Back to GetFilings.com
================================================================================
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
--------------------------------
FORM 10-Q
[X] QUARTERLY REPORT UNDER SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 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|
================================================================================
This report contains 30 pages
1
GENESIS ENERGY, L.P.
Form 10-Q
INDEX
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements Page
----
Consolidated Balance Sheets - September 30, 2003
and December 31, 2002............................................. 3
Consolidated Statements of Operations for the Three
and Nine Months Ended September 30, 2003 and 2002................. 4
Consolidated Statements of Comprehensive Income (Loss) for the
Three and Nine Months Ended September 30, 2003 and 2002........... 5
Consolidated Statements of Cash Flows for the Nine Months
Ended September 30, 2003 and 2002................................. 6
Consolidated Statement of Partners' Capital for the Nine
Months Ended September 30, 2003................................... 7
Notes to Consolidated Financial Statements........................... 8
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations..................... 16
Item 3. Quantitative and Qualitative Disclosures about Market Risk.. 29
Item 4. Controls and Procedures..................................... 30
PART II. OTHER INFORMATION
Item 1. Legal Proceedings........................................... 30
Item 6. Exhibits and Reports on Form 8-K............................ 30
SIGNATURES........................................................... 30
2
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
(Unaudited)
September 30, December 31,
2003 2002
-------- ----------
ASSETS
CURRENT ASSETS
Cash and cash equivalents...................................... $ 3,933 $ 1,071
Accounts receivable-trade...................................... 74,582 80,664
Inventories.................................................... 575 4,952
Other.......................................................... 5,344 5,410
---------- ----------
Total current assets........................................ 84,434 92,097
FIXED ASSETS, at cost............................................. 119,778 118,418
Less: Accumulated depreciation................................ (74,831) (73,958)
---------- ----------
Net fixed assets............................................ 44,947 44,460
OTHER ASSETS, net of amortization................................. 1,064 980
---------- ----------
TOTAL ASSETS...................................................... $ 130,445 $ 137,537
========== ==========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable -
Trade....................................................... $ 75,135 $ 82,640
Related party............................................... 4,251 4,746
Accrued liabilities............................................ 8,527 8,834
---------- ----------
Total current liabilities................................... 87,913 96,220
LONG-TERM DEBT.................................................... 6,000 5,500
COMMITMENTS AND CONTINGENCIES (Note 11)
MINORITY INTERESTS................................................ 515 515
PARTNERS' CAPITAL
Common unitholders, 8,625 units issued and outstanding......... 35,289 34,626
General partner................................................ 728 715
Accumulated other comprehensive income......................... - (39)
---------- ----------
Total partners' capital..................................... 36,017 35,302
---------- ----------
TOTAL LIABILITIES AND PARTNERS' CAPITAL........................... $ 130,445 $ 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 Nine Months Ended
September 30, September 30,
2003 2002 2003 2002
------------ ----------- ------------ ------------
REVENUES:
Gathering and marketing revenues
Unrelated parties.............................. $ 233,670 $ 209,916 $ 704,166 $ 677,697
Related parties................................ - - - 3,036
Pipeline revenues................................. 5,361 6,434 16,696 15,625
------------ ----------- ------------ ------------
Total revenues.............................. 239,031 216,350 720,862 696,358
COST OF SALES:
Crude costs, unrelated parties.................... 214,926 193,469 640,664 644,178
Crude costs, related parties...................... 12,738 9,181 41,604 13,566
Field operating costs............................. 4,404 4,021 12,571 12,025
Pipeline operating costs.......................... 4,809 4,911 12,755 10,161
------------ ----------- ------------ ------------
Total cost of sales............................ 236,877 211,582 707,594 679,930
------------ ----------- ------------ ------------
GROSS MARGIN......................................... 2,154 4,768 13,268 16,428
EXPENSES:
General and administrative........................ 1,994 2,060 6,802 6,352
Depreciation and amortization..................... 1,360 1,412 4,244 4,310
Other ............................................ (143) - (190) -
------------- ----------- ------------- ------------
OPERATING INCOME (LOSS).............................. (1,057) 1,296 2,412 5,766
OTHER INCOME (EXPENSE):
Interest income................................... 6 30 21 45
Interest expense.................................. (162) (209) (877) (892)
Change in fair value of derivatives............... - (1,037) - (2,094)
Gain on asset disposals........................... - 23 - 698
------------ ----------- ------------ ------------
Income (loss) before minority interest............... (1,213) 103 1,556 3,523
Minority interest.................................... - - - -
------------ ----------- ------------ ------------
NET INCOME (LOSS).................................... $ (1,213) $ 103 $ 1,556 $ 3,523
============ =========== ============ ============
NET INCOME (LOSS) PER COMMON UNIT-
BASIC AND DILUTED................................... $ (0.14) $ 0.01 $ 0.18 $ 0.40
============ =========== ============ ============
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 (LOSS)
(In thousands)
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
2003 2002 2003 2002
------------ ----------- ------------ ------------
NET INCOME (LOSS).................................... $ (1,213) $ 103 $ 1,556 $ 3,523
OTHER COMPREHENSIVE INCOME:
Change in fair value of derivatives used
for hedging purposes.......................... - - 39 -
------------ ----------- ------------ ------------
COMPREHENSIVE INCOME (LOSS).......................... $ (1,213) $ 103 $ 1,595 $ 3,523
============ =========== =========== ============
The accompanying notes are an integral part of these
consolidated financial statements.
