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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
--------------------------------
FORM 10-Q
[X] QUARTERLY REPORT UNDER SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2003
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 in Rule 12b-2 of the Exchange Act).
Yes No |X|
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This report contains 28 pages
1
GENESIS ENERGY, L.P.
Form 10-Q
INDEX
PART I. FINANCIAL INFORMATION
Page
----
Item 1. Financial Statements
Consolidated Balance Sheets - June 30, 2003 and December 31, 2002.............................. 3
Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2003 and 2002 4
Consolidated Statements of Comprehensive Income for the Six Months Ended June 30, 2003......... 5
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2003 and 2002.......... 6
Consolidated Statement of Partners' Capital for the Six Months Ended June 30, 2003............. 7
Notes to Consolidated Financial Statements..................................................... 8
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.......... 15
Item 3. Quantitative and Qualitative Disclosures about Market Risk..................................... 27
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 .......................................................................................... 28
2
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
(Unaudited)
June 30, December 31,
2003 2002
---------- ----------
ASSETS
CURRENT ASSETS
Cash and cash equivalents...................................... $ 2,863 $ 1,071
Accounts receivable-trade...................................... 76,795 80,664
Inventories.................................................... 1,490 4,952
Other.......................................................... 4,269 5,410
---------- ----------
Total current assets........................................ 85,417 92,097
FIXED ASSETS, at cost............................................. 119,906 118,418
Less: Accumulated depreciation................................ (74,220) (73,958)
---------- ----------
Net fixed assets............................................ 45,686 44,460
OTHER ASSETS, net of amortization................................. 1,028 980
---------- ----------
TOTAL ASSETS...................................................... $ 132,131 $ 137,537
========== ==========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable -
Trade....................................................... $ 75,865 $ 82,640
Related party............................................... 4,163 4,746
Accrued liabilities............................................ 7,918 8,834
---------- ----------
Total current liabilities................................... 87,946 96,220
LONG-TERM DEBT.................................................... 6,000 5,500
COMMITMENTS AND CONTINGENCIES (Note 10)
MINORITY INTERESTS................................................ 515 515
PARTNERS' CAPITAL
Common unitholders, 8,625 units issued and outstanding......... 36,909 34,626
General partner................................................ 761 715
Accumulated other comprehensive income......................... - (39)
---------- ----------
Total partners' capital..................................... 37,670 35,302
---------- ----------
TOTAL LIABILITIES AND PARTNERS' CAPITAL........................... $ 132,131 $ 137,537
========== ==========
The accompanying notes are an integral part of these
consolidated financial statements.
3
GENESIS ENERGY, L.P.
STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
(Unaudited)
Three Months Ended June 30, Six Months Ended June 30,
2003 2002 2003 2002
------------ ----------- ------------ ------------
REVENUES:
Gathering and marketing revenues
Unrelated parties.............................. $ 214,532 $ 235,890 $ 470,496 $ 467,781
Related parties................................ - - - 3,036
Pipeline revenues................................. 5,417 4,879 11,335 9,191
------------ ----------- ------------ ------------
Total revenues.............................. 219,949 240,769 481,831 480,008
COST OF SALES:
Crude costs, unrelated parties.................... 192,628 223,892 425,738 450,709
Crude costs, related parties...................... 13,684 4,385 28,866 4,385
Field operating costs............................. 4,028 4,014 8,167 8,004
Pipeline operating costs.......................... 3,750 2,256 7,946 5,250
------------ ----------- ------------ ------------
Total cost of sales............................ 214,090 234,547 470,717 468,348
------------ ----------- ------------ ------------
GROSS MARGIN......................................... 5,859 6,222 11,114 11,660
EXPENSES:
General and administrative........................ 2,445 2,204 4,808 4,292
Depreciation and amortization..................... 1,369 1,475 2,884 2,898
Other ............................................ (3) - (47) -
------------ ----------- ------------ ------------
OPERATING INCOME..................................... 2,048 2,543 3,469 4,470
OTHER INCOME (EXPENSE):
Interest income................................... 7 10 15 15
Interest expense.................................. (165) (278) (715) (683)
Change in fair value of derivatives............... - (355) - (1,057)
Gain on asset disposals........................... - 186 - 675
------------ ----------- ------------ ------------
Income before minority interest...................... 1,890 2,106 2,769 3,420
Minority interest.................................... - - - -
------------ ----------- ------------ ------------
NET INCOME........................................... $ 1,890 $ 2,106 $ 2,769 $ 3,420
============ =========== ============ ============
NET INCOME PER COMMON UNIT - BASIC AND DILUTED....... $ 0.21 $ 0.24 $ .31 $ 0.39
============ =========== ============ ============
WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING.. 8,625 8,625 8,625 8,625
============ =========== ============ ============
The accompanying notes are an integral part of these
consolidated financial statements.
4
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
(Unaudited)
Three Months Ended June 30, Six Months Ended June 30,
2003 2002 2003 2002
------------ ----------- ------------ ------------
NET INCOME........................................... $ 1,890 $ 2,106 $ 2,769 $ 3,420
OTHER COMPREHENSIVE INCOME:
Change in fair value of derivatives used for
hedging purposes - - 39 -
------------ ----------- ------------ ------------
COMPREHENSIVE INCOME................................. $ 1,890 $ 2,106 $ 2,808 $ 3,420
============ =========== ============ ============
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)
Six Months Ended June 30,
2003 2002
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income...................................................................... $ 2,769 $ 3,420
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation................................................................. 2,678 2,474
Amortization of covenant not-to-compete...................................... 206 424
Amortization and write-off of credit facility issuance costs................. 841 320
Change in fair value of derivatives.......................................... 39 1,057
Minority interest's equity in earnings....................................... - -
Gain on asset disposals...................................................... (47) (675)
Other noncash charges........................................................ - 810
Changes in components of working capital -
Accounts receivable....................................................... 3,869 89,290
Inventories............................................................... 3,027 3,676
Other current assets...................................................... 1,141 5,453
Accounts payable.......................................................... (7,358) (93,251)
Accrued liabilities....................................................... (916) (1,412)
--------- ---------
Net cash provided by operating activities......................................... 6,249 11,586
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment............................................. (3,509) (1,212)
Change in other assets.......................................................... (2) 1
Proceeds from sales of assets................................................... 87 2,182
--------- ---------
Net cash (used in) provided by investing activities............................... (3,424) 971
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings (repayments) of debt................................................. 500 (12,400)
Credit facility issuance costs.................................................. (1,093) -
Distributions to common unitholders............................................. (431) -
Distributions to general partner................................................ (9) -
---------- ---------
Net cash used in financing activities............................................. (1,033) (12,400)
--------- ---------
Net increase in cash and cash equivalents......................................... 1,792 157
Cash and cash equivalents at beginning of period.................................. 1,071 5,777
--------- ---------
Cash and cash equivalents at end of period........................................ $ 2,863 $ 5,934
========= =========
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
-------------------------------------------------------
Accumulated
Other
Common General Comprehensive
Unitholders Partner Income Total
---------- --------- ------------ ------------
Partners' capital at December 31, 2002................. $ 34,626 $ 715 $ (39) $ 35,302
Net income for the six months ended June 30, 2003...... 2,714 55 - 2,769
Cash distributions to partners during the six months
ended June 30, 2003.................................. (431) (9) - (440)
Change in fair value of derivatives used for hedging
purposes............................................. - - 39 39
---------- --------- ------------ ------------
Partners' capital at June 30, 2003..................... $ 36,909 $ 761 $ - $ 37,670
========== ========= ============ ============
The accompanying notes are an integral part of these
consolidated financial statements.
7
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Formation and Offering
Genesis Energy, L.P. ("GELP" or the "Partnership") was formed in December
1996 as an initial public offering of 8.6 million Common Units, representing
limited partner interests in GELP. 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").
