------
Partners' capital at January 1, 2004 ...................................... 9,314 $ 51,299 $ 1,055 $ 52,354
Net income for the three months ended March 31, 2004 ...................... - (985) (20) (1,005)
Distributions to partners during the three months ended March 31, 2004 .... - (1,397) (29) (1,426)
------- ----------- ---------- ----------
Partners' capital at March 31, 2004 ....................................... 9,314 $ 48,917 $ 1,006 $ 49,923
======= =========== ========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
-6-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
Organization
Genesis Energy, L.P. ("GELP" or the "Partnership") is a publicly traded
Delaware limited partnership engaged in gathering, marketing and transportation
of crude oil and wholesale marketing of carbon dioxide (CO2). We were formed in
December 1996 through an initial public offering of 8.6 million Common Units,
representing limited partner interests in GELP of 98%. The General Partner of
GELP is Genesis Energy, Inc. (the "General Partner") which owns a 2% general
partner interest in GELP. The General Partner is owned by Denbury Gathering &
Marketing, Inc. a subsidiary of Denbury Resources Inc. Denbury and its
subsidiaries are hereafter referred to as Denbury.
In November 2003, an additional 0.7 million Common Units were sold to our
general partner in a private placement. These Common Units are not registered
with the Securities and Exchange Commission. See Note 4.
Genesis Crude Oil, L.P. is the operating limited partnership and is owned
99.99% by GELP and 0.01% by the General Partner. Genesis Crude Oil, L.P. has two
subsidiary partnerships, Genesis Pipeline Texas, L.P. and Genesis Pipeline USA,
L.P. Genesis Crude Oil, L.P. and its subsidiary partnerships will be referred to
as GCOLP.
Basis of Presentation
The accompanying financial statements and related notes present the
consolidated financial position as of March 31, 2004 and December 31, 2003 for
GELP and its results of operations, cash flows and changes in partners' capital
for the three months ended March 31, 2004 and 2003, and changes in comprehensive
income for the three months ended March 31, 2004 and 2003.
The financial statements included herein have been prepared by us 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, we believe 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 our Annual Report on Form 10-K for the year ended
December 31, 2003 filed with the SEC.
All significant intercompany transactions have been eliminated. Certain
reclassifications were made to prior period amounts to conform to current period
presentation. Such reclassifications had no effect on reported net income, total
assets, total liabilities or partners' equity.
No provision for income taxes related to the operation of GELP is included
in the accompanying consolidated financial statements; as such income will be
taxable directly to the partners holding partnership interests in the
Partnership.
2. NEW ACCOUNTING PRONOUNCEMENTS
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities" (FIN 46), which requires the consolidation of
variable interest entities, as defined. FIN 46, as revised, was applicable to
financial statements of companies that have interests in "special purpose
entities", as defined, during 2003. FIN 46 is applicable to financial statements
of companies that have interests in all other types of entities, in the first
quarter of 2004. We did not have any variable interest entities that were
required to be consolidated as a result of FIN 46.
3. DEBT
At March 31, 2004, we had $9.9 million outstanding under our credit
facility with a group of banks with Fleet National Bank as agent ("Fleet
Agreement"). Due to the revolving nature of loans under the Fleet Agreement,
additional borrowings and periodic repayments and re-borrowings may be made
until the maturity date of March 14,
-7-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2006. At March 31, 2004, we had letters of credit outstanding under the Fleet
Agreement totaling $13.4 million, comprised of $8.0 million and $4.6 million for
crude oil purchases related to March 2004 and April 2004, respectively and $0.8
million related to other business obligations.
Under the Fleet Agreement, distributions to Unitholders and the General
Partner can only be made if the Borrowing Base exceeds the usage (working
capital borrowings plus outstanding letters of credit) under the Fleet Credit
Facility by at least $10 million plus the distribution, measured once each
month. See additional discussion below under "Distributions".
4. PARTNERS' CAPITAL AND DISTRIBUTIONS
Partners' Capital
Until November 2003, partnership equity consisted of the general
partner interest of 2% and 8.6 million Common Units representing limited partner
interests of 98%. The Common Units were sold to the public in an initial public
offering in December 1996. In November 2003, we issued 688,811 additional Common
Units to our General Partner. At March 31, 2004, a total of 9,313,811 Common
Units were outstanding.
The general partner interest is held by our General Partner. The
Partnership is managed by the General Partner. The General Partner also holds a
0.01% general partner interest in GCOLP, which is reflected as a minority
interest in the consolidated balance sheet at March 31, 2004.
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.
Distributions
Generally, we will distribute 100% of our 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 our cash receipts less cash
disbursements adjusted for net changes to reserves. The target minimum quarterly
distribution ("MQD") for each quarter is $0.20 per unit. For the first three
quarters of 2003, we paid a regular quarterly distribution of $0.05 per unit
($0.4 million in total per quarter). Beginning with the fourth quarter of 2003,
we increased our quarterly distribution to $0.15 per unit ($1.4 million in
total). We have declared a $0.15 per unit distribution for the first quarter of
2004, payable on May 14, 2004 to unitholders of record on April 30, 2004.
Under the Fleet Agreement, a provision requires that the Borrowing
Base exceed the usage under the Fleet Agreement by at least $10 million plus the
quarterly distribution, measured once each month, in order for us to make a
distribution for the quarter.
Our general partner is entitled to receive incentive distributions if
the amount we distribute with respect to any quarter exceeds levels specified in
our partnership agreement. Under the quarterly incentive distribution
provisions, the general partner generally is entitled to receive 13.3% of any
distributions in excess of $0.25 per unit, 23.5% of any distributions in excess
of $0.28 per unit and 49% of any distributions in excess of $0.33 per unit
without duplication. We have not paid any incentive distributions through March
31, 2004.
-8-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Net Income Per Common Unit
The following table sets forth the computation of basic net income per
Common Unit (in thousands, except per unit amounts).
Three Months Ended March 31,
----------------------------
2004 2003
---------- ----------
Numerators for basic and diluted net income per common unit:
(Loss) income from continuing operations ..................... $ (782) $ 382
Less general partner 2% ownership ............................ (16) 8
---------- ----------
(Loss) income from continuing operations available for common
unitholders ............................................... $ (766) $ 374
========== ==========
(Loss) income from discontinued operations ................... $ (223) $ 497
Less general partner 2% ownership ............................ (4) 10
---------- ----------
(Loss) income from discontinued operations available for
common unitholders ........................................ $ (219) $ 487
========== ==========
Denominator for basic and diluted per Common Unit - weighted average
number of Common Units outstanding ............................. 9,314 8,625
========== ==========
Basic and diluted net income (loss) per Common Unit:
(Loss) income from continuing operations ..................... $ (0.09) $ 0.04
(Loss) income from discontinued operations ................... (0.02) 0.06
---------- ----------
Net (loss) income ............................................ $ (0.11) $ 0.10
========== ==========
5. BUSINESS SEGMENT INFORMATION
Our operations consist of three operating segments: (1) Crude Oil
Gathering and Marketing - the purchase and sale of crude oil at various points
along the distribution chain; (2) Crude Oil Pipeline Transportation - interstate
and intrastate crude oil pipeline transportation; and (3) CO2 marketing - the
sale of CO2 acquired under a volumetric production payment to industrial
customers. Prior to 2003, we managed our crude oil gathering, marketing and
pipeline operations as a single segment. The tables below reflect all periods
presented as though the current segment designations had existed, and include
only continuing operations data.
We evaluate segment performance based on segment margin before
depreciation and amortization. All of our revenues are derived from, and all of
our assets are located in the United States.