5
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
Nine Months Ended
September 30,
2003 2002
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income...................................................................... $ 1,556 $ 3,523
Adjustments to reconcile net income to net cash provided by
operating activities Depreciation............................................ 4,038 3,674
Amortization of covenant not-to-compete...................................... 206 636
Amortization and write-off of credit facility issuance costs................. 903 551
Change in fair value of derivatives.......................................... 39 2,094
Minority interest's equity in earnings....................................... - -
Gain on sales of fixed assets................................................ (190) (698)
Other noncash charges........................................................ - 1,500
Changes in components of working capital -
Accounts receivable....................................................... 6,082 89,683
Inventories............................................................... 4,129 1,967
Other current assets...................................................... 66 5,631
Accounts payable.......................................................... (8,187) (89,119)
Accrued liabilities....................................................... (307) (5,832)
--------- ---------
Net cash provided by operating activities......................................... 8,335 13,610
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment............................................. (4,136) (2,753)
Change in other assets.......................................................... (100) 1
Proceeds from sales of assets................................................... 236 2,204
--------- ---------
Net cash used in investing activities............................................. (4,000) (548)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings (repayments) of debt................................................. 500 (13,900)
Credit facility issuance costs.................................................. (1,093) -
Distributions to common unitholders............................................. (862) -
Distributions to general partner................................................ (18) -
--------- ---------
Net cash used in financing activities............................................. (1,473) (13,900)
--------- ---------
Net increase in cash and cash equivalents......................................... 2,862 (838)
Cash and cash equivalents at beginning of period.................................. 1,071 5,777
--------- ---------
Cash and cash equivalents at end of period........................................ $ 3,933 $ 4,939
========= =========
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 nine months ended September 30,
2003 .............................................. 1,525 31 - 1,556
Cash distributions to partners during the nine months
ended September 30, 2003............................. (862) (18) - (880)
Change in fair value of derivatives used for hedging
purposes............................................. - - 39 39
---------- --------- ------------ ------------
Partners' capital at September 30, 2003................ $ 35,289 $ 728 $ - $ 36,017
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 September 30, 2003 and December 31, 2002
for GELP, the results of operations for the three and nine months ended
September 30, 2003 and 2002, cash flows for the nine months ended September 30,
2003 and 2002, and changes in partners' capital for the nine months ended
September 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 nine months ended September 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. See Note 7.
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. During the third quarter of 2003, the Partnership recorded
termination benefits related to the sale of its Texas Gulf Coast operations in
the amount of $0.3 million. See Note 12 for information regarding this sale.
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
8
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 11.
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 adopted SFAS No. 149 on
July 1, 2003. The adoption of this statement had no effect on the Partnership's
financial position, results of operations or cash flows.
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 adopted SFAS No. 150 effective July 1, 2003. The adoption of this
statement had no 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 24%, 14% and 11%,
respectively, of revenues in the first nine months of 2003. ExxonMobil
Corporation and Marathon Ashland Petroleum LLC accounted for 14% and 17%,
respectively, of revenues in the first nine months of 2002.
5. Inventory Reduction
As a result of a change in the Partnership's operations in 2001 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 nine months of 2002, the Partnership realized additional gross margin of
approximately $889,000 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 was
2.50%.
9
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 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 was
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 September 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 September 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 September 30, 2003, the
Partnership had letters of credit outstanding under the Fleet Agreement totaling
$19.3 million, comprised of $11.4 million and $7.1 million for crude oil
purchases related to September 2003 and October 2003, respectively and $0.8
million related to other business obligations.
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, as defined,
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.