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. The general partner of these subsidiary partnerships is Genesis Energy,
Inc. The General Partner has no income or ownership interest in the subsidiary
partnerships. Genesis Crude Oil, L.P. and its subsidiary partnerships will be
referred to as "GCOLP".
2. Basis of Presentation
The accompanying consolidated financial statements and related notes
present the financial position as of June 30, 2003 and December 31, 2002 for
GELP, the results of operations for the three and six months ended June 30, 2003
and 2002, cash flows for the six months ended June 30, 2003 and 2002, and
changes in partners' capital for the six months ended June 30, 2003.
The financial statements included herein have been prepared by the
Partnership without audit pursuant to the rules and regulations of the
Securities and Exchange Commission ("SEC"). Accordingly, they reflect all
adjustments (which consist solely of normal recurring adjustments) which are, in
the opinion of management, necessary for a fair presentation of the financial
results for interim periods. Certain information and notes normally included in
financial statements prepared in accordance with generally accepted accounting
principles have been condensed or omitted pursuant to such rules and
regulations. However, the Partnership believes that the disclosures are adequate
to make the information presented not misleading. These financial statements
should be read in conjunction with the financial statements and notes thereto
included in the Partnership's Annual Report on Form 10-K for the year ended
December 31, 2002 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 and six months ended June 30, 2003 and 2002 was
8,625,000. 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.
Certain prior period amounts have been reclassified to conform with the
current year presentation. Such reclassifications had no effect on reported net
income, total assets, total liabilities and partners' equity.
3. New Accounting Pronouncements
GELP adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" on
January 1, 2003. This statement requires entities to record the fair value of a
liability for legal obligations associated with the retirement obligations of
tangible long-lived assets in the period in which the obligation is incurred and
can be reasonably estimated. When the liability is initially recorded, a
corresponding increase in the carrying amount of the related long-lived asset
would be recorded. Over time, accretion of the liability is recognized each
period, and the capitalized cost is depreciated over the useful life of the
related asset. Upon settlement of the liability, an entity either settles the
obligation for its recorded amount or incurs a gain or loss on settlement.
With respect to its pipelines, federal regulations will require GELP to
purge the crude oil from its pipelines when the pipelines are retired. The
Partnership's right of way agreements do not require it to remove pipe or
otherwise perform remediation upon taking the pipelines out of service. Many of
its truck unload stations are on leased sites that require that the Partnership
remove improvements upon expiration of the lease term. For its pipelines,
management of the Partnership is unable to reasonably estimate and record
liabilities for its obligations
8
that fall under the provisions of this statement because it cannot reasonably
estimate when such obligations would be settled. For the truck unload stations,
the site leases have provisions such that the lease continues until one of the
parties gives notice that it wishes to end the lease. At this time management
of the Partnership cannot reasonably estimate when such notice would be given
and when the obligations to remove its improvements would be settled. The
Partnership will record asset retirement obligations in the period in which it
determines the settlement dates.
On January 1, 2003, GELP adopted SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities," which addresses accounting for
restructuring and similar costs. This statement requires that the liability for
costs associated with an exit or disposal activity be recognized when the
liability is incurred rather than at the date of commitment to an exit plan.
This adoption of this statement had no material impact on the Partnership's
financial statements.
GELP implemented FASB Interpretation No. 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others" as of December 31, 2002. This interpretation of SFAS No.
5, 57 and 107, and rescission of FASB Interpretation No. 34 elaborates on the
disclosures to be made by a guarantor in its interim and annual financial
statements about its obligations under certain guarantees that it has issued. It
also clarifies that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the fair value of the obligation undertaken in
issuing the guarantee. The information required by this interpretation is
included in Note 10.
GELP adopted SFAS No. 148, "Accounting for Stock-Based
Compensation-Transition and Disclosure," as of January 1, 2003. This statement
provides alternative methods of transition from a voluntary change to the fair
value based method of accounting for stock-based employee compensation and
amends the disclosure requirements of SFAS No. 123 in both annual and interim
financial statements. As there are no outstanding grants of Partnership units
under any compensation plans of the Partnership, the adoption of this statement
had no effect on either the financial position, results of operations, cash
flows or disclosure requirements of the Partnership.
On April 30, 2003, the FASB issued SFAS No. 149, "Amendment of Statement
133 on Derivative Instruments and Hedging Activities." This statement amends and
clarifies accounting for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities under SFAS
No. 133. This statement is effective for contracts entered into or modified
after June 30, 2003, for hedging relationships designated after June 30, 2003,
and to certain preexisting contracts. The Partnership will adopt SFAS No. 149 on
a prospective basis at its effective date on July 1, 2003. Under Statement 133
and related amendments and interpretations, volumes with physical delivery that
were net scheduled for delivery purposes and where gross payments were made and
credit risk was assumed were designated for the normal purchase and sale
exemption and were exempt from derivative accounting treatment. SFAS No. 149
eliminates this exemption if net scheduling occurs. Therefore, a few of the
Partnership's contracts representing a small volume will be required to be
treated as derivatives in the future and marked to market each period.
In May 2003, The FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity". SFAS
No. 150 establishes standards for how an issuer classifies and measures certain
freestanding instruments with characteristics of both liabilities and equity.
SFAS No. 150 requires that an issuer classify a financial instrument that is
within its scope as a liability (or asset in some circumstances). The
Partnership is required to adopt SFAS No. 150 effective July 1, 2003. The
adoption of this statement is not expected to have a material effect on the
Partnership's financial position, results of operations or cash flows.
4. Business Segment and Customer Information
The Partnership manages all of its material operations around the gathering
and marketing of crude oil, and reports its operations, both internally and
externally, as a single business segment. Marathon Ashland Petroleum LLC,
ExxonMobil Corporation and Shell Oil Company accounted for 25%, 14% and 12%,
respectively, of revenues in the first six months of 2003. ExxonMobil
Corporation and Marathon Ashland Petroleum LLC accounted for 15% and 15%,
respectively, of revenues in the first six months of 2002.
9
5. Inventory Reduction
As a result of a change in the Partnership's operations to focus on its
gathering activities, and due to changes made in its gathering business as a
result of changes in its credit facilities, the Partnership determined that the
volume of crude oil needed to ensure efficient and uninterrupted operation of
its gathering business should be reduced. These crude oil volumes had been
carried at their weighted average cost and classified as fixed assets. In the
first six months of 2002, the Partnership realized additional gross margin of
approximately $337,000 as a result of the sale of these volumes.
6. Credit Resources and Liquidity
In March 2003, the Partnership entered into a $65 million three-year credit
facility with a group of banks with Fleet National Bank as agent ("Fleet
Agreement"). This agreement replaced an agreement with Citicorp North America,
Inc. ("Citicorp Agreement"). The Fleet Agreement has a sublimit for working
capital loans in the amount of $25 million, with the remainder of the facility
available for letters of credit.
The key terms of the Fleet Agreement are as follows:
o Letter of credit fees are based on the usage of the Fleet facility
in relation to the borrowing base and will range from 2.00% to
3.00%. During the first six months of the facility, the rate will be
2.50%.
o The interest rate on working capital borrowings is also based on the
usage of the Fleet facility in relation to the borrowing base. Loans
may be based on the prime rate or the LIBOR rate, at the
Partnership's option. The interest rate on prime rate loans can
range from the prime rate plus 1.00% to the prime rate plus 2.00%.
The interest rate for LIBOR-based loans can range from the LIBOR
rate plus 2.00% to the LIBOR rate plus 3.00%. During the first six
months of the facility, the Partnership may choose to borrow at
either the prime rate plus 1.50% or the LIBOR rate plus 2.50%. The
Partnership's outstanding balance at June 30, 2003 was borrowed at
the prime rate plus 1.50%.
o The Partnership pays a commitment fee on the unused portion of the
$65 million commitment. This commitment fee is also based on the
usage of the Fleet facility and will range from 0.375% to 0.50%.