-9-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Crude Oil
-------------------------
Gathering and CO2
Marketing Pipeline Marketing Total
------------- ---------- ---------- ----------
(in thousands)
Three Months Ended March 31, 2004
Revenues:
External Customers .............................................. $ 192,996 $ 3,263 $ 1,831 $ 198,090
Intersegment (a) ................................................ - 822 - 822
---------- ---------- ---------- ----------
Total revenues of reportable segments ........................... $ 192,996 $ 4,085 $ 1,831 $ 198,912
========== ========== ========== ==========
Segment margin excluding depreciation and amortization (b) ...... $ 1,006 1,853 $ 1,240 $ 4,099
Capital expenditures ............................................ $ 51 $ 349 $ - $ 400
Maintenance capital expenditures ................................ $ 51 $ 104 $ - $ 155
Net fixed and other long-term assets ............................ $ 5,211 $ 28,903 $ 23,550 $ 57,664
Three Months Ended March 31, 2003
Revenues:
External Customers .............................................. $ 171,693 $ 3,211 $ - $ 174,904
Intersegment (a) ................................................ - 778 - 778
---------- ---------- ---------- ----------
Total revenues of reportable segments ........................... $ 171,693 $ 3,989 $ - $ 175,682
========== ========== ========== ==========
Segment margin excluding depreciation and amortization (b) ...... $ 2,790 1,511 $ - $ 4,301
Capital expenditures ............................................ $ 96 $ 854 $ - $ 950
Maintenance capital expenditures ................................ $ 96 $ 854 $ - $ 950
a) Intersegment sales were conducted on an arm's length basis.
b) Segment margin was calculated as revenues less cost of sales and operations
expense. A reconciliation of segment margin to operating (loss) income
from continuing operations for period presented is as follows:
Three Months Ended March 31,
----------------------------
2004 2003
----------- ------------
(in thousands)
Segment margin excluding depreciation and amortization........ $ 4,099 $ 4,301
General and administrative expenses........................... 3,164 2,277
Depreciation, amortization and impairment..................... 1,547 1,144
Net gain on disposal of surplus assets........................ - (44)
----------- ------------
Operating (loss) income from continuing operations............ $ (612) $ 924
=========== ============
6. DISCONTINUED OPERATIONS
In the fourth quarter of 2003, we sold a significant portion of our Texas
Pipeline System and the related crude oil gathering and marketing operations to
TEPPCO Crude Oil, L.P. Additionally we sold other segments of our
-10-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Texas Pipeline System that had been idled in 2002 to Blackhawk Pipeline, L.P.,
an affiliate of Multifuels, Inc. Some remaining segments not sold to these
parties were abandoned in place.
Costs incurred to dismantle abandoned segments during the first quarter of
2004 are included in discontinued operations. For the first quarter of 2003,
discontinued operations includes the operating results of the assets sold or
abandoned in the fourth quarter of 2003.
Operating results from the discontinued operations for the three months
ended March 31, 2004 and 2003 were as follows:
Three Months Ended March 31,
----------------------------
2004 2003
----------- ------------
(in thousands)
Revenues:
Gathering and marketing............................................... $ - $ 84,271
Pipeline.............................................................. - 1,929
----------- ------------
Total revenues..................................................... - 86,200
Costs and expenses:
Crude costs........................................................... - 82,230
Field operating costs................................................. 7 1,297
Pipeline operating costs.............................................. 216 1,718
General and administrative............................................ - 87
Depreciation and amortization......................................... - 371
----------- ------------
Total costs and expenses........................................... 223 85,703
----------- ------------
(Loss) income from operations from discontinued Texas System before
minority interests.................................................... $ (223) $ 497
=========== ============
7. TRANSACTIONS WITH RELATED PARTIES
Sales, purchases and other transactions with affiliated companies, in the
opinion of management, are conducted under terms no more or less favorable than
those conducted with unaffiliated parties.
Purchases of Crude Oil
Purchases of crude oil from Denbury for the three months ended March 31,
2004 and 2003 were $23.0 million and $15.2 million, respectively. Purchases from
Denbury are partially secured by letters of credit.
General and Administrative Services
We do not directly employ any persons to manage or operate our business.
Those functions are provided by the General Partner. We reimburse the General
Partner for all direct and indirect costs of these services. Total costs
reimbursed to the General Partner by us were $3.4 million and $4.0 million for
the three months ended March 31, 2004 and 2003, respectively.
Due to Related Parties
At March 31, 2004 and December 31, 2003, we owed Denbury $8.4 million
and $6.9 million, respectively, for purchases of crude oil. Additionally, we
owed Denbury $0.4 million and $0.1 million for CO2 transportation services at
March 31, 2004 and December 31, 2003, respectively. We had advanced $0.5 million
to the General Partner at March 31, 2004 for administrative services. We owed
the General Partner $0.1 million at December 31, 2003 for administrative
services.
Directors' Fees
In both the first quarter of 2004 and 2003, we paid $30,000 to Denbury
for the services of each of four of Denbury's officers who serve as directors of
the General Partner, the same rate at which our independent directors were paid.
-11-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
CO2 Volumetric Production Payment and Transportation
We acquired a volumetric production payment from Denbury in November
2003 for $24.4 million. Denbury charges us a transportation fee of $0.16 per Mcf
(adjusted for inflation) to deliver the CO2 for us to our customers. For the
three months ended March 31, 2004, we incurred $0.6 million for transportation
services related to our sales of CO2.
Financing
Our general partner guarantees our obligations under the Fleet Facility.
Our general partner that guarantees the obligations is a wholly-owned subsidiary
of Denbury. The obligations are not guaranteed by Denbury or any of its other
subsidiaries.
8. MAJOR CUSTOMERS AND CREDIT RISK
We derive our revenues from customers primarily in the crude oil industry.
This industry concentration has the potential to impact our overall exposure to
credit risk, either positively or negatively, in that our customers could be
affected by similar changes in economic, industry or other conditions. However,
we believe that the credit risk posed by this industry concentration is offset
by the creditworthiness of our customer base. Our portfolio of accounts
receivable is comprised in large part of major international corporate entities
with stable payment experience. The credit risk related to contracts which are
traded on the NYMEX is limited due to the daily cash settlement procedures and
other NYMEX requirements.
We have established various procedures to manage our credit exposure,
including initial credit approvals, credit limits, collateral requirements and
rights of offset. Letters of credit, prepayments and guarantees are also
utilized to limit credit risk to ensure that our established credit criteria are
met.
ExxonMobil Corporation, Marathon Ashland Petroleum LLC and Plains All
American, L.P. accounted for 15%, 14% and 10% of total revenues for the first
quarter of 2004, respectively. Marathon Ashland Petroleum LLC, ExxonMobil
Corporation and Shell Oil Company accounted for 25%, 14% and 14% of total
revenues during the first quarter of 2003, respectively. The majority of the
revenues from these four customers in both periods relate to our gathering and
marketing operations.
9. SUPPLEMENTAL CASH FLOW INFORMATION
Cash received by the Partnership for interest was $24,000 and $9,000 for
the three months ended March 31, 2004 and 2003, respectively. Payments of
interest and commitment fees were $52,000 and $130,000 for the three months
ended March 31, 2004 and 2003, respectively.
10. DERIVATIVES
Our market risk in the purchase and sale of crude oil contracts is the
potential loss that can be caused by a change in the market value of the asset
or commitment. In order to hedge our exposure to such market fluctuations, we
may enter into various financial contracts, including futures, options and
swaps. Historically, any contracts we have used to hedge market risk were less
than one year in duration. During the first quarter of 2004 we did not use any
hedging instruments.
We may utilize crude oil futures contracts and other financial derivatives
to reduce our exposure to unfavorable changes in crude oil prices. Every
derivative instrument (including certain derivative instruments embedded in
other contracts) must be recorded in the balance sheet as either an asset or
liability measured at its fair value. Changes in the derivative's fair value
must 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.