10
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 three quarters of 2003, the Partnership met the test in the
Fleet Agreement. A distribution of $0.05 per unit ($0.4 million in total each
quarter) was paid in each of May 2003 and August 2003, covering the first and
second quarters of 2003. A distribution of $0.05 per unit ($0.4 million in
aggregate) payable on November 14, 2003 to Unitholders of record on October 31,
2003 has been declared for the third quarter of 2003.
7. Asset Retirement Obligations
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 generally 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 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.
In the third quarter of 2003, the Partnership recorded a liability in
the amount of $0.7 million representing the anticipated cost to remove a
pipeline from offshore waters of the State of Louisiana. The costs are expected
to be incurred before June 30, 2004.
8. 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 nine months ended September 30, 2003, were $41.6 million.
Purchases from Denbury during the nine months ended September 30, 2002 while it
was a related party (May to September) were $13.6 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 $11,929,000 and $12,854,000 for the nine months ended September 30, 2003
and 2002, respectively.
11
Directors' Fees
The Partnership paid $90,000 to Denbury in the nine months ended
September 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.
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 nine
months ended September 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.
9. Supplemental Cash Flow Information
Cash received by the Partnership for interest was $21,000 and $46,000 for
the nine months ended September 30, 2003 and 2002, respectively. Payments of
interest were $238,000 and $453,000 for the nine months ended September 30, 2003
and 2002, respectively.
10. 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 may enter into various financial contracts,
including futures, options and swaps. Normally, any contracts used to hedge
market risk are less than one year in duration. During 2003, the Partnership has
not used hedging instruments.
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 transactions 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 September 30, 2003, the
Partnership had no contracts outstanding that qualified for derivative treatment
under SFAS No. 133.
12
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 derivative contracts qualified for the
normal purchase and sale exemption at September 30, 2003. The decrease in fair
value of the Partnership's net asset for derivatives not qualifying as hedges in
the first nine months of 2002 was $2.1 million. This decrease in fair value of
$2.1 million is recorded as a loss in the consolidated statements of operations
under the caption "Change in fair value of derivatives".
11. 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 $11.2 million at September 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 September 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. On July 28,
2003, the claim was dismissed with prejudice. The plaintiff did not appeal this
dismissal, therefore 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.. 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.
12. Subsequent Events
Sale of Texas Gulf Coast Operations
On October 14, 2003, subsidiaries of GELP entered into a Pipeline Sale
and Purchase Agreement ("PSA") with TEPPCO Crude Pipeline, L.P. ("TEPPCO"),
pursuant to which TEPPCO agreed to purchase parts of GELP's Texas crude oil
pipeline system and associated gathering and marketing operations (the "Texas
Gulf Coast Operations"). The parts of the Texas crude oil pipeline system sold
by GELP include the segments of pipeline from Hearne to Bryan, Texas, Conroe to
Satsuma in northwest Houston, Texas, and Hillje and Withers to West Columbia,
Texas. The gathering and marketing operations in a 40-county area surrounding
these pipeline segments were also sold, and TEPPCO assumed the responsibilities
under GELP's crude oil purchase and sale contracts in that area. The transaction
was completed on October 31, 2003 (the "Closing Date"). TEPPCO paid GELP $21.6
million for the Texas Gulf Coast Operations. Additionally TEPPCO will purchase
the crude oil inventory of GELP in the 40-county area during November 2003 at a
contractually-agreed price. The Texas Gulf Coast Operations will be reflected as
discontinued operations in the consolidated statement of operations beginning in
the fourth quarter of 2003.
TEPPCO assumed responsibility for unpaid royalties related to the crude
oil purchase and sale contracts it assumed and GELP transferred $0.6 million to
TEPPCO for those liabilities.
On the Closing Date, GELP entered into various agreements with TEPPCO
pursuant to the PSA, including (a) a transitional services agreement whereby
GELP will provide to Teppco the use of certain assets TEPPCO did not acquire and
pipeline monitoring services for a minimum period of six months, and (b) a joint
tariff agreement whereby TEPPCO will invoice and collect and share with GELP the
tariffs for transportation on the pipeline being sold and the segments of
pipeline being retained by GELP for a one-year period. Additionally the PSA
contains provisions prohibiting competition by GELP in the 40-county area for a
five year period.
GELP retained responsibility for environmental matters related to the
Texas Gulf Coast Operations for the period prior to the Closing Date, subject to
certain conditions. TEPPCO will pay the first $25,000 for each environmental
claim up to an aggregate total of $100,000. GELP would be responsible for any
environmental claims in excess of these amounts up to an aggregate total of $2
million. TEPPCO has purchased an environmental insurance policy for amounts in
excess of GELP's $2 million responsibility, and GELP paid for one-half of the
policy premium. GELP's responsibility to indemnify TEPPCO will cease ten years
from the Closing Date.