During the first six months of the facility, the commitment fee will
be 0.50%.
o The amount that the Partnership may have outstanding in working
capital borrowings and letters of credit is subject to a Borrowing
Base calculation. The Borrowing Base is defined in the Fleet
Agreement generally to include cash balances, net accounts
receivable and inventory, less deductions for certain accounts
payable, and is calculated monthly.
o Collateral under the Fleet Agreement consists of the Partnership's
accounts receivable, inventory, cash accounts, margin accounts and
fixed assets.
o The Fleet Agreement contains covenants requiring a minimum current
ratio, a maximum leverage ratio, a minimum cash flow coverage ratio,
a maximum ratio of indebtedness to capitalization, a minimum EBITDA
(earnings before interest, taxes depreciation and amortization), and
limitations on distributions to Unitholders. The Partnership was in
compliance with these covenants at June 30, 2003.
Under the Fleet Agreement, distributions to Unitholders and the General
Partner can only be made if the Borrowing Base exceeds the usage by certain
amounts. See additional discussion below under "Distributions".
At June 30, 2003, the Partnership had $6.0 million outstanding under the
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, 2006. At June 30, 2003, the Partnership had
letters of credit outstanding under the Fleet Agreement totaling $26.4 million,
comprised of $13.5 million and $12.1 million for crude oil purchases related to
June 2003 and July 2003, respectively and $0.8 million related to other business
obligations.
10
Credit Availability
Any significant decrease in the Partnership's financial strength,
regardless of the reason for such decrease, may increase the number of
transactions requiring letters of credit, which could restrict its gathering and
marketing activities due to the limitations of the Fleet Agreement and Borrowing
Base. This situation could in turn adversely affect its ability to maintain or
increase the level of its purchasing and marketing activities or otherwise
adversely affect its profitability and liquidity.
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, 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. Currently, the
target minimum quarterly distribution ("MQD") for each quarter is $0.20 per
unit.
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 Agreement
by at least $10 million plus the distribution, measured once each month.
During 2002, the Partnership did not pay any regular distributions
although it met the Borrowing Base test in the last two quarters of that year.
During the first and second quarters of 2003, the Partnership met the test in
the Fleet Agreement. A distribution of $0.05 per unit ($0.4 million in total)
was paid in May 2003 for the first quarter of 2003. A distribution of $0.05 per
unit ($0.4 million in aggregate) payable on August 14, 2003 to Unitholders of
record on July 31, 2003 has been declared for the second quarter of 2003.
7. Transactions with Related Parties
Sales, purchases and other transactions with affiliated companies, except
for below-market guarantee fees paid in 2002 to Salomon Smith Barney Holdings
Inc. ("Salomon"), in the opinion of management, are conducted under terms no
more or less favorable than those conducted with unaffiliated parties. Salomon
was the owner of the General Partner until May 2002.
Sales and Purchases of Crude Oil
Denbury became a related party in May 2002. Purchases of crude oil from
Denbury for the six months ended June 30, 2003, were $28.9 million. Purchases
from Denbury during the six months ended June 30, 2002 while it was a related
party were $4.4 million and purchases during the period before it became an
affiliate were $10.9 million. Purchases from Denbury are secured by letters of
credit.
Salomon ceased to be a related party in May 2002. During the period in
2002 when Salomon was a related party, sales totaling $3.0 million were made to
Phibro Inc., a subsidiary of Salomon.
General and Administrative Services
The Partnership does not directly employ any persons to manage or
operate its business. These services 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 $7,913,000 and $8,970,000 for the six months ended June 30, 2003 and 2002,
respectively.
Directors' Fees
The Partnership paid $60,000 to Denbury in the six months ended June 30,
2003, for the services of four of Denbury's officers as directors of the General
Partner, the same rate at which the Partnership's independent directors were
paid.
11
Credit Agreement
In December 2001, Citicorp began providing the Partnership with a
working capital and letter of credit facility. Citicorp and Salomon are both
subsidiaries of Citicorp, Inc. From January 1, 2002, until May 14, 2002, when
Citicorp ceased to be a related party, the Partnership incurred letter of credit
fees, interest and commitment fees totaling $396,000 under the Credit Agreement.
In December 2001, the Partnership paid Citicorp $900,000 as a fee for providing
the facility. This facility fee was being amortized to earnings over the
two-year life of the Credit Agreement and was included in interest expense on
the consolidated statements of operations. When the facility was replaced in
March 2003, the unamortized balance of this fee totaling $371,000 was charged to
interest expense.
Guaranty Fees
From January 2002 to April 2002, Salomon provided guaranties under a
transition arrangement with Salomon, Citicorp and the Partnership. For the six
months ended June 30, 2002, the Partnership paid Salomon $61,000 for guarantee
fees. The guarantee fees are included as a component in cost of crude on the
consolidated statements of operations. These guarantee fees were less than the
cost of a letter of credit facility from a bank.
8. Supplemental Cash Flow Information
Cash received by the Partnership for interest was $15,000 for the first
half of both 2003 and 2002. Payments of interest were $170,000 and $338,000 for
the six months ended June 30, 2003 and 2002, respectively.
9. Derivatives
The Partnership's market risk in the purchase and sale of its 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 its exposure to such market
fluctuations, the Partnership enters into various financial contracts, including
futures, options and swaps. Normally, any contracts used to hedge market risk
are less than one year in duration.
The Partnership utilizes crude oil futures contracts and other financial
derivatives to reduce its exposure to unfavorable changes in crude oil prices.
Every derivative instrument (including certain derivative instruments embedded
in other contracts) is recorded in the balance sheet as either an asset or
liability measured at its fair value. Changes in the derivative's fair value are
recognized currently in earnings unless specific hedge accounting criteria are
met. 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.
The Partnership marks to fair value its 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, 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.
The Partnership regularly reviews its contracts to determine if the
contracts qualify for treatment as derivatives. At June 30, 2003, the
Partnership had no contracts outstanding that qualified for derivative treatment
under SFAS No. 133. At December 31, 2002, the Partnership determined that the
only contract qualifying as a derivative was a qualifying cash flow hedge. The
decrease of $39,000 in the fair value of this hedge was recorded in other
comprehensive income and as accumulated other comprehensive income in the
consolidated balance sheet. No hedge ineffectiveness was recognized during 2002.
The anticipated transaction (crude oil sales) occurred in January 2003, and all
related amounts held in other comprehensive income at December 31, 2002, were
reclassified to the consolidated statement of operations in the first quarter of
2003. The Partnership determined that its other derivative contracts qualified
for the normal purchase and sale exemption at June 30, 2003. The decrease in
fair value of the Partnership's net asset for derivatives not qualifying as
hedges in the first six months of 2002 was $1.1 million. This decrease in fair
value of $1.1 million is recorded as a loss in the consolidated statements of
operations under the caption "Change in fair value of derivatives".
12
10. Contingencies
Guarantees
The Partnership has guaranteed $5.2 million of residual value related to
the leases of tractors and trailers. Management of the Partnership believes the
likelihood the Partnership 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 $10.1 million at June 30, 2003, 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 Agreement related to
borrowings and letters of credit. Borrowings at June 30, 2003, were $6.0 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.
Unitholder Litigation
On June 7, 2000, Bruce E. Zoren, a holder of units of limited partner
interests in the partnership, filed a putative class action complaint in the
Delaware Court of Chancery, No. 18096-NC, seeking to enjoin a restructuring that
was approved by the unitholders and completed in December 2000. Zoren is also
seeking damages. Defendants named in the complaint include the Partnership,
Genesis Energy L.L.C., members of the board of directors of Genesis Energy,
L.L.C., and Salomon Smith Barney Holdings Inc. The plaintiff alleges numerous
breaches of fiduciary duty loyalty owed by the defendants to the purported class
in connection with making a proposal for restructuring. In November 2000, the
plaintiff amended its complaint. In response, the defendants removed the amended
complaint to federal court. On March 27, 2002, the federal court dismissed the
suit; however, the plaintiff filed a motion to alter or amend the judgment. On
May 15, 2002, the federal court denied the motion to alter or amend. The time
for an appeal to be taken expired without an appeal being filed. On June 11,
2002, the plaintiff refiled the original complaint in the Delaware Court of
Chancery, No. 19694-NC. On July 19, 2002, the defendants moved to dismiss the
complaint for failure to state a claim upon which relief can be granted. On July
28, 2003, the claim was dismissed with prejudice. While the plaintiff can appeal
this dismissal, management of the Partnership believes that this matter has now
been resolved.