We mark to fair value our derivative instruments at each period end with
changes in fair value of derivatives not designated as hedges being recorded as
unrealized gains or losses. Such unrealized gains or losses will change,
-12-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
based on prevailing market prices, at each balance sheet date prior to the
period in which the transaction actually occurs. Unrealized gains or losses on
derivative transaction qualifying as hedges are reflected in other comprehensive
income.
We regularly review our contracts to determine if the contracts qualify for
treatment as derivatives. We had no contracts qualifying for treatment as
derivatives at March 31, 2004 or December 31, 2003. We determined that all of
our derivative contracts qualified for the normal purchase and sale exemption
and were designated as such at those dates.
11. CONTINGENCIES
Guarantees
We have guaranteed $3.3 million of residual value related to our leases
of tractors and trailers. We believe the likelihood we would be required to
perform or otherwise incur any significant losses associated with this guaranty
is remote.
GELP has guaranteed crude oil purchases of GCOLP. These guarantees,
totaling $12.4 million, were provided to counterparties. To the extent
liabilities exist under the contracts subject to these guarantees, such
liabilities are included in the consolidated balance sheet.
GELP, the General Partner and the subsidiaries of GCOLP have guaranteed
the payments by GCOLP to Fleet under the terms of the Fleet Facility related to
borrowings and letters of credit. Borrowings at March 31, 2004 were $9.9 million
and are reflected in the consolidated balance sheet. To the extent liabilities
exist under the letters of credit, such liabilities are included in the
consolidated balance sheet.
Pennzoil Litigation
We were named one of the defendants in a complaint filed on January 11,
2001, in the 125th District Court of Harris County, Texas, Cause No. 2001-01176.
Pennzoil-Quaker State Company ("PQS") was seeking property damages, loss of use
and business interruption suffered as a result of a fire and explosion that
occurred at the Pennzoil Quaker State refinery in Shreveport, Louisiana, on
January 18, 2000. PQS claimed the fire and explosion were caused, in part, by
Genesis selling to PQS crude oil that was contaminated with organic chlorides.
In December 2003, our insurance carriers settled this litigation for $12.8
million. The settlement was funded in February 2004, with certain insurance
companies directly funding $5.9 million of the payment and $6.9 million was
funded by us. We received reimbursement of the $6.9 million from the insurance
company on May 3, 2004.
PQS is also a defendant in five suits brought by neighbors living in the
vicinity of the PQS Shreveport, Louisiana refinery in the First Judicial
District Court, Caddo Parish, Louisiana, Cause Nos. 455,647-A. 455,658-B,
455,655-A, 456,574-A, and 458,379-C. PQS has brought third party demand against
Genesis and others for indemnity with respect to the fire and explosion of
January 18, 2000. We believe that the demand against Genesis is without merit
and intend to vigorously defend ourselves in this matter.
Environmental
On December 20, 1999, we had a spill of crude oil from our Mississippi
System. Approximately 8,000 barrels of oil spilled from the pipeline near
Summerland, Mississippi, and entered a creek nearby. A portion of the oil then
flowed into the Leaf River. The oil spill is covered by insurance and the direct
financial impact to us of the cost of the clean-up has not been material.
Included in insurance receivable on the consolidated balance sheet at March 31,
2004 and December 31, 2003 is $2.0 million and $2.8 million, respectively,
related to this spill. Management of the Partnership has reached an agreement in
principle with the US Environmental Protection Agency and the Mississippi
Department of Environmental Quality for the payment of fines under environmental
laws with respect to this oil spill. Based on this agreement in principle, in
2001 and 2002, a total accrual of $3.0 million was recorded for these fines. The
fines will not be covered by insurance.
-13-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We are subject to various environmental laws and regulations. Policies
and procedures are in place to monitor compliance and to detect and address any
releases of crude oil from our pipelines or other facilities, however no
assurance can be made that such environmental releases may substantially affect
our business.
Other Matters
We have taken additional security measures since the terrorist attacks
of September 11, 2001 in accordance with guidance provided by the Department of
Transportation and other government agencies. We cannot assure you that these
security measures would prevent our facilities from a concentrated attack. Any
future attacks on us or our customers or competitors could have a material
effect on our business, whether insured or not. We believe we are adequately
insured for public liability and property damage to others and that our coverage
is similar to other companies with operations similar to ours. No assurance can
be made that we will be able to maintain adequate insurance in the future at
premium rates that we consider reasonable.
We are 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 our financial
position, results of operations or cash flows.
12. SUBSEQUENT EVENT
On April 14, 2004, the Board of Directors of the General Partner declared a
cash distribution of $0.15 per Unit for the quarter ended March 31, 2004. The
distribution will be paid May 14, 2004, to the General Partner and all Common
Unitholders of record as of the close of business on April 30, 2004.
-14-
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Included in Management's Discussion and Analysis are the following
sections:
- Overview
- Results of Operations and Outlook for the Remainder of 2004 and
Beyond
- Liquidity and Capital Resources
- Commitments and Off-Balance Sheet Arrangements
- Other Matters
In the discussions that follow, we will focus on two measures that we use
to manage the business and to review the results of our operations. Those two
measures are segment margin and available cash. Our profitably depends to a
significant extent upon our ability to maximize segment margin. Segment margin
is calculated as revenues less costs of sales and operating expense, and does
not include depreciation and amortization. A reconciliation of Segment Margin (a
non-GAAP financial measure) to operating income from continuing operations is
included in our segment disclosures in Note 5 to the consolidated financial
statements. Available Cash is a non-GAAP liquidity measure calculated as net
income with several adjustments, the most significant of which are the
elimination of gains and losses on asset sales, except those from the sale of
surplus assets, the addition of non-cash expenses such as depreciation and
amortization, and the subtraction of maintenance capital expenditures, which are
expenditures to sustain existing cash flows but not to provide new sources of
revenues. For additional information on Available Cash and a reconciliation of
this measure to cash flows from operations, see "Non-GAAP Financial Measure"
below.
OVERVIEW
We operate in three business segments - crude oil gathering and marketing,
crude oil pipeline transportation and CO2 marketing. Our revenues are earned by
selling crude oil and CO2 and by charging fees for transportation of crude oil
through our pipelines. Our focus is on the margin we earn on these revenues,
which is calculated by subtracting the costs of the crude oil, the costs of
transporting the crude oil and CO2 to the customer, and the costs of operating
our assets.
Our primary goal is to generate Available Cash for our unitholders. This
Available Cash is then distributed quarterly to our unitholders.
We had a loss for the first quarter of 2004 resulting primarily from the
effects of increasing the liability under an incentive compensation plan. We
have a stock appreciation rights plan under which employees and directors are
granted rights to receive cash upon exercise for the difference between the
strike price of the rights and the market price for our units at the time of
exercise. These rights vest over several years. As of March 31, 2004, no rights
were vested. As the market price for our units increases or decreases, we record
an increase or a decrease in our liability under this plan. In the first quarter
of 2004, our unit price increased 27%. As our unit price rose from $9.80 at
December 31, 2003 to $12.45 per unit at March 31, 2004, we increased our
liability during the first quarter from $0.2 million to $1.3 million, recording
a charge of $1.1 million.
We generated Available Cash during the quarter equal to our distribution
for the quarter. Additionally, we are making progress toward our initiatives to
expand our credit facility to make accretive acquisitions.
RESULTS OF OPERATIONS AND OUTLOOK FOR THE REMAINDER OF 2004 AND BEYOND
The following table summarizes financial data by segment for this
discussion of the results of operations. (in thousands, except volumes per day).