In the third quarter of 2003, the Partnership recorded $0.3 million in
termination benefits related to this sale. These benefits include retention
bonuses and severance pay for employees affected by the sale and are being
accrued during the period that the employees are required to provide services in
order to receive the benefits. Approximately $0.2 million of this amount in
included in Field Operating Costs, and $0.1 million is included in Pipeline
Operating Costs in the Statement of Operations.
14
Acquisition of CO2 Sales Contracts
On October 15, 2003, the Partnership signed a letter of intent to acquire
an interest in 167.5 Bcf of CO2 under a volumetric production payment, plus
certain marketing rights, from Denbury Resources, Inc. ("Denbury") for $24.0
million, enabling it to commence a wholesale CO2 marketing business. As a result
of this transaction, the Partnership will sell CO2 to industrial customers and
pay Denbury a fee to transport the CO2 to the customers in a pipeline that
Denbury owns. In a separate transaction, Genesis Energy, Inc., the General
Partner of the Partnership and a wholly-owned subsidiary of Denbury, purchased
688,811 GELP Common Units for $4.9 million. These transactions are expected to
close in November 2003.
Distribution
On October 14, 2003, the Board of Directors of the General Partner declared
a cash distribution of $0.05 per Unit for the quarter ended September 30, 2003.
The distribution will be paid November 14, 2003, to the General Partner and all
Common Unitholders of record as of the close of business on October 31, 2003.
15
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
-1-
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. A distribution of $0.05 per unit was also paid
in August 2003 for the second quarter of 2003 and we have declared a
distribution for the third quarter of 2003, payable November 14, 2003 to
unitholders of record on October 31, 2003, and the general partner in the amount
of $0.05 per unit.
During the first nine months of 2003, we replaced 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.
On October 31, 2003, we sold parts of our Texas crude oil pipeline system
and associated gathering and marketing operations (the "Texas Gulf Coast
Operations") to TEPPCO Crude Pipeline, L.P. ("TEPPCO"). The parts of the Texas
crude oil pipeline system sold include the segments of pipeline from Hearne to
Bryan, Texas, Conroe to Satsuma in northwest Houston, Texas, and Hillje and
Withers to West Columbia, Texas. The gathering and marketing operations in a
40-county area surrounding these pipeline segments were also sold, and TEPPCO
assumed the responsibilities under our crude oil purchase and sale contracts in
that area. TEPPCO paid us $21.6 million for the Texas Gulf Coast Operations. See
Note 12 of Notes to Consolidated Financial Statements for additional information
on this sale. Additionally see the Form 8-K filed dated October 31, 2003 for the
pro forma effects of this sale.
On October 15, 2003, we signed a letter of intent to acquire an interest in
167.5 Bcf of CO2 under a volumetric production payment, plus certain marketing
rights, from Denbury Resources, Inc. ("Denbury") for $24.0 million, enabling us
to commence a wholesale CO2 marketing business. As a result of this transaction,
we will sell CO2 to industrial customers and pay Denbury a fee to transport the
CO2 to the customers in a pipeline that Denbury owns. In a separate transaction,
Genesis Energy, Inc., our General Partner, purchased 688,811 GELP Common Units
for $4.9 million. These transactions are expected to close in November 2003
16
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 Nine Months Ended
September 30, September 30,
2003 2002 2003 2002
------------ ----------- ------------ ------------
Gross margin (excluding depreciation)
Gathering and marketing revenues.......... $ 233,670 $ 209,916 $ 704,166 $ 680,733
Crude costs............................... 227,664 202,650 682,268 657,744
Field operating costs..................... 4,404 4,021 12,571 12,025
------------ ----------- ------------ ------------
Gathering and marketing gross margin...... $ 1,602 $ 3,245 $ 9,327 $ 10,964
============ =========== ============ ============
Pipeline revenues......................... $ 5,361 $ 6,434 $ 16,696 $ 15,625
Pipeline operating costs.................. 4,809 4,911 12,755 10,161
------------ ----------- ------------ ------------
Pipeline gross margin..................... $ 552 $ 1,523 $ 3,941 $ 5,464
============ =========== ============ ============
Barrels per day
Wellhead.................................. 60,155 60,044 60,135 64,308
Bulk and exchange......................... 24,075 23,243 22,827 42,738
Pipeline.................................. 68,029 75,172 70,285 75,385
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.