Pennzoil Litigation
The Partnership was 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") seeks 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 claims the fire and explosion was caused, in part, by
Genesis selling to PQS crude oil that was contaminated with organic chlorides.
Management of the Partnership believes that the suit is without merit and
intends to vigorously defend itself in this matter. Management of the
Partnership believes that any potential liability will be covered by insurance.
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. Management of the Partnership believes that the demand against
Genesis is without merit and intends to vigorously defend itself in this matter.
A trial date in October 2003 has been set. Management of the Partnership
believes that any potential liability will substantially be covered by
insurance.
Other Matters
On December 20, 1999, the Partnership had a spill of crude oil from its
Mississippi System. Approximately 8,000 barrels of oil spilled from the pipeline
near Summerland, Mississippi, and entered a creek nearby. A portion
13
of the oil then flowed into the Leaf River. The oil spill is covered by
insurance and the financial impact to the Partnership for the cost of the
clean-up has not been material. 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.
The Partnership is subject to various environmental laws and
regulations. Policies and procedures are in place to monitor compliance.
The Partnership is subject to lawsuits in the normal course of business
and examination by tax and other regulatory authorities. Such matters presently
pending are not expected to have a material adverse effect on the financial
position, results of operations or cash flows of the Partnership.
11. Subsequent Event
On July 14, 2003, the Board of Directors of the General Partner declared a
cash distribution of $0.05 per Unit for the quarter ended June 30, 2003. The
distribution will be paid August 14, 2003, to the General Partner and all Common
Unitholders of record as of the close of business on July 31, 2003.
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 and Mississippi. The
following review of the results of operations and financial condition should be
read in conjunction with the Consolidated Financial Statements and Notes thereto
and with the Partnership's annual report on Form 10-K for the year ended
December 31, 2002.
Included in Management's Discussion and Analysis are the following
sections:
o 2003 Highlights
o Results of Operations
o Outlook for the Remainder of 2003 and Beyond
o Liquidity and Capital Resources
o Forward Looking Statements
2003 Highlights
In May 2003, we resumed distributions to partners in the Partnership by
making a distribution for the first quarter of 2003 in the amount of $0.05 per
unit for a total of $0.4 million. We have declared a distribution for the second
quarter of 2003, payable August 14, 2003 to unitholders of record on July 31,
2003, and the general partner in the amount of $0.05 per unit.
The most significant event in the first half of 2003 was replacement of the
credit facility with Citicorp North America, Inc. ("Citicorp") with a three-year
$65 million credit facility with a group of banks, with Fleet National Bank as
agent ("Fleet Agreement").
The Fleet Agreement replaced an $80 million credit facility that was to
expire in December 2003. Reduction of the size of the credit facility to a size
in line with our needs reduces the commitment fees we are required to pay.
Obtaining a facility for a three-year period provides a source of funding and
credit for a longer term and provides additional financial institutions that may
make access to debt capital easier as we grow. The Fleet Agreement has terms
that are summarized more fully below and in Note 6 to the Consolidated Financial
Statements.
As a result of the replacement of the Citicorp Agreement, the unamortized
portion of the fees paid in December 2001 to obtain the Citicorp Agreement were
charged to expense in the first quarter of 2003. The total of fees charged to
expense was $0.6 million, with $0.2 million included in general and
administrative expenses and the remainder classified as interest expense.
Results of Operations
Financial and volumetric information for this discussion of the results of
operations follows, in thousands, except volumes per day.
Three Months Ended June 30, Six Months Ended June 30,
2003 2002 2003 2002
------------ ----------- ------------ ------------
Gross margin (excluding depreciation)
Gathering and marketing revenues.......... $ 214,532 $ 235,890 $ 470,496 $ 470,817
Crude costs............................... 206,312 228,277 454,604 455,094
Field operating costs..................... 4,028 4,014 8,167 8,004
------------ ----------- ------------ ------------
Gathering and marketing gross margin...... $ 4,192 $ 3,599 $ 7,725 $ 7,719
============ =========== ============ ============
Pipeline revenues......................... $ 5,417 $ 4,879 $ 11,335 $ 9,191
Pipeline operating costs.................. 3,750 2,256 7,946 5,250
------------ ----------- ------------ ------------
Pipeline gross margin..................... $ 1,667 $ 2,623 $ 3,389 $ 3,941
============ =========== ============ ============
Barrels per day
Wellhead.................................. 58,815 65,497 60,125 66,476
Bulk and exchange......................... 21,834 38,338 22,193 52,647
Pipeline.................................. 71,472 75,576 71,432 75,493
15
Our profitability depends to a significant extent upon our ability to
maximize gross margin (excluding depreciation). Gross margins (excluding
depreciation) from gathering and marketing operations are a function of volumes
purchased and the difference between the price of crude oil at the point of
purchase and the price of crude oil at the point of sale, minus the associated
costs of aggregation and transportation. The absolute price levels for crude oil
do not necessarily bear a relationship to gross margin (excluding depreciation)
as absolute price levels normally impact revenues and cost of sales by
equivalent amounts. Because period-to-period variations in revenues and cost of
sales are not generally meaningful in analyzing the variation in gross margin
(excluding depreciation) 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 between the wellhead and the end user (usually a refinery) where
we can achieve positive gross margins (excluding depreciation). We generally
purchase crude oil at prevailing prices from producers at the wellhead under
short-term contracts and then transport the crude by truck or pipeline for sale
to or exchange with customers. We generally enter into exchange transactions
only when the cost of the exchange is less than the alternate cost we would
incur in transporting or storing the crude oil. In addition, we often exchange
one grade of crude oil for another to maximize 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 future delivery obligations, on the
other hand. It is our policy not to hold crude oil, futures contracts or other
derivative products for the purpose of speculating on crude oil price changes.
Pipeline revenues and gross margin (excluding depreciation) 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
our pipeline operations and are addressed in the following discussion of our
pipeline operations.
Six Months Ended June 30, 2003 Compared with Six Months Ended June 30, 2002
Gathering and marketing gross margin excluding depreciation, Gross
margin (excluding depreciation) from gathering and marketing operations was $7.7
million for the six months ended June 30, 2003 and 2002. Although gross margin
(excluding depreciation) was the same, the factors comprising gross margin
(excluding depreciation) changed.
Gross margin (excluding depreciation) increased in 2003 by $5.5 million
due to price variances - an increase in the average difference between the price
of crude oil at the point of purchase and the price of crude oil at the point of
sale.
Offsetting this increase were the following factors:
o a $4.8 million decrease due to a reduction of 31 percent in wellhead, bulk
and exchange purchase volumes between 2002 and 2003;
o a $0.3 million increase in gross margin in the 2002 period as a result of
the sale of crude oil that was no longer needed to ensure efficient and
uninterrupted operations; no such sale occurred in the 2003 period;
o a $0.2 million increase in field operating costs due to higher diesel fuel
costs to operate the Partnership's tractor/trailers, plus the costs of
repairs to truck unloading stations; and
16
o a $0.2 million increase in credit costs due to the use of letters of credit
in 2003 at a higher cost than the Salomon guaranties used from January to
April 2002.
The key drivers affecting our gathering and marketing gross margin
(excluding depreciation) include production volumes, volatility of P-Plus
margins, volatility of grade differentials, inventory management, and credit
costs.