-15-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Three Months Ended March 31,
2004 2003
----------- ------------
Revenues
Crude oil gathering and marketing........................... $ 192,996 $ 171,693
Crude oil pipeline.......................................... 4,085 3,989
CO2 marketing............................................... 1,831 -
----------- ------------
Total revenues................................................. $ 198,912 $ 175,682
=========== ============
Segment margin
Crude oil gathering and marketing........................... $ 1,006 $ 2,790
Crude oil pipeline.......................................... 1,853 1,511
CO2 marketing............................................... 1,240 -
----------- ------------
Total segment margin........................................... 4,099 4,301
General and administrative expenses............................ 3,164 2,277
Depreciation and amortization.................................. 1,547 1,144
Net gain on disposal of surplus assets......................... - (44)
----------- ------------
Operating (loss) income........................................ (612) 924
Interest expense, net.......................................... (170) (542)
----------- ------------
(Loss) income from continuing operations....................... (782) 382
(Loss) income from discontinued operations..................... (223) 497
----------- ------------
Net (loss) income.............................................. $ (1,005) $ 879
=========== ============
Volumes per day from continuing operations:
Crude oil wellhead - barrels................................ 48,445 45,869
Crude oil total - barrels................................... 60,591 56,313
Crude oil pipeline - barrels................................ 68,583 67,728
CO2 - Mcf................................................... 39,173 -
CRUDE OIL GATHERING AND MARKETING OPERATIONS
The key drivers affecting our crude oil gathering and marketing segment
margin include production volumes, volatility of P-Plus, volatility of grade
differentials, inventory management, and credit costs.
Segment 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 segment 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 segment 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
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. Additionally, we
enter into exchange transactions with third parties, generally 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 margins or meet contract delivery
requirements.
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. Through these transactions, we seek
to maintain a position that is substantially balanced between crude oil
purchases, on the one hand, and sales or
-16-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
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.
Most of our contracts for the purchase and sale of crude oil have
components in the pricing provisions such that the price paid or received is
adjusted for changes in the market price for crude oil. Often the pricing in a
contract to purchase crude oil will consist of the market price component and a
bonus, which is generally a fixed amount ranging from a few cents to several
dollars. Typically the pricing in a contract to sell crude oil will consist of
the market price component and a bonus that is not fixed, but instead is based
on another market factor. This floating bonus is usually the price quoted by
Platt's for WTI "P-Plus". Because the bonus for purchases of crude oil is fixed
and P-Plus floats in the sales contracts, the margin on individual transactions
can vary from month-to-month depending on changes in the P-Plus component.
P-Plus does not necessarily move in correlation with the price of crude
oil in the market. P-Plus is affected by numerous factors such as future
expectations for changes in crude oil prices, such that crude oil prices can be
rising, but P-Plus can be decreasing. The table below shows the average P-Plus
and the average posted price for West Texas Intermediate (WTI) as posted by Koch
Supply & Trading, L.P. by quarter in 2003 and 2004, based on the simple
averaging of the monthly averages.
Quarter P-Plus WTI Posting
- --------- ------- -----------
2003
First $4.1336 $ 30.6306
Second $4.6063 $ 25.7125
Third $4.0336 $ 27.0065
Fourth $3.4881 $ 27.9642
2004
First $3.9137 $ 31.8518
As can be seen from this table, changes in P-Plus do not necessarily
correspond to changes in the market price of oil. An example is the decline in
P-Plus between the third and fourth quarters of 2003 when the WTI posting
increased. This unpredictable volatility in P-Plus can create volatility in our
earnings.
A few purchase contracts and some sale contracts also include a
component for grade differentials. The grade refers to the type of crude oil.
Crude oils from different wells and areas can have different chemical
compositions. These different grades of crude oil will appeal to different
customers depending on the processing capabilities of the refineries that
ultimately process the crude oil. We may buy crude oil under a contract where we
considered the typical grade differences in the market when we set the fixed
bonus. If we then sell the oil under a contract with a floating grade
differential in the formula, and that grade differential fluctuates, then we can
experience an increase or decrease in our margin from that oil purchase and
sale. The table below shows the grade differential between West Texas
Intermediate grade crude oil and West Texas Sour grade crude oil, using the
monthly averages for each quarter 2003 and 2004, and the differential between
West Texas Intermediate grade crude oil and Light Louisiana Sweet grade crude
oil for the same periods.
WTI/WTS WTI/LLS
Quarter Differential Differential
- --------- ------------ ------------
2003
First $(2.361) $ 0.460
Second $(3.189) $(0.216)
Third $(2.443) $(0.234)
Fourth $(2.711) $ 0.320
2004
First $(2.876) $ 0.404
-17-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
As can be seen from this table, the WTI/LLS market differential varied
from a negative $0.234 per barrel in the third quarter of 2003 to a positive
$0.404 in the first quarter of 2004. This volatility in grade differentials can
affect the volatility of our gathering and marketing segment margin.
Our purchase and sales contracts are primarily "Evergreen" contracts,
which means they continue from month to month unless one of the parties to the
contract gives 30-days notice of cancellation. In order to change the pricing in
a fixed bonus contract, we would have to give 30-days notice that we want to
cancel or renegotiate the contract. This notice time requirement, therefore,
means that at least a month will pass before the fixed bonus can be reduced to
correspond with a decrease in the P-Plus component of the related sales
contract. In this case, our margin would be reduced until such a change is made.
Because of the volatility of P-Plus, it is not practical to renegotiate every
purchase contract for every change in P-Plus. So segment margins from the sale
of the crude oil may be volatile as a result of these timing differences.
Another factor that can contribute to volatility in our earnings is
inventory management. Generally contracts for the purchase of crude oil will
state that we will buy all of the production for the month from a particular
well. We generally aggregate the volumes purchased from numerous wells and
deliver it into a pipeline where we sell the crude oil to a third party. While
oil producers can make estimates of the volume of oil that their wells will
produce in a month, they cannot state absolutely how much oil will be produced.
Our sales contracts typically state a specific volume to be sold. Consequently,
if a well produces more than expected, we will purchase volumes in a month that
we have not contracted to sell. These volumes are then held as inventory and are
sold in a later month. Should the market price of crude oil fluctuate while we
have these inventory volumes, we would have to recognize a loss in our financial
statements should the market price fall below the cost of the inventory. Should
market prices rise, then we will realize a gain when we sell the unexpected
volume of inventory in a later month at higher prices. We make every effort to
limit our exposure to these price fluctuations by minimizing inventory volumes.
Three Months Ended March 31, 2004 as Compared to Three Months Ended
March 31, 2003
Gathering and marketing segment margins from continuing operations
decreased $1.8 million or 64% to $1.0 million for the three months ended March
31, 2004, as compared to $2.8 million for the three months ended March 31, 2003.
A $2.1 million decrease 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, was the primary reason for this decline.
Factors offsetting this decrease were:
- A 9% increase in wellhead, bulk and exchange purchase
volumes between first quarters of 2003 and 2004,
resulting in a $0.5 million increase in segment margin;
and
- a $0.2 million increase in field operating costs,
primarily from increased fuel costs to operate our
tractor/trailers and higher insurance costs. Although we
reduced our operations in 2004 from 2003 levels, our
insurance costs did not decline proportionately.
Field operating costs primarily consist of the costs to operate our
fleet of 49 trucks used to transport crude oil, and the costs to maintain the
trucks and assets used in the crude oil gathering operation. Approximately 55%
of these costs are variable and increase and decrease with volumetric changes.
Such costs include payroll and benefits (as drivers are paid on a commission
basis based on volumes), maintenance costs for the trucks (as we lease the
trucks under full service maintenance contracts under which we pay a maintenance
fee per mile driven), and fuel costs. Fuel costs also fluctuate based on changes
in the market price of diesel fuel. Fixed costs include the base lease payment
for the vehicle, insurance costs and costs for environmental and safety related
items.