17
Nine Months Ended September 30, 2003 Compared with
Nine Months Ended September 30, 2002
Gathering and marketing gross margin excluding depreciation, Gross
margin (excluding depreciation) from gathering and marketing operations was $9.3
million for the nine months ended September 30, 2003 and $11.0 million for the
same period in 2002. The decrease in gross margin (excluding depreciation) was
the result of several factors.
Gross margin (excluding depreciation) decreased in 2003 due to the
following factors:
o a $5.1 million decrease in gross margin due to a reduction of 22
percent in wellhead, bulk and exchange purchase volumes between
the 2002 and 2003 periods;
o a $0.9 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 $0.1 million increase in field operating costs due to the costs
to dispose of water in the tanks at one of our facilities;
o a $0.2 million increase in field operating costs due to termination
benefits recorded in the 2003 period related to employees affected
by the sale of the Texas Gulf Coast Operations;
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, partially
offset by lower payroll costs; and
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.
These decreases in gross margin (excluding depreciation) in 2003 were
partially offset by a $5.0 million increase in gross margin 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.
The key drivers affecting our gathering and marketing gross margin
(excluding depreciation) include production volumes, P-Plus margins, 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 stabilized during the second and third quarters 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
18
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
July $4.6870 $27.5242
August $3.9029 $28.3952
September $3.5110 $25.1000
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 increased or can be reduced to correspond with an
increase or decrease in the P-Plus component of the related sales contract. If
P-Plus is rising, our margin will benefit until we are asked to increase the
fixed bonus. When P-Plus is declining, our margin is 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
crude oil can be volatile as a result of these timing differences. During the
first half of 2003, we benefited from the 31% increase in P-Plus from December
2002 to April 2003. However, as P-Plus increased, we adjusted bonuses on some of
our purchase contracts. When P-Plus declined in June, August and September, we
experienced declines in margins. Until we give the required notice and
renegotiate the purchase contract bonuses, or unless P-Plus increases, our
margins will be reduced.
We also saw fluctuations in grade differentials during the first nine
months 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 nine months 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.
19
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
July $(2.379) $(0.336)
August $(2.310) $(0.251)
September $(2.640) $(0.116)
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 $4.0 million for the nine months ended September
30, 2003, as compared to $5.5 million for the first nine months in 2002. The
$1.5 million decrease in pipeline gross margin (excluding depreciation) was due
to the following factors:
o a $4.1 million increase in pipeline operating costs in the 2003
period. In the third quarter of 2003, we recorded an asset retirement
obligation of $0.7 million related to an offshore pipeline.
Additionally we recorded $0.1 million of termination benefits related
to employees affected by the sale of the Texas Gulf Coast Operations.
Pipeline operating costs increased $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 for 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 $0.9 million. Expenses for maintenance of tanks, pumps and
meters increased $0.1 million. Expenses for purging lines and removal
of related equipment increased $0.3 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 nine months of 2003 totaled $0.7 million.
Insurance costs increased $0.3 million due to the combination of
insurance market conditions and our loss history. Maintenance costs
related to the pipe, including corrosion control, increased $0.1
million. Other operating costs, including power costs, increased a
total of $0.4 million;
o a $0.4 million decrease in revenues from sales of pipeline loss
allowance barrels primarily as a result of lower volumes; and
o a $0.8 million decrease in revenues due to a decline in throughput of
7% between the two periods.
20
Largely offsetting these decreases were the following factors:
o a $2.3 million increase in revenue due to a 20 percent increase in the
average tariff on shipments; and
o the 2002 period increase in our accrual for fines and penalties of
$1.5 million related to the oil spill in Mississippi in 1999; no such
accrual occurred in the 2003 period.
During the first nine months of 2003, volumes averaged 70,285 barrels
per day, with 47,498 barrels per day of that volume on the Texas System, 8,226
barrels per day on the Mississippi System and 14,561 barrels per day on the Jay
System.
Although we sold the Texas Gulf Coast Operations, we expect volumes for
the next year on our remaining pipeline segments in Texas to remain consistent
with the third quarter 2003 levels.
The volumes on the Mississippi System of 8,226 barrels per day were less
than the fourth quarter 2002 average of 9,915 barrels per day. During the first
nine months of 2003, volumes from parties other than Denbury Resources declined.