A significant factor affecting our gathering and marketing gross
margins (excluding depreciation) is changes in the domestic production of crude
oil. Short-term and long-term price trends impact the amount of capital that
producers have available to maintain existing production and to invest in
developing crude reserves, which in turn impacts the amount of crude oil that is
available to be gathered and marketed by us and our competitors. The volatility
in prices over the last four years makes it very difficult to estimate
investments that producers will make in finding and developing crude oil
reserves, and therefore the volume available to purchase in future periods is
difficult to estimate. We expect to continue to be subject to volatility and
long-term declines in the availability of crude oil production for purchase.
During the first quarter of 2003 market prices for crude oil fluctuated
significantly due to world conditions. The conflict in Iraq led to expectations
of disruptions in crude oil supply which caused prices to increase dramatically.
The anticipation of a quick ending to the conflict and the lack of damage to the
oil fields of Iraq then caused prices to decline beginning in March. The effects
of strikes in Venezuela also impacted crude oil prices during the first quarter.
Prices have stabilized during the second quarter of 2003.
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, so that the changes in
prices do not necessarily have a direct impact on our profitability. 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 market factor in
the sales contracts 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 an individual transaction 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 oil
in the market. P-Plus is affected by numerous factors, such as future
expectations for changes in crude oil prices, so that at times 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.
Month Average P-Plus WTI Posting
----- -------------- -----------
December $3.9130 $26.2177
January $3.4690 $29.5161
February $4.3850 $32.3839
March $4.5470 $29.9919
April $5.1440 $25.0250
May $4.9670 $24.8790
June $3.7080 $27.2333
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 have to give 30-days notice to cancel and renegotiate
the contract. This notice requirement 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 margins from the sale of the crude oil can be volatile as a result of these
timing differences. Because of the increase in P-Plus in the last quarter of
2002 and first half of 2003, we have adjusted
17
bonuses on some of our purchase contracts. Should P-Plus decline to levels more
consistent with the first five months of 2002 when P-Plus ranged from $2.744 to
$3.1005, we could experience declines in margins until we are able to give the
required notice and renegotiate the purchase contract bonuses. Although P-Plus
did decline in June 2003, in July it returned to $4.6870, an amount more
consistent with levels in the first five months of 2003.
We also saw fluctuations in grade differentials during the first half
of 2003. 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 oil. We may buy oil under a contract where we considered
the typical grade differences in the market in setting 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, we can experience an increase
or decrease in our gross margin (excluding depreciation) 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 for December
2002 and each month of the first half of 2003 and the differential between West
Texas Intermediate grade crude oil and Light Louisiana Sweet grade crude oil for
the same periods. Grade differentials fluctuate based on the needs of refiners
and the real or perceived availability of the different crude types.
WTI/WTS WTI/LLS
Month Differential Differential
----- ------------ ------------
December $(2.243) $(0.008)
January $(1.569) $ 0.510
February $(1.404) $ 0.692
March $(4.109) $ 0.178
April $(4.797) $(0.065)
May $(3.270) $(0.257)
June $(1.499) $ 0.026
This volatility in grade differentials can affect the volatility of our
gathering and marketing gross margins (excluding depreciation).
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 typically 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 given month, they cannot predict exactly how much oil will be
produced. Our sales contracts typically state a specific volume to be sold,
which is determined prior to the month of production. Consequently, if the
actual production gathered by us is more or less than we expected and sold, we
will either increase or decrease our inventory volume. Under our risk management
policy and the terms of the Fleet Facility, we are not allowed to speculate on
the price of crude oil and are required to hedge our inventory if it exceeds
certain levels. As a result, the main objective of inventory management is
minimizing the variances in the volumes between purchases and sales and
eliminating the volume variances that inevitably result.
Pipeline gross margin excluding depreciation. Pipeline gross margin
(excluding depreciation) was $3.4 million for the six months ended June 30,
2003, as compared to $3.9 million for the first six months in 2002. The $0.5
million decrease in pipeline gross margin (excluding depreciation) was due to
the following factors:
o a $2.7 million increase in pipeline operating costs in the 2003 period.
This increase included costs totaling $0.2 million for personnel and
benefits costs related to additions of operations staff in Mississippi and
additions of staff engineers, and $0.1 million of costs associated with
work vehicles for the new staff. Costs associated with maintenance of
right-of-ways, including clearing of tree canopies, and costs for testing
under pipeline integrity regulations increased a combined $0.4 million.
Expenses for maintenance of pumps and meters increased $0.3 million.
Expenses for purging lines and removal of
18
related equipment increased $0.2 million. In 2003, we increased safety
training for pipeline operations personnel at a cost of $0.2 million.
During the third quarter of 2002, we undertook a project to add our
pipelines to the National Pipeline Mapping System with Global Positioning
Satellite (GPS) information on our pipeline maps as required by pipeline
safety regulations. Expenses incurred on this project in the first half of
2003 totaled $0.5 million. Insurance costs increased $0.2 million
due to the combination of insurance market conditions and our loss history.
Maintenance costs related to the pipe, including corrosion control,
increased $0.3 million. Other operating costs, including power costs,
increased a total of $0.3 million; and
o a $0.4 million decrease due to a decline in throughput of 5% between the
two periods.
Largely offsetting these decreases were increases from the following factors:
o a $2.0 million increase in revenue due to a 29 percent increase in the
average tariff on shipments; and
o a $0.6 million increase in revenues from sales of pipeline loss allowance
barrels primarily as a result of higher crude prices.
During the first half of 2003, volumes averaged 71,432 barrels per day,
with 48,236 barrels per day of that volume on the Texas System, 8,711 barrels
per day on the Mississippi System and 14,485 barrels per day on the Jay System.
The Texas System volume was negatively impacted during the first half of 2003
due to the cessation of deliveries to Marathon Ashland Petroleum LLC for almost
a month while we conducted a pressure test of our pipeline and Marathon
performed routine major maintenance.
The volumes on the Mississippi System of 8,711 barrels per day were less
than the fourth quarter 2002 average of 9,915 barrels per day. During the first
half of 2003, volumes from parties other than Denbury Resources Inc. declined.
We expect Mississippi System volumes for the remainder of 2003 to average
between 8,000 and 10,000 barrels per day. We had anticipated that a connecting
carrier would begin shipping on the Liberty-to-near-Baton Rouge segment of the
Mississippi System that has been out-of-service since February 1, 2002, again
during the latter half of 2003. It now appears unlikely that shipments of any
significance on this segment will begin before 2004 as sufficient volumes do not
appear to be available for shipment.
The volumes on the Jay System were 14,485 barrels per day for the first
half of 2003. During the fourth quarter of 2002, volumes on this system averaged
14,748 barrels. We were recently advised by a producer near our pipeline that
their development plans for their fields in the area have been postponed until
the fourth quarter of 2003, so it is unlikely that we will see any increase in
volume on this system until late in 2003.
The tariff increases we obtained in 2002 should continue to benefit
2003's pipeline revenues. Gross margin (excluding depreciation) from pipeline
operations was positively impacted by the recognition of revenue from volumes
related to the pipeline loss allowances and quality deductions from shipper
volumes in excess of volumetric measurement losses. During the first half of
2003, we recognized revenue of $2.0 million related to these deductions from
shippers net of losses, which totaled approximately 72,000 barrels. Additionally
we realized $0.4 million of revenue from the sale of volumes in inventory at
December 31, 2002 due to the rise in prices. If crude oil market prices continue
the recent trend to decline, revenues from these net deductions may be less.
Expenses and Other. General and administrative expenses increased $0.5
million between the 2003 and 2002 six month periods. This increase is primarily
attributable to the write-off of $0.2 million of unamortized legal and
consultant costs related to the Citicorp Agreement and an accrual of $0.3
million related to the reinstatement of the Partnership's bonus program for
employees. Under the Partnership's bonus program, bonuses were eliminated unless
distributions are being paid, which resulted in no accrual in the 2002 period.