Outlook for 2004 and Beyond
We expect volatility in P-Plus to continue. During 2004, we expect our
crude oil gathering and marketing business to generate at least as much segment
margin as it did in 2003; however, no assurance can be made that this
-18-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
will occur. Our plans include increasing volumes by acquiring new production and
production currently being gathered by other parties. Additionally we are
reviewing our costs and operating methods to reduce costs and increase
efficiencies.
CRUDE OIL PIPELINE OPERATIONS
We operate three common carrier pipeline systems in a five state area.
We refer to these pipelines as our Texas System, Mississippi System and Jay
System. Volumes shipped on these systems for the first quarters of 2004 and 2003
are as follows (barrels per day):
Three Months Ended
March 31,
------------------
Pipeline System 2004 2003
- --------------- ------ ------
Texas 42,206 43,178
Mississippi 10,495 9,295
Jay 15,882 15,255
In 2003, we sold or abandoned significant portions of our Texas System.
The segments we retained and continue to operate are from West Columbia to
Webster, Cullen Junction to Webster, and from Webster to Texas City, and Webster
to a shipper's facility in Houston. Information on the segments sold or
abandoned is discussed in the section "Discontinued Operations" below. The
following information pertains only to continuing operations.
Volumes on our Texas System averaged 42,206 barrels per day during the
first quarter of 2004. The crude oil that enters our system comes to us at West
Columbia and Cullen Junction where we have connections to TEPPCO's South Texas
System and at Webster where we have a connection with another pipeline. Under
the terms of our sale to TEPPCO of portions of the pipeline, we have a joint
tariff with TEPPCO through September 2004 under which we earn $0.40 per barrel
on the majority of the barrels we deliver to the shipper's facilities and $0.50
per barrel on heavier crude oil we deliver. Most of the volume being shipped on
our Texas System goes to three refineries on the Texas Gulf Coast. We are still
shipping substantially the same volumes that we were shipping before the sale to
TEPPCO, however our tariff revenue is much less than before the sale, as we ship
the crude oil over a shorter distance.
The Mississippi System is best analyzed in two segments. The first
segment is the portion of the pipeline that begins in Soso, MS and extends to
Liberty, MS. At Liberty, shippers can transfer the crude oil to a connection to
Capline, a pipeline system that moves crude oil from the Gulf Coast to
refineries in the Midwest. The segment from Soso to Liberty has also been
improved to handle the increased volumes produced by Denbury and transported on
the pipeline. In order to handle future increases in production volumes in the
area that are expected, we have made capital expenditures for tank, station and
pipeline improvements and we intend to make further improvements. See Capital
Expenditures under "Liquidity and Capital Resources" below.
The second segment of the pipeline from Liberty to near Baton Rouge, LA
has been out of service since February 1, 2002 while a connecting carrier tested
its pipeline. The connecting carrier has decided not to reactivate its pipeline
at this time, so we will displace the crude oil in this segment with inhibited
water until the connecting carrier either repairs its system or we identify an
alternative use for this segment. The cost of this displacement is being paid
for by the owner of the crude oil. In 2004 and 2003, this segment made no
contribution to pipeline revenues.
The Jay pipeline system in Florida/Alabama ships crude oil from fields
with relatively short remaining production lives. Volumes between the first
quarters of 2004 and 2003 have increased slightly. Many of the costs to operate
our pipeline are fixed costs, including the costs of environmental compliance
and the costs of insurance, so the declines in volumes from prior years
necessitated increases in our tariffs. The only shipper on the largest portion
of the pipeline agreed to a tariff rate increase in July 2003 that has helped
offset the declines in the volumes and increased costs of operating this
pipeline.
-19-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Historically, the largest operating costs in our crude oil pipeline
segment have consisted of personnel costs, power costs, maintenance costs and
costs of regulatory compliance. Some of these costs are not predictable, such as
failures of equipment, or are not within our control, like power cost increases.
We perform regular maintenance on our assets to keep them in good operational
condition to minimize cost increases.
Three Months Ended March 31, 2004 Compared with Three Months Ended March
31, 2003
Pipeline segment margin increased $0.4 million or 23% to $1.9 million
for the three months ended March 31, 2004, as compared to $1.5 million for the
three months ended March 31, 2003. The increase in pipeline segment margin is
primarily attributable to a decrease in pipeline operating costs. In the first
quarter of 2003, we performed a hydrotest of the segment of pipeline from
Webster to Texas City at a cost of approximately $0.3 million. This test will
not have to be repeated for several years.
Revenues increased $0.1 million in the first quarter of 2004 compared to
the prior year period due to the combination of higher tariffs and slightly
greater volumes.
Outlook for 2004 and Beyond
In April 2004, we began receiving the barrels at Webster that we had
been receiving at Cullen Junction from TEPPCO. The new connection at Webster
with ExxonMobil Pipe Line Company was established at TEPPCO's request as an
alternative method to ship the crude oil. After September 2004, we expect to
continue to provide capacity to transport crude oil on our Texas System from
Webster to Texas City and Houston.
Through September 2004, we will continue to receive a tariff of $0.40 on
the volumes shipped from the ExxonMobil connection. After September 2004, we
expect to receive less tariff income from those shipments than we are receiving
under the current joint tariff with TEPPCO and ExxonMobil. We are also examining
strategic opportunities to place the remaining segments in alternative service
after the arrangement with TEPPCO expires.
We expect that volumes on the Texas System may decline as refiners on
the Texas Gulf Coast compete for crude oil with other markets connected to
TEPPCO's pipeline systems; however, those effects may not occur until the summer
of 2004 when TEPPCO finishes its integration and connection of the segments
acquired from us.
As discussed above, the primary shipper on the segment of our
Mississippi pipeline from Liberty to near Baton Rouge advised us in February
2004 that it does not have plans to reinstate shipments on this segment of
pipeline. We currently plan to temporarily idle this segment of pipeline by
removing the crude oil from the line while we evaluate future plans for this
segment. Any future plans in crude oil service will require sufficient volumes
being available to be transported on this segment of pipeline to justify the
costs to perform the integrity testing and upgrading that may be necessary as a
result of that testing. Future plans for this segment may include connecting the
segment to alternative transportation services.
Denbury is the largest oil and gas producer in Mississippi. Our
Mississippi pipeline is adjacent to several of Denbury's existing and
prospective oil fields. There may be mutual benefits to Denbury and us due to
this common production and transportation area. Because of this relationship, we
may be able to obtain certain commitments for increased crude oil volumes, while
Denbury may obtain the certainty of transportation for its oil production at
competitive market rates. As Denbury continues to acquire and develop old oil
fields using CO2 based tertiary recovery operations, Denbury would expect to add
crude oil gathering and CO2 supply infrastructure to these fields. Further, as
the fields are developed over time, it may create increased demand for our crude
oil transportation services.
The production shipped from oil fields surrounding our Jay system is a
combination of new fields with estimated short production lives and older fields
that have been producing for twenty to thirty years and are in the later stages
of their economic lives. We believe that the highest and best use of the Jay
system would be to convert it to natural gas service. We continue to review
strategic alternatives to develop this opportunity. This initiative is in a very
preliminary stage. Part of the process will involve finding alternative methods
for us to continue to provide crude oil transportation services in the area.
While we believe this initiative has long-term potential, it is not expected to
have a substantial impact on us during 2004 or 2005.
-20-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Pipeline segment margins from continuing operations should remain flat
or decline slightly in 2004. We expect volume increases on the Mississippi
system and the tariff increases on the Jay system to substantially offset
increases in fixed costs, including the costs for testing under the integrity
management program.