We expect Mississippi System volumes for the remainder of 2003 to average
between 6,500 and 7,500 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, 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 14,561 barrels per day for the first
nine months 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 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 have continued to benefit
2003's pipeline revenues, and additional increases went into effect in July 2003
on the Jay system. 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 nine months
of 2003, we recognized revenue of $2.8 million related to these deductions from
shippers net of losses, which totaled approximately 101,000 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 their recent 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 nine 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 $0.2
million related to the reinstatement of the Partnership's bonus program for
employees. Other general and administrative costs increased by $0.1 million. The
write-off of the unamortized costs was necessitated by the replacement of the
Citicorp Agreement with the Fleet Agreement. Under the Partnership's bonus
program, bonuses were eliminated unless distributions were being paid, which
resulted in no accrual in the 2002 period. 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..
Depreciation and amortization expense was flat between the nine month
periods. Property additions during 2002 and 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 nine-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 nine-month
21
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 September 30, 2003, we
determined that our contracts did 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. We adopted SFAS No. 149, which amends SFAS No. 133 on July 1,
2003. This statement had no effect on the results for the nine-month period. In
the 2002 period, the contracts were designated as normal purchases and sales,
and the recorded net asset of $2.1 million was charged to expense in that
period, and was included in the consolidated statements of operations in "Change
in Fair Value of Derivatives".
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 September 30, 2003 Compared with
Three Months Ended September 30, 2002
Gathering and marketing gross margin excluding depreciation. Gross
margin (excluding depreciation) from gathering and marketing operations was $1.6
million for the quarter ended September 30, 2003, as compared to $3.2 million
for the quarter ended September 30, 2002.
Gross margin (excluding depreciation) decreased in the third quarter of
2003 due to the following factors:
o a $0.8 million decrease in the 2003 period due to price variances -
a decrease in the average difference between the price of crude oil
at the point of purchase and the price of crude oil at the point of
sale, resulting primarily from the 25% decline in P-Plus from July
to September;
o a $0.6 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 $0.1 million increase in field operating costs due to the costs
to dispose of water in the tanks at one of our facilities; and
o a $0.2 million increase in field operating costs due to termination
benefits recorded in the 2003 period related to employees affected
by the sale of the Texas Gulf Coast Operations.
These decreases in gross margin (excluding depreciation) in 2003 were
partially offset by a $0.1 million increase due to a 1 percent improvement in
wellhead, bulk and exchange purchase volumes between 2002 and 2003. Credit costs
were flat between the two quarterly periods.
Pipeline gross margin excluding depreciation. Pipeline gross margin
(excluding depreciation) was $0.6 million for the quarter ended September 30,
2003, as compared to $1.5 million for the third quarter of 2002. This $0.9
million decrease in pipeline gross margin (excluding depreciation) was due to:
o a $1.4 million increase in pipeline operating costs;
o a $0.9 million decrease in revenues from sales of pipeline loss
allowance barrels primarily as a result of lower volume; and
o a $0.4 million decrease in revenue due to a decline in throughput of
10 percent between the two periods.
Partially offsetting these decreases were the following factors:
o a $0.3 million increase in revenue due to a 7 percent increase in the
average tariff on shipments; and
o the 2002 period increase in our accrual for fines and penalties of
$1.5 million related to the oil spill in Mississippi in 1999; no such
accrual occurred in the 2003 period.
22
The increased pipeline operating costs included an asset retirement
obligation of $0.7 million recorded in the 2003 period related to an offshore
pipeline. Additionally we recorded $0.1 million of termination benefits related
to employees affected by the sale of the Texas Gulf Coast Operations. Also
contributing to the increase was $0.2 million related to the GPS project and
$0.6 million related to integrity testing of the pipelines, offset by a decrease
of $0.2 million related to maintenance of the pipe, including corrosion control.
Expenses and Other. General and administrative expenses and interest
costs were flat between the two third quarter periods. As a result of the
designation of our contracts as normal purchases and sales, the recorded net
asset of $1.0 million was charged to expense in the 2002 period.
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.
Remainder of 2003
The sale of the Texas Gulf Coast Operations closed on October 31, 2003.
We expect to report a gain on this sale of approximately $12.0 million during
the fourth quarter. See the Form 8-K dated October 31, 2003 for pro forma
information of the effects of this sale.
We expect our gathering and marketing operations to perform better in
the fourth quarter than the third quarter of 2003, but not as well as the first
two quarters of 2003. Margins are expected to be lower in the final quarter due
to continuing market pressure on P-Plus. Pipeline gross margin excluding
depreciation for the final quarter of 2003 is expected to be generally
consistent with that in the first half of the year. We expect the gross margin
excluding depreciation from the CO2 activities being acquired from Denbury and
the termination of the Texas Gulf Coast Operations sold to Teppco to generally
offset each other.