The write-off of the unamortized costs was necessitated by the replacement of
the Citicorp Agreement with the Fleet Agreement. Changes in personnel reduced
salaries and benefits $0.4 million in the 2003 period; however, this decrease
was completely offset by increased legal, audit and other consultant fees,
directors' fees and insurance premiums for officers and directors liability
insurance. We expect to incur increased costs to comply with SEC regulations
mandated by the Sarbanes-Oxley Act in 2003.
19
Depreciation and amortization expense was flat between the six month
periods. Property additions during 2002 and the first half of 2003 increased
depreciation; however, a covenant not-to-compete was fully amortized at March
31, 2003, so amortization expense in 2003 was less than in the prior year
period.
Interest expense was flat between the two periods. In the 2003 period,
the Partnership wrote off $0.4 million of unamortized facility costs related to
the Citicorp Agreement, in addition to the write-off of legal and consultant
costs in general and administrative expenses noted above. However differences in
the facility size during the six-month periods offset this increase, due to
higher commitment fees in the 2002 period. The facility size was $130 million
from January 1, 2002, through early May 2002, when it was reduced to $80
million. In the 2003 six-month period, the facility was $80 million until March
14, 2003, when the Fleet Facility of $65 million replaced the Citicorp
Agreement. As a result of these differences, commitment fees were $0.2 million
greater in 2002. Additionally, amortization of facility fees and interest
expense, in total, were $0.2 million more in 2002.
As a result of a review of contracts existing at June 30, 2003, we
determined that our contracts do not meet the requirement for treatment as
derivative contracts under SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities" (as amended and interpreted). The contracts were
designated as normal purchases and sales under the provisions for that treatment
in SFAS No. 133.
The fair value of the Partnership's net asset for derivatives had decreased
by $1.1 million for the six months ended June 30, 2002.
The gain on asset disposals in the 2002 period included a gain of $0.5
million from the sale of the Partnership's memberships in the New York
Mercantile Exchange ("NYMEX").
Three Months Ended June 30, 2003 Compared with Three Months Ended June 30, 2002
Gathering and marketing gross margin excluding depreciation. Gross
margin (excluding depreciation) from gathering and marketing operations was $4.2
million for the quarter ended June 30, 2003, as compared to $3.6 million for the
quarter ended June 30, 2002. The $0.6 million increase in gross margin
(excluding depreciation) between the two periods was due to a $2.3 million
increase due to price variances, offset by a decline of $1.7 million due to a
22% decrease in wellhead, bulk and exchange purchase volumes in the 2003
three-month period. Credit costs and field costs were flat between the two
quarterly periods.
Pipeline gross margin excluding depreciation. Pipeline gross margin
(excluding depreciation) was $1.7 million for the quarter ended June 30, 2003,
as compared to $2.6 million for the second quarter of 2002. This $0.9 million
decrease in pipeline gross margin (excluding depreciation) was due to:
o a $1.5 million increase in pipeline operating costs; and
o a $0.2 million decrease in revenue due to a decline in throughput of 5
percent between the two periods.
Offsetting these factors were increases in pipeline gross margin (excluding
depreciation) due to:
o a $0.4 million increase in revenues from sales of pipeline loss allowance
barrels primarily as a result of higher crude prices; and
o a $0.4 million increase in revenues due to an increase of 10 percent in the
average tariff on shipments.
The increased pipeline operating costs included $0.2 million related to
the GPS project, $0.2 million related to integrity testing of the pipelines,
$0.2 million related to maintenance of the pipe, including corrosion control,
$0.2 million for costs for additional personnel, $0.1 million in higher
insurance costs and $0.6 million related to operating costs.
Expenses and Other. General and administrative expenses increased $0.2
million during the three months ended June 30, 2003 as compared to the same
period in 2002. The primary factors in this increase were small increases in
audit and consultant fees, directors' fees and increased premiums for officers
and directors liability
20
insurance. An accrual for bonuses under the partnership's bonus program in 2003
was offset by reductions in personnel and benefits costs.
Interest costs were $0.1 million less in the 2003 quarter due primarily
to the decreased commitment amount under credit facilities for which commitment
fees were owed.
Outlook for the Remainder of 2003 and Beyond
The information below is provided as an update to the "Outlook for 2003 and
Beyond" section of our Annual Report on Form 10-K for the year ended December
31, 2002.
Gathering and Marketing Operations
Both gathering and marketing volumes and margins are expected to be
lower during the second half of 2003 as compared to first six months of the
year. Operating results during the first half benefited from unusually high
P-Plus market prices. Volatility in P-Plus during the remainder of 2003 is
expected to reduce margins. Additionally, we expect gathering and marketing
gross margins (excluding depreciation) to decline relative to first half 2003
margins due to an expected decrease in the volume of crude oil to be gathered.
Additionally we reduced our inventory volumes during the first half of 2003
during a period when crude oil market prices were high.
Pipeline Operations
Volumes on our pipeline systems declined during the first half of 2003
as compared to the same period in 2002. We expect this volumetric loss to
continue during the remainder of 2003 due to the natural declines in the
production of oil wells near our pipelines. As discussed above, plans to
increase production by producers near our Jay System have been deferred until
late in 2003. In Mississippi we expect that increased production by Denbury to
only partially offset the loss of volumes from other producers in the area.
We expect our pipeline operating costs to be higher for the remainder of
2003 than in 2002 as we continue testing under pipeline integrity regulations,
performing testing of tanks and painting projects at pipeline stations. Pipeline
gross margin (excluding depreciation) should decline slightly in 2003 as
compared to 2002.
We are currently reviewing strategic opportunities for the Texas System.
While the tariff increases in 2002 have improved the outlook for this system, we
continue to examine opportunities for every part of the system to determine if
each segment should be sold, abandoned or invested in for further growth. As
part of this examination, we must consider the ability to increase tariffs,
which involves reviewing the alternatives available to shippers to move the oil
on other pipelines or by truck, production and drilling in the area around the
pipeline, the costs to test and improve our pipeline under integrity management
regulations, and other maintenance and capital expenditure expectations.
Our Mississippi pipeline is adjacent to several of Denbury's existing
and prospective oil fields. There may be mutual benefits to Denbury and to 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 carbon dioxide (CO2) based tertiary recovery
operations, Denbury would be expected 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.
Distribution Expectations
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. We made no regular distributions during 2002. On May
15, 2003 we paid a regular distribution of $0.05 per Unit for the first quarter
of 2003, and we have declared a distribution for the second quarter of $0.05 per
unit payable on August 14, 2003 to Common Unitholders of record on July 31,
2003, and the General Partner. 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
21
letters of credit) under the Fleet Agreement by at least $10 million plus the
distribution, measured once each month. Based on the need for larger than normal
capital expenditures to comply with the pipeline regulations during 2003 and
2004 and the need to strengthen our balance sheet to improve our access to
capital for growth, and considering this restrictive covenant in our new credit
facility, we do not expect to restore the regular distribution to the targeted
minimum quarterly distribution amount of $0.20 per quarter for the next year or
two. However, if we exceed our expectations for improving the performance of the
business, or 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 increase our regular quarterly distributions or restore the targeted minimum
quarterly distribution sooner.
Liquidity and Capital Resources
Cash Flows
During the first six months of 2003, we generated cash flows from
operating activities of $6.2 million as compared to $11.6 million for the same
period in 2002. In 2003, we reduced our inventories by $3.0 million while
changes in other components of working capital increased by $3.3 million. Net
income was $2.8 million and depreciation of assets and amortization of assets
and deferred charges was $3.7 million. In the first half of 2002, net income was
$3.4 million and depreciation and amortization and other non-cash items were
$4.4 million. The change in components of working capital provided cash of $3.8
million. Factors related to the timing of cash receipts and payments related to
the exit of the bulk and exchange business at the end of 2001 were the primary
reasons for the fluctuation in our current assets and liabilities in the 2002
period.