CARBON DIOXIDE (CO2) OPERATIONS
In November 2003, we acquired a volumetric production payment of 167.5
Bcf of CO2 from Denbury. Denbury owns 1.6 trillion cubic feet of estimated
proved reserves of CO2 in the Jackson Dome area near Jackson, Mississippi. In
addition to the production payment, Denbury also assigned to us three of their
existing long-term CO2 contracts with industrial customers. Denbury owns the
pipeline that is used to transport the CO2 to our customers as well as to its
own tertiary recovery operations.
The industrial customers treat the CO2 and transport it to their own
customers. The primary industrial applications of CO2 by these customers include
beverage carbonation and food chilling and freezing. Based on Denbury's
experience, we can expect some seasonality in our sales of CO2, as the dominant
months for beverage carbonation and freezing food are from April to October,
when warm weather drives up demand for beverages and the approaching holidays
increase demand for frozen foods.
Volumes sold by Denbury during the first quarter of 2003 under the
contracts that we acquired averaged 37,388 Mcf per day. During the first quarter
of 2004 we sold 39,173 Mcf per day under these contracts. We paid Denbury $0.16
per Mcf , or $0.6 million, to transport the CO2 to our customers on Denbury's
pipeline.
We expect to generate approximately $5 million of annual segment margin
from this business during the first five years. The purchase of these assets
provides us with diversity in our asset base and a stable long-term source of
cash flow.
DISCONTINUED OPERATIONS
In the fourth quarter of 2003, we sold a significant portion of our
Texas Pipeline System and the related crude oil gathering and marketing
operations to TEPPCO Crude Oil, L.P. Additionally we sold other segments of our
Texas Pipeline System that had been idled in 2002 to Blackhawk Pipeline, L.P.,
an affiliate of Multifuels, Inc. Other remaining segments not sold to these
parties were abandoned in place.
Three Months Ended March 31, 2004 Compared with Three Months Ended March
31, 2003
During the first quarter of 2004, we incurred costs totaling $0.2
million related to the dismantlement of assets that we abandoned. During the
first quarter of 2003, the assets we disposed during the fourth quarter of 2003
generated $0.5 million of segment margin.
OTHER COSTS AND INTEREST
Three Months Ended March 31, 2004 Compared with Three Months Ended March
31, 2003
General and administrative expenses. General and administrative expenses
increased $0.9 million in the 2004 period as compared to the 2003 period. We
recorded expense of $1.1 million related to our stock appreciation rights plan
for employees and directors in the first quarter of 2004. This plan is a
long-term incentive plan whereby rights are granted for the grantee to receive
cash equal to the difference between the grant price and Common Unit price at
date of exercise. The rights vest over several years. Our unit price rose 27%
from $9.80 at December 31, 2003 to $12.45 at March 31, 2004 resulting in a $1.1
million increase to the accrual for this liability.
Offsetting this increase was a reduction in professional services fees.
In the 2003 first quarter period, we charged to expense $0.2 million of
unamortized legal and consultant costs related to a credit facility that was
replaced.
Excluding the effect of changes in our unit price on our accrual for our
stock appreciation rights plan, we expect general and administrative expenses in
2004 to remain level with those of 2003. We expect to incur costs in
-21-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
2004 for consultants related to the internal documentation and assessment
provisions of the Sarbanes-Oxley Act that will offset the 2003 write-off of
credit facility costs.
Interest expense, net. In the 2004 first quarter, our net interest
expense decreased by $0.4 million compared to the 2003 period. The primary
reason for this decrease was the write-off in 2003 of unamortized facility fees
related to a credit facility that was replaced in that quarter.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
Our primary sources of cash flows are operations and credit facilities.
Our primary uses of cash flows are capital expenditures and distributions. A
summary of our cash flows is as follows:
Three Months Ended March 31,
-----------------------------
2004 2003
----------- ------------
(in thousands)
Cash provided by (used in):
Operating activities............ $ (3,603) $ 6,056
Investing activities............ $ (400) $ (2,111)
Financing activities............ $ 1,474 $ (3,093)
Operating. Net cash from operating activities for each period have been
comprised of the following:
Three Months Ended March 31,
----------------------------
2004 2003
----------- -------------
(in thousands)
Net (loss) income................................... $ (1,005) $ 879
Depreciation, amortization and impairment........... 1,640 2,265
Gain on sales of assets............................. - (44)
Other non-cash items................................ 1,104 39
Changes in components of working capital, net....... (5,342) 2,917
----------- -------------
Net cash from operating activities............... $ (3,603) $ 6,056
=========== =============
Our operating cash flows are affected significantly by changes in items
of working capital. In the 2004 period we temporarily funded $6.9 million of a
litigation settlement with funds we borrowed and funds on hand. We were
reimbursed for this payment by insurers in May 2004, however, at March 31, 2004,
we had a net cash outflow related to this payment. Affecting all periods is the
timing of capital expenditures and their effects on our recorded liabilities.
Our cash management in the crude oil gathering and marketing business
functions is as follows. All purchases and sales are settled monthly with
payment on the 20th of the following month. We receive payment for sales by wire
transfer on the 20th. Approximately 75% of the obligations for purchases are
also paid by wire transfer on the 20th. The remaining purchases are paid for by
check. These checks, primarily to royalty owners and small oil companies,
generally take five or six days to clear our bank account. This payment cycle
provides several benefits to us. We know that substantially all of our
receivables for crude oil sales will be collected on the 20th. We also defer
payment until checks that were mailed clear our checking accounts. Our
borrowings, and therefore our interest costs, are reduced for this short time
period each month following the 20th.
Similarly, tariffs are billed monthly and require payment ten days after
the invoice date. Therefore collection of our pipeline accounts receivable is
usually timely since shippers generally want to continue shipping without
interruption.
Our accounts receivable settle monthly and collection delays generally
relate only to discrepancies or disputes as to the appropriate price, volume or
quality of crude oil delivered. Of the $74.4 million aggregate
-22-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
receivables on our consolidated balance sheet at March 31, 2004, approximately
$72.2 million, or 97%, were less than 30 days past the invoice date.
Investing. Cash flows used in investing activities in the first quarter
of 2004 were $0.4 million as compared to $2.1 million in 2003 period. In 2004 we
expended $0.2 million for the first phase of an addition to our Mississippi
System, by acquiring right-of-ways to be used for a crude oil pipeline and a CO2
pipeline of approximately ten miles. We expended $0.2 million for other capital
improvements related to our corporate office and to handling the increased
volumes on our Mississippi System more efficiently.
In the first quarter of 2003 we expended $2.2 million for property and
equipment additions, and received $0.1 million from the sale of surplus assets.
The expenditures included replacement of pipe in Texas and satellite
communication equipment for our control and monitoring system for all three of
our pipelines.
Financing. In the first quarter of 2004, financing activities provided
net cash of $1.5 million. Our outstanding debt increased $2.9 million, primarily
related to the funding of a litigation settlement for which we received
reimbursement in May 2004. Distributions to our partners utilized $1.4 million.
Net cash expended for financing activities was $3.1 million in the first
quarter of 2003. In 2003 we reduced our outstanding long-term debt balance by
$2.0 million from the balance at December 31, 2002. We also paid $1.1 million in
credit facility issuance costs related to a new credit facility put in place in
March 2003.