2004
During 2004, we expect to generate gross margin before depreciation from
the wholesale CO2 marketing business that will offset the gross margin before
depreciation from the Texas Gulf Coast operations that were sold. However,
expected 2004 maintenance capital expenditures have been reduced by $6.6 million
to $3.1 million as a result of the sale of the Texas Gulf Coast Operations.
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. We paid a
regular distribution of $0.05 per Unit for the first and second quarters of
2003, and we have declared a distribution for the third quarter of $0.05 per
unit payable on November 14, 2003 to Common Unitholders of record on October 31,
2003, and the General Partner. As a result of the sale of the Texas Gulf
Operations and the acquisition of the CO2 contracts, we expect to increase our
regular quarterly distribution for the fourth quarter of 2003 to $0.15. We would
expect to pay that distribution in the first quarter of 2004. 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 the third quarter of
2003, we exceeded the requirement by at least $25 million at each measurement
date. We expect to be able to sustain a regular quarterly distribution of $0.15
per unit starting with the distribution that will be paid for the fourth quarter
of 2003. We continue to expect to restore the targeted minimum quarterly
distribution of $0.20 per unit in 2005. However, as we gain experience with the
new asset base, as cost savings initiatives are implemented, and as
opportunities to make accretive acquisitions are developed, we may be able to
restore the targeted minimum quarterly distribution of $0.20 per unit during
2004.
23
Liquidity and Capital Resources
Cash Flows
During the first nine months of 2003, we generated cash flows from
operating activities of $8.3 million as compared to $13.6 million for the same
period in 2002. In 2003, we reduced our inventories by $4.1 million while
changes in other components of working capital used cash of $2.3 million. Net
income was $1.5 million and depreciation of assets and amortization of assets
and deferred charges was $5.0 million. In the first nine months of 2002, net
income was $3.5 million and depreciation and amortization and other non-cash
items were $7.8 million. The change in components of working capital provided
cash of $2.3 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 nine months of
2003 were $4.0 million as compared to cash flows used in investing activities of
$0.5 million in the 2002 period. In 2003 we expended $4.1 million for property
and equipment additions, including maintenance capital expenditures totaling
$3.5 million, as further described below. Partially offsetting these
expenditures in 2003 were sales of surplus assets for $0.2 million. We also
incurred costs totaling $0.1 million related to the CO2 contract acquisition.
In the first quarter of 2002, we sold our two seats on the NYMEX for
$1.7 million. In the 2002 period, we also received $0.5 million from the
disposal of additional surplus assets, while expending $2.8 million for property
additions.
Net cash expended for financing activities was $1.5 million in the
first nine months of 2003. We expended $1.1 million for fees related to
obtaining the Fleet Agreement. We paid cash distributions totaling $0.9 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 $13.9 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 $4.1 million in the first
nine months of 2003 on capital expenditures, with $3.5 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 are needed to extend their useful lives. We spent $0.5 million for
installation of pipeline satellite monitoring capabilities, $1.2 million for
capital expenditures on the Mississippi Pipeline System, $1.2 million on the
Texas Pipeline System, and $0.6 million for truck unloading additions and
computer hardware and software. The $1.2 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. In
the first half of 2003, we continued to upgrade the West Columbia segment of our
Texas pipeline.
For the remainder of 2003, we estimate our capital expenditures will be
less than $0.5 million, with substantially all of it to 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 $3.1 million, with $2.5 million for pipeline integrity
improvements and the $0.6 million balance for tankage and other improvements. By
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 $0.5 million to $1.5 million level
annually, as the expected integrity improvements should not be as great on the
remaining segments of the pipelines.
24
Capital Resources
Our $65 million three-year credit facility with a group of banks led by
Fleet National Bank has a sublimit for working capital loans in the amount of
$25 million, with the remainder of the facility available for letters of credit.
At September 30, 2003, we had $6.0 million outstanding under the Fleet
Agreement. The average daily balance outstanding during the quarter ended
September 30, 2003 was $0.1 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
September 30, 2003, we had letters of credit outstanding under the Fleet
Agreement totaling $19.3 million, comprised of $11.4 million and $7.1 million
for crude oil purchases related to September 2003 and October 2003,
respectively, and $0.8 million related to other business obligations.
The amount of our outstanding cumulative working capital borrowings and
letters of credit is subject to a borrowing base calculation. The borrowing base
generally includes our cash balances, net accounts receivable and inventory,
less deductions for certain accounts payable, and is calculated monthly. At
September 30, 2003, the Borrowing Base was $52.2 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 (as defined in the Fleet Agreement) requiring a current ratio, a
leverage ratio, a cash flow coverage ratio, a funded indebtedness to
capitalization ratio, minimum EBITDA, and limitations on distributions to
Unitholders. 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". We were in compliance with all of these
covenants at September 30, 2003.