Cash flows used in investing activities in the first six months of 2003
were $3.4 million as compared to cash flows provided by investing activities of
$1.0 million in the 2002 period. In 2003 we expended $3.5 million for property
and equipment additions, including maintenance capital expenditures totaling
$2.9 million, as further described below. Offsetting these expenditures in 2003
were sales of surplus assets for $0.1 million.
In the first quarter of 2002, we sold our two seats on the NYMEX for
$1.7 million. These seats had become surplus assets when the business model was
changed to reduce bulk and exchange activities, reducing the level of NYMEX
activity that Genesis would need. In the 2002 period, we also received $0.5
million from the disposal of additional surplus assets, while expending $1.2
million for property additions.
Net cash expended for financing activities was $1.0 million in the
first six months of 2003. We expended $1.1 million for fees related to obtaining
the Fleet Agreement. We paid cash distributions totaling $0.4 million to the
limited partners and general partner. Partially offsetting these outflows was an
increase in the outstanding balance of our long-term debt of $0.5 million. In
the 2002 period, we repaid $12.4 million of debt under our credit facility. No
cash distributions were paid in the 2002 period.
Capital Expenditures
As discussed above, we expended a total of $3.5 million in the first
half of 2003 on capital expenditures, with $2.9 million of that amount for
maintenance capital expenditures on property and equipment, and $0.6 million to
acquire a condensate storage facility in Texas.
Maintenance capital expenditures are expenditures that are needed to
maintain the existing operating capacity of partially or fully depreciated
assets or extend their useful lives. We spent $0.5 million for installation of
pipeline satellite monitoring capabilities, $1.0 million for capital
expenditures on the Mississippi Pipeline System, $1.1 million on the Texas
Pipeline System, and $0.3 million for truck unloading additions and computer
hardware and software. The $1.0 million spent for the Mississippi Pipeline
System was for two purposes. First, we made 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. Second, we 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. We
continued to upgrade the West Columbia segment of our Texas pipeline.
For the remainder of 2003, we estimate our capital expenditures will be
approximately $2.4 million. We expect $1.6 million of the $2.4 million will be
spent for capital improvements to our pipeline systems as result of the
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IMP assessments. Of the remaining $0.6 million in capital expenditures,
substantially all of it will be spent on pipeline improvements such as equipment
upgrades for pipeline monitoring and corrosion control.
In 2004, currently we expect the level of capital expenditures to be
approximately $9.5 million, with $5.4 million for pipeline integrity
improvements and the balance of $4.1 million for tankage and other improvements.
At the end of 2004, we expect to have incurred most of the significant costs
related to the IMP regulatory compliance and expect to only spend $2.1 million
in 2005 for capital items, with $1.6 million related to IMP. Expenditures in
years after 2006 should remain in the $1.5 million to $2.5 million level as the
expected integrity improvements should not be as great on the remaining segments
of the pipelines.
Capital Resources
In March 2003, we replaced our credit agreement with Citicorp with a
$65 million three-year credit facility with a maturity date of March 31, 2006
with a group of banks with Fleet National Bank as agent ("Fleet Agreement"). The
Fleet Agreement has a sublimit for working capital loans in the amount of $25
million, with the remainder of the facility available for letters of credit.
The amount of our outstanding cumulative working capital borrowings and
letters of credit is subject to a Borrowing Base calculation. The Borrowing Base
(as defined in the Fleet Agreement) generally includes our cash balances, net
accounts receivable and inventory, less deductions for certain accounts payable,
and is calculated monthly. At June 30, 2003, the Borrowing Base was $57.2
million. Collateral under the Fleet Agreement consists of our accounts
receivable, inventory, cash accounts, margin accounts and property and
equipment. The Fleet Agreement contains covenants requiring a Current Ratio (as
defined in the Fleet Agreement), a Leverage Ratio (as defined in the Fleet
Agreement), a Cash Flow Coverage Ratio (as defined in the Fleet Agreement), a
Funded Indebtedness to Capitalization Ratio (as defined in the Fleet Agreement),
Minimum EBITDA, and limitations on distributions to Unitholders. We were in
compliance with all of these covenants at June 30, 2003.
Under the Fleet Agreement, distributions to Unitholders and the General
Partner can only be made if certain tests are met. See additional discussion
above under "Distributions".
At June 30, 2003, we had $6.0 million outstanding under the Fleet
Agreement. The average balance outstanding during the quarter ended June 30,
2003 was $0.6 million. 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 31, 2006. At June 30, 2003, we had
letters of credit outstanding under the Fleet Agreement totaling $26.4 million,
comprised of $13.5 million and $12.1 million for crude oil purchases related to
June 2003 and July 2003, respectively and $0.8 million related to other business
obligations.
Any significant decrease in our financial strength, regardless of the
reason for such decrease, may increase the number of transactions requiring
letters of credit, which could restrict our gathering and marketing activities
due to the limitations of the Fleet Agreement and Borrowing Base. This situation
could in turn adversely affect our ability to maintain or increase the level of
our purchasing and marketing activities or otherwise adversely affect our
profitability and liquidity.
Working Capital
Our balance sheet reflects negative working capital of $2.5 million.
The majority of this difference can be attributed to the accrual for the fines
and penalties that we expect to pay to state and federal regulators related to
the December 1999 Mississippi oil spill. That accrual is $3.0 million.
Additionally, we have received funds for purchases of crude oil that have not
yet been paid out to the owners of the oil, as those parties have not been
located or ownership issues exist. These funds, referred to as suspended
royalties, totaled $3.8 million at June 30, 2003, and have been applied to the
outstanding balance owed to Fleet. We have also received prepayments for future
oil sales totaling $2.5 million which have been applied to the balance owed to
Fleet. As we have a working capital sublimit under the Fleet Agreement of $25
million and have only borrowed $6.0 million at June 30, 2003, we have the
ability to borrow the funds to make the necessary payments. The accrual for the
fines and penalties, the suspended royalties and the prepayments by customers
are reflected as current liabilities. Should we be required to make these
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payments, we will borrow the funds under the Fleet facility, thereby increasing
the outstanding balance of long-term debt by $9.3 million and reducing current
liabilities and increasing working capital by $9.3 million.
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 $76.8 million aggregate receivables on
our consolidated balance sheet at June 30, 2003, approximately $75.9 million, or
98.8%, were less than 30 days past the invoice date.
Contractual Obligation and Commercial Commitments
In addition to the Fleet Agreement discussed above, we have contractual
obligations under operating leases as well as commitments to purchase crude oil.
The table below summarizes these obligations and commitments at June 30, 2003
(in thousands).
Payments Due by Period
-----------------------------------------------------------------------
Less than 1 - 3 4 - 5 After 5
Contractual Cash Obligations 1 Year Years Years Years Total
---------------------------- ------------ ------------ ----------- ------------ ------------
Fleet Agreement.......... $ - $ 6,000 $ - $ - $ 6,000
Operating Leases......... 4,416 5,697 1,815 2,075 13,732
Unconditional Purchase
Obligations (1)....... 122,637 - - - 122,637
------------ ------------ ----------- ------------ ------------
Total Contractual Cash
Obligations........... $ 126,783 $ 11,697 $ 1,815 $ 2,075 $ 142,369
============ ============ =========== ============ ============
(1) The unconditional purchase obligations included above are
contracts to purchase crude oil, generally at market-based
prices. For purposes of this table, market prices at June 30,
2003, were used to value the obligations, such that actual
obligations may differ from the amounts included above.
Distributions
The Partnership Agreement for Genesis Energy, L.P. provides that 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 Partnership Agreement indicates that the target
minimum quarterly distribution for each quarter is $0.20 per unit.