Capital Expenditures
A summary of our capital expenditures in the three months ended March
31, 2004 and 2003 is as follows:
Three Months Ended March 31,
----------------------------
2004 2003
----------- -----------
(in thousands)
Maintenance capital expenditures:
Texas pipeline system......................... $ 8 $ 770
Mississippi pipeline system................... 91 592
Jay pipeline system........................... 5 146
Crude oil gathering assets.................... - 62
Administrative assets......................... 51 74
----------- -----------
Total maintenance capital expenditures..... 155 1,644
Growth capital expenditures:
Mississippi pipeline system................... 245 -
Crude oil gathering assets.................... - 551
----------- -----------
Total growth capital expenditures.......... 245 551
----------- -----------
Total capital expenditures.............. $ 400 $ 2,195
=========== ===========
Maintenance capital expenditures in 2004 included station improvements
in Mississippi to handle increased volumes. Administrative assets included
computer software and hardware. In the 2003 period, maintenance capital
expenditures included a total of $0.4 million for the installation of pipeline
satellite monitoring equipment on all three systems. In the first quarter of
2003, we continued to upgrade the West Columbia to Markham segment of our Texas
pipeline. The expenditures on the Mississippi system included additional
improvements to the pipeline from Soso to Gwinville, where the crude oil spill
had occurred in December 1999, to restore this segment to service. We also
improved the pipeline from Gwinville to Liberty to be able to handle increased
volumes on that segment by upgrading pumps and meters and completing additional
tankage.
Growth capital expenditures in the first quarter of 2004 related to the
acquisition of right-of-way for a ten mile extension of our crude oil pipeline
and a CO2 pipeline to Denbury's Brookhaven field. This extension should be
complete by the end of the third quarter of 2004. Growth capital expenditures in
2003 included the acquisition of a condensate storage facility in Texas that was
subsequently sold to TEPPCO.
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GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Although we have no commitments to make capital expenditures, based on
the information available to us at this time, we currently anticipate that our
maintenance capital expenditures will be as follows:
2004 2005 2006
-------- --------- ---------
(in thousands)
Maintenance capital expenditures:
Texas System........................... $ 106 $ 396 $ 199
Mississippi System..................... 455 1,593 969
Jay System............................. 30 145 75
Other.................................. 167 60 60
-------- --------- ---------
Total maintenance capital expenditures...... $ 758 $ 2,194 $ 1,303
======== ========= =========
In 2004, we expect the expenditures on our Texas system to relate
primarily to corrosion control and in 2005 and 2006, to improvements to our
control and monitoring system.
The maintenance capital expenditure estimates for our Mississippi system
include corrosion control expenditures, minor facility improvements and
rehabilitation of the pipeline as a result of integrity management test results.
Additionally we have growth capital expenditures currently underway in 2004 to
extend our Mississippi crude oil pipeline and add a CO2 pipeline in the same
right-of-way. The CO2 pipeline will be used to supply Denbury's Brookhaven field
with CO2 for tertiary recovery and the crude oil pipeline will be used to move
the resulting crude oil production to market. We also will build an extension
from our existing crude oil pipeline to move crude oil from Denbury's
Smithdale/McComb fields. We anticipate that we will spend approximately $8.2
million to complete these projects in 2004.
Expenditures on capital assets to grow the partnership will depend on
our access to debt and capital discussed below in "Sources of Future Capital."
Those acquisitions may include the acquisition of additional CO2 assets from
Denbury and the construction of CO2 and crude oil pipelines to access Denbury's
crude oil fields in Mississippi. Denbury owns additional CO2 industrial sales
contracts that we might be able to purchase along with additional volume under
our production payment. We may also construct and operate additional CO2
pipelines next to crude oil pipelines to supply Denbury's fields with the CO2
for tertiary recovery and then to move the resulting crude oil production to
market. We will also look for opportunities to acquire assets from other parties
that meet our criteria for stable cash flows.
Capital Resources
At March 31, 2004, we had $9.9 million outstanding under our credit
facility with a group of banks with Fleet National Bank as agent ("Fleet
Facility"). Due to the revolving nature of loans under the Fleet Facility,
additional borrowings and periodic repayments and re-borrowings may be made
until the maturity date of March 14, 2006. At March 31, 2004, we had letters of
credit outstanding under the Fleet Facility totaling $13.4 million, comprised of
$8.0 million and $4.6 million for crude oil purchases related to March 2004 and
April 2004, respectively and $0.8 million related to other business obligations.
Outstanding letters of credit issued to Denbury for the purchase of crude oil at
March 31, 2004, totaled $3.7 million, and are included in the $13.0 million
total above.
Sources of Future Capital
Prior to 2003, we funded our capital commitments from operating cash and
borrowings under bank facilities. In 2003, we issued common units to our general
partner for cash and sold assets to fund growth. Our plans for the future
include a combination of borrowings and the issuance of additional common units
to the public.
We are in discussions with Fleet National Bank regarding an expansion of
our existing credit facility from $65 million to $100 million. We would like to
reduce the amount of the facility committed to letters of credit and working
capital borrowings from $65 million to $50 million and have $50 million
available for acquisitions.
-24-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
We may consider raising capital through an equity offering of additional
common units if we make acquisitions using an expanded credit facility. Any such
proceeds could be used to reduce the outstanding balances under the credit
facility thereby freeing up debt capacity to use for additional accretive
acquisitions. An equity offering would probably not occur before the fourth
quarter of 2004.
Distributions
As a master limited partnership, the key consideration of our
Unitholders is the amount of our distribution, its reliability and the prospects
for distribution growth. Normally we distribute 100% of our 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 our cash receipts
less cash disbursements adjusted for net changes to reserves. The target minimum
quarterly distribution ("MQD") for each quarter is $0.20 per unit. Beginning
with the distribution for the first quarter of 2003, we paid a regular quarterly
distribution of $0.05 per unit ($0.4 million in total per quarter). For the
fourth quarter of 2003, we increased our quarterly distribution to $0.15 per
unit ($1.4 million in total), which was paid in February 2004. We have declared
a distribution of $0.15 per unit ($1.4 million in total) for the first quarter
of 2004 that will be paid May 14, 2004 to unitholders of record on April 30,
2004.
Under the Fleet Agreement, a provision requires that the Borrowing Base
exceed the usage under the Fleet Agreement by at least $10 million plus the
distribution measured once each month in order for us to make a distribution for
the quarter.
Our general partner is entitled to receive incentive distributions if
the amount we distribute with respect to any quarter exceeds levels specified in
our partnership agreement. Under the quarterly incentive distribution
provisions, the general partner generally is entitled to receive 13.3% of any
distributions in excess of $0.25 per unit, 23.5% of any distributions in excess
of $0.28 per unit and 49% of any distributions in excess of $0.33 per unit
without duplication. We have not paid any incentive distributions through
December 31, 2003. The likelihood and timing of the payment of any incentive
distributions will depend on our ability to make accretive acquisitions and
generate cash flows from of those acquisitions. We do not expect to make
incentive distributions during 2004.
We believe we will be able to sustain a regular quarterly distribution
at $0.15 per unit during 2004. We do not expect to be able to restore the
distribution to the targeted minimum quarterly distribution level of $0.20 per
unit until 2005. However, if we exceed our expectations for improving the
performance of the business, if our capital projects cost less than we currently
estimate, or if our access to capital allows us to make accretive acquisitions,
we may be able to restore the targeted minimum quarterly distribution sooner.
Available Cash before reserves for the quarter ended March 31, 2004, is
as follows (in thousands):
Net loss..................................................... $ (1,005)
Depreciation and amortization................................ 1,547
Non-cash charges............................................. 1,104
Maintenance capital expenditures............................. (155)
-----------
Available Cash before reserves............................... $ 1,491
===========
Available Cash (a non-GAAP liquidity measure) has been reconciled to
cash flow from operating activities (the GAAP measure) for the year ended March
31, 2004 below.
The non-GAAP financial measure of Available Cash is calculated in
accordance with generally accepted accounting principles (GAAP), with the
exception of maintenance capital expenditures as used in our calculation of
Available Cash. Maintenance capital expenditures are capital expenditures (as
defined by GAAP) to replace or enhance partially or fully depreciated assets in
order to sustain the existing operating capacity or efficiency of our assets and
extend their useful lives.