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 $3.5 million,
$3.0 million of which is attributed to the accrual for the fines and penalties
that we expect to pay to state and federal regulators related to our December
1999 Mississippi oil spill. 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 September 30, 2003, and have
been applied to the outstanding 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 September 30, 2003, we have the ability to borrow the funds to
make the necessary payments. The accrual for the fines and penalties and the
suspended royalties are reflected as current liabilities. Should we be required
to make these payments, we will borrow the funds under the Fleet Agreement,
thereby increasing the outstanding balance of long-term debt by $6.8 million and
reducing current liabilities and increasing working capital by $6.8 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 $74.6 million aggregate receivables on
our consolidated balance sheet at September 30, 2003, approximately $74.2
million, or 99.5%, 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 September 30,
2003 (in thousands).
25
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......... 4,206 4,926 1,793 1,849 12,774
Unconditional Purchase
Obligations (1) 99,534 - - - 99,534
------------ ------------ ----------- ------------ ------------
Total Contractual Cash
Obligations $ 103,740 $ 10,926 $ 1,793 $ 1,849 $ 118,308
============ ============ =========== ============ ============
(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 September
30, 2003, were used to value the obligations, such that actual
amounts paid may differ from the amounts included above.
As a result of the assignment to Teppco of operating leases related to
tractors and trailers used in the Texas Gulf Coast Operations, our total
operating leases will decrease by $4.2 million in total.
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 nine months ended
September 30, 2003, is as follows (in thousands):
Three Nine
Months Months
Ended Ended
September 30, September 30,
2003 2003
--------- ---------
AVAILABLE CASH BEFORE RESERVES:
Net income (loss).................................................... $ (1,213) $ 1,556
Depreciation and amortization........................................ 1,360 4,244
Cash proceeds in excess of gains on asset sales...................... 6 46
Maintenance capital expenditures..................................... (539) (3,479)
--------- ---------
Available Cash before reserves....................................... $ (386) $ 2,367
========= =========
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.
We declared a distribution for the third quarter in the amount of $0.05
per unit ($0.4 million in total) payable on November 14, 2003, to Common
Unitholders of record at the close of business on October 31, 2003, and to the
General Partner. While we did not earn sufficient Available Cash in the third
quarter for this distribution, we had reserves from the first half of the year
from which to pay the distribution.
We expect to make a regular quarterly distribution for the fourth
quarter of 2003 of $0.15 per unit, which will be paid in February 2004.
Thereafter, 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.
26
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 a quantitative standard used throughout the
investment community with respect to publicly-traded partnerships.
Several adjustments to net income are required to calculate Available
Cash. These adjustments include: (1) the addition of non-cash expenses such as
depreciation and amortization expense; (2) miscellaneous non-cash adjustments
such as the addition of 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 nine months ended
September 30, 2003, is as follows (in thousands):
Three Nine
Months Months
Ended Ended
September 30, September 30,
2003 2003
--------- ---------
Cash flows from operating activities................................. $ 2,086 $ 8,335
Adjustments to reconcile operating cash flows to Available Cash:
Maintenance capital expenditures................................. (539) (3,479)
Proceeds from asset sales........................................ 149 236
Change in fair value of derivatives.............................. - (39)
Amortization of credit facility issuance fees.................... (62) (903)
Net effect of changes in operating accounts not included in
calculation of Available Cash................................. (2,020) (1,783)
--------- ---------
Available Cash before reserves....................................... $ (386) $ 2,367
========== =========
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.
27
Any future terrorist attacks on our assets, or assets of our customers or
competitors could have a material adverse effect 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 prices and grade
differentials;
o the success of 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;
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.
28
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 September 30, 2003, no contracts were outstanding. Information about
inventory at September 30, 2003, is contained in the table set forth below.
Crude Oil Inventory
Volume in barrels................................ 180,000
Carrying value .................................. $ 3,872,000
Fair value....................................... $ 5,070,000
Fair values were determined by using the notional amount in barrels
multiplied by published market closing prices for the applicable crude oil type
at September 30, 2003.
As a result of a review of contracts existing at September 30, 2003, we
determined that our contracts did 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. We adopted SFAS No. 149, which amends SFAS No. 133 on July 1,
2003. This statement had no effect on the results for the nine-month period.
29
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 Financial 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 August 11, 2003 containing the
Partnership's earnings press release for the second 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: November 12, 2003 By: /s/ ROSS A. BENAVIDES
---------------------------------
Ross A. Benavides
Chief Financial Officer