Available cash before reserves for the quarter and six months ended
June 30, 2003, is as follows (in thousands):
Three Six
Months Months
Ended Ended
June 30, June 30,
2003 2003
--------- ---------
AVAILABLE CASH BEFORE RESERVES:
Net income........................................................... $ 1,890 $ 2,769
Depreciation and amortization........................................ 1,369 2,884
Cash proceeds in excess of gains on asset sales.......................... - 40
Maintenance capital expenditures......................................... (1,296) (2,940)
--------- ---------
Available Cash before reserves....................................... $ 1,963 $ 2,753
========= =========
Available Cash is a non-GAAP measure. For further information on
available cash and a reconciliation of this measure to cash flows from operating
activities, see "Non-GAAP Financial Measure" below.
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On May 15, 2003, we paid a distribution of $0.05 per unit for the first
quarter to Common Unitholders and the General Partner of record at the close of
business on April 30, 2003. On July 14, 2003, we declared a distribution for the
second quarter in the amount of $0.05 per unit ($0.4 million in total) payable
on August 14, 2003, to Common Unitholders of record at the close of business on
July 31, 2003, and the General Partner. We expect to continue regular quarterly
distributions during 2003 of at least $0.05 per unit. Any decision to restore
the distribution to the targeted minimum quarterly distribution will take into
account our ability to sustain the distribution on an ongoing basis with cash
generated by our existing asset base, capital requirements needed to maintain
and optimize the performance of our asset base, and our ability to finance our
existing capital requirements and accretive acquisitions.
Non-GAAP Financial Measure
The non-GAAP financial measure of Available Cash is presented in this Form
10-Q. The amounts used in calculating this measure are computed 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 defined as capital expenditures (as defined
by GAAP) which do not increase the capacity of an asset or generate additional
revenues or cash flow from operations.
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 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 the 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 decreases or the subtraction of increases in the value
of financial instruments; 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 for the quarter and six months ended June
30, 2003, is as follows (in thousands):
Three Six
Months Months
Ended Ended
June 30, June 30,
2003 2003
--------- ---------
Cash flows from operating activities................................. $ 193 $ 6,249
Adjustments to reconcile operating cash flows to Available Cash:
Maintenance capital expenditures................................. (1,296) (2,940)
Proceeds from asset sales........................................ 3 87
Change in fair value of derivatives.............................. - (39)
Amortization of credit facility issuance fees.................... (91) (841)
Net effect of changes in operating accounts not included in
calculation of available cash.................................. 3,154 237
--------- ---------
Available Cash before reserves....................................... $ 1,963 $ 2,753
========= =========
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Insurance
We maintain insurance of various types that we consider adequate to
cover our operations and properties. The insurance policies are subject to
deductibles that we consider reasonable. The policies do not cover every
potential risk associated with operating our assets, including the potential for
a loss of significant revenues. Consistent with the coverage available in the
industry, our policies provide limited pollution coverage, with broader coverage
for sudden and accidental pollution events. Additionally, as a result of the
events of September 11, the cost of insurance available to the industry has
risen significantly, and insurers have excluded or reduced coverage for losses
due to acts of terrorism and sabotage.
Since September 11, 2001, warnings have been issued by various agencies
of the United States Government to advise owners and operators of energy assets
that those assets may be a future target of terrorist organizations. Any future
terrorist attacks on our assets, or assets of our customers or competitors could
have a material adverse affect on our business.
We believe that we are adequately insured for public liability and
property damage to others as a result of our operations. However, no assurances
can be given that an event not fully insured or indemnified against will not
materially and adversely affect our operations and financial condition.
Additionally, no assurance can be given that we will be able to maintain
insurance in the future at rates that we consider reasonable.
Critical Accounting Policies and Recent Accounting Pronouncements
For a discussion of our critical accounting policies, which are related
to depreciation, amortization and impairment, revenue and expense accruals and
liability and contingency accruals, and which remain unchanged, see our annual
report on Form 10-K for the year ended December 31, 2002.
We continuously monitor and revise our accounting policies as relevant
accounting literature changes. At this time there are several new accounting
pronouncements that have been recently issued which will or may impact our
accounting or disclosure, as they become effective. For further discussion of
new accounting rules, see Item 1. Consolidated Financial Statements-Note 3
Recent Accounting Pronouncements.
Forward Looking Statements
The statements in this report on Form 10-Q that are not historical
information may be forward looking statements within the meaning of Section 27a
of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
1934. Although we believe that its expectations regarding future events are
based on reasonable assumptions, no assurance can be made that our goals will be
achieved or that expectations regarding future developments will prove to be
correct. Important factors that could cause actual results to differ materially
from the expectations reflected in the forward looking statements herein
include, but are not limited to, the following:
o changes in regulations;
o our success in obtaining additional wellhead barrels;
o changes in crude oil production volumes (both world-wide and in
areas in which we have operations);
o developments relating to possible acquisitions, dispositions or
business combination opportunities;
o volatility of crude oil prices, P-Plus and grade differentials;
o the success of the risk management activities;
o credit requirements by our counterparties;
o the ability to obtain liability and property insurance at a
reasonable cost;
o acts of sabotage, terrorism or other similar acts causing damage
greater than our insurance coverage limits;
o our ability in the future to generate sufficient amounts of
Available Cash to permit the payment to unitholders of a
quarterly distribution;
o any additional requirements for testing or changes in the
Mississippi pipeline system as a result of the oil spill that
occurred there in December 1999;
26
o any fines and penalties federal and state regulatory agencies may
impose in connection with the oil spill that would not be
reimbursed by insurance;
o the costs of testing under pipeline integrity management
programs and any rehabilitation required as a result of that
testing;
o estimated timing and amount of future capital expenditures;
o our success in increasing tariff rates on our common carrier
pipelines;
o results of current or threatened litigation; and
o conditions of capital markets and equity markets during the
periods covered by the forward looking statements.
All subsequent written or oral forward looking statements attributable
to us, or persons acting our behalf, are expressly qualified in their entirety
by the foregoing cautionary statements.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
Price Risk Management and Financial Instruments
The Partnership's primary price risk relates to the effect of crude oil
price fluctuations on its inventories and the fluctuations each month in grade
and location differentials and their effects on future contractual commitments.
Historically, the Partnership has utilized New York Mercantile Exchange
("NYMEX") commodity based futures contracts, forward contracts, swap agreements
and option contracts to hedge its exposure to market price fluctuations;
however, at June 30, 2003, no contracts were outstanding. Information about
inventory at June 30, 2003, is contained in the table set forth below.
Crude Oil Inventory
Volume in barrels................................. 49,000
Carrying value ................................... $ 1,382,000
Fair value........................................ $ 1,452,000
Fair values were determined by using the notional amount in barrels
multiplied by published market closing prices for the applicable crude oil type
at June 30, 2003.
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Item 4. Controls and Procedures
The Partnership has evaluated the effectiveness of its disclosure
controls and procedures as of the end of the period covered by this report
pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. Such
evaluation was conducted under the supervision and with the participation of the
Partnership's Chief Executive Officer ("CEO") and its Chief Financial Officer
("CFO"). Based upon such evaluation, the Partnership's CEO and CFO have
concluded that the Partnership's disclosure controls and procedures are
effective in ensuring that information required to be disclosed is recorded,
processed, summarized and reported in a timely manner. There has been no change
in the Partnership's internal control over financial reporting that occurred
during the last fiscal quarter that has materially affected, or is reasonably
likely to affect the Partnership's internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
See Part I. Item 1. Note 10 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-15(b) under the Securities Exchange Act of 1934
Exhibit 31.2 Certification by Chief Executive Officer Pursuant
to Rule 13a-15(b) 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 May 7, 2003 containing the
Partnership's earnings press release for the first quarter of 2003.
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: August 12, 2003 By: /s/ ROSS A. BENAVIDES
----------------------------
Ross A. Benavides
Chief Financial Officer
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