We believe that investors benefit from having access to the same
financial measures being utilized by management. Available Cash is a liquidity
measure used by our management to compare cash flows generated by the
Partnership to the cash distribution we pay to our limited partners and the
general partner. This is an important
-25-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
financial measure to our public unitholders since it is an indicator of our
ability to provide a cash return on their investment. Specifically, this
financial measure tells investors whether or not the Partnership is generating
cash flows at a level that can support a quarterly cash distribution to our
partners. Lastly, Available Cash (also referred to as distributable cash flow)
is a quantitative standard used throughout the investment community with respect
to publicly-traded partnerships.
Several adjustments to net income are required to calculate Available
Cash. These adjustments include: (1) the addition of non-cash expenses such as
depreciation and amortization expense; (2) miscellaneous non-cash adjustments
such as the addition of increases and subtraction of decreases in the accrual
for our stock appreciation rights plan in excess of any actual cash payments
under the plan; and (3) the subtraction of maintenance capital expenditures. See
"Distributions" above.
The reconciliation of Available Cash (a non-GAAP liquidity measure) to
cash flow from operating activities (the GAAP measure) for the three months
ended March 31, 2004, is as follows:
Three Months
Ended
March 31,
2004
--------------
(in thousands)
Cash flows used in operating activities.............................. $ (3,603)
Adjustments to reconcile operating cash flows to Available Cash:
Maintenance capital expenditures................................. (155)
Amortization of credit facility issuance fees.................... (93)
Net effect of changes in operating accounts not included in
calculation of Available Cash................................. 5,342
---------
Available Cash before reserves....................................... $ 1,491
=========
COMMITMENTS AND OFF-BALANCE SHEET ARRANGEMENTS
Contractual Obligation and Commercial Commitments
In addition to the Fleet Facility discussed above, we have contractual
obligations under operating leases as well as commitments to purchase crude oil.
The table below summarizes our obligations and commitments at March 31, 2004.
Payments Due by Period
-----------------------------------------------------------------------
Less than 1 - 3 4 - 5 After 5
Contractual Cash Obligations 1 Year Years Years Years Total
- ---------------------------- ------------ ------------ ----------- ------------ ------------
(in thousands)
Long-term Debt.............. $ - $ 9,900 $ - $ - $ 9,900
Operating Leases............ 2,910 2,206 1,069 802 6,987
Mississippi oil spill fine.. 3,000 - - - 3,000
Offshore pipeline removal... 696 - - - 696
Unconditional Purchase
Obligations............ 90,380 - - - 90,380
------------ ------------ ----------- ------------ ------------
Total Contractual Cash
Obligations............ $ 96,986 $ 12,106 $ 1,069 $ 802 $ 110,963
============ ============ =========== ============ ============
We expect to pay the estimated $3.0 million fine related to the
Mississippi oil spill that occurred in 1999 (see Note 11 to the consolidated
financial statements) during 2004. We expect to incur approximately $0.7 million
to remove an abandoned offshore pipeline during 2004.
-26-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
While the payment of the fine and pipeline removal costs will increase
our average outstanding debt during 2004, we believe we have sufficient capacity
under the Fleet Facility to meet these obligations.
Off-Balance sheet Arrangements
We have no off-balance sheet arrangements, special purpose entities, or
financing partnerships, other than as disclosed in this section, nor do we have
any debt or equity triggers based upon our unit or commodity prices.
NEW ACCOUNTING PRONOUNCEMENTS
For information on new accounting pronouncements see Note 2 to the
consolidated financial statements.
FORWARD LOOKING STATEMENTS
The statements in this Quarterly Report on Form 10-Q that are not
historical information may be "forward looking statements" within the meaning of
the various provisions of the Securities Act of 1933 and the Securities Exchange
Act of 1934. All statements, other than historical facts, included in this
document that address activities, events or developments that we expect or
anticipate will or may occur in the future, including things such as plans for
growth of the business, future capital expenditures, competitive strengths,
goals, references to future goals or intentions and other such references are
forward-looking statements. These statements include, but are not limited to,
statements identified by the words "anticipate," "believe," "estimate,"
"expect," "plan," or "intend" and similar expressions and statements regarding
our business strategy, plans and objectives of our management for future
operations. These statements are made by us based on our past experience and our
perception of historical trends, current conditions and expected future
developments as well as other considerations we believe are appropriate under
the circumstances. Whether actual results and developments in the future will
conform to our expectations is subject to numerous risks and uncertainties, many
of which are beyond our control. These risks and uncertainties include general
economic conditions, market and business conditions, opportunities that may be
presented and pursued by us or the lack of such opportunities, competitive
actions by other companies in our industries, changes in laws and regulations,
access to capital, and other factors. Therefore, all the forward-looking
statements made in this document are qualified in their entirety by these
cautionary statements, and no assurance can be made that our goals will be
achieved or that expectations regarding future developments will prove to be
correct. Except as required by applicable securities laws, we do not intend to
update these forward-looking statements and information.
-27-
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Price Risk Management and Financial Instruments
Our 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. We
utilize New York Mercantile Exchange ("NYMEX") commodity based futures contracts
and forward contracts to hedge our exposure to these market price fluctuations
as needed. At March 31, 2004, we had no outstanding contracts.
At March 31, 2004, we held 37,000 barrels of crude oil in inventory with a
carrying cost of $1.2 million. The market value of this inventory was $50,000
more than its cost.
ITEM 4. CONTROLS AND PROCEDURES
We maintain disclosure controls and procedures and internal controls
designed to ensure that information required to be disclosed in our filings
under the Securities Exchange Act of 1934 is recorded, processed, summarized and
reported within the time periods specified in the Securities and Exchange
Commission's rules and forms. Our chief executive officer and chief financial
officer have evaluated our disclosure controls and procedures as of the end of
the period covered by this Quarterly Report on Form 10-Q and have determined
that such disclosure controls and procedures are adequate and effective in all
material respects in providing to them on a timely basis material information
relating to us (including our consolidated subsidiaries) required to be
disclosed in this quarterly report.
There have been no significant changes in our internal controls over
financial reporting during the three months ended March 31, 2004, that have
materially affected, or are reasonably likely to materially affect, our internal
controls over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See Part I. Item 1. Note 11 to the Consolidated Financial Statements
entitled "Contingencies", which is incorporated herein by reference.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits.
Exhibit 31.1 Certification by Chief Executive Officer Pursuant
to Rule 13a-14(a) under the Securities Exchange Act of 1934.
Exhibit 31.2 Certification by Chief Financial Officer Pursuant
to Rule 13a-14(a) under the Securities Exchange Act of 1934.
Exhibit 32.1 Certification by Chief Executive Officer Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit 32.2 Certification by Chief Financial Officer Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
(b) Reports on Form 8-K.
A report on Form 8-K was filed on February 25, 2004, which
included a press release of the Partnership's earnings for the year ended
December 31, 2003.
-28-
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
GENESIS ENERGY, L.P.
(A Delaware Limited Partnership)
By: GENESIS ENERGY, INC., as
General Partner
Date: May 11, 2004 By: /s/ ROSS A. BENAVIDES
------------------------------------
Ross A. Benavides
Chief Financial Officer
-29-
EXHIBIT INDEX
Exhibits Description of Exhibit
- ------------ ---------------------------------------------------------------
Exhibit 31.1 Certification by Chief Executive Officer Pursuant
to Rule 13a-14(a) under the Securities Exchange Act of 1934.
Exhibit 31.2 Certification by Chief Financial Officer Pursuant
to Rule 13a-14(a) under the Securities Exchange Act of 1934.
Exhibit 32.1 Certification by Chief Executive Officer Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit 32.2 Certification by Chief Financial Officer Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.