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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
--------------------------------
FORM 10-Q
[X] QUARTERLY REPORT UNDER SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 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
incorporation or organization) Identification No.)
500 Dallas, Suite 2500, Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
(713) 860-2500 (Registrant's
telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes |X| No
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This report contains 31 pages
2
GENESIS ENERGY, L.P.
Form 10-Q
INDEX
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements Page
----
Consolidated Balance Sheets - March 31, 2003 and
December 31, 2002.............................................. 3
Consolidated Statements of Operations for the Three Months
Ended March 31, 2003 and 2002.................................. 4
Consolidated Statements of Comprehensive Income for the Three
Months Ended March 31, 2003.................................... 5
Consolidated Statements of Cash Flows for the Three Months
Ended March 31, 2003 and 2002.................................. 6
Consolidated Statement of Partners' Capital for the Three
Months Ended March 31, 2003.................................... 7
Notes to Consolidated Financial Statements....................... 8
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations...................................... 15
Item 3. Quantitative and Qualitative Disclosures about Market Risk....... 28
Item 4. Controls and Procedures.......................................... 29
PART II. OTHER INFORMATION
Item 1. Legal Proceedings................................................ 29
Item 6. Exhibits and Reports on Form 8-K................................. 29
SIGNATURES .............................................................. 29
CERTIFICATIONS............................................................ 30
3
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
(Unaudited)
March 31, December 31,
2003 2002
---------- -----------
ASSETS
CURRENT ASSETS
Cash and cash equivalents...................................... $ 1,923 $ 1,071
Accounts receivable-Trade...................................... 88,661 80,664
Inventories.................................................... 1,402 4,952
Other.......................................................... 5,184 5,410
---------- ----------
Total current assets........................................ 97,170 92,097
FIXED ASSETS, at cost............................................. 120,242 118,418
Less: Accumulated depreciation................................ (74,936) (73,958)
---------- ----------
Net fixed assets............................................ 45,306 44,460
OTHER ASSETS, net of amortization................................. 1,117 980
---------- ----------
TOTAL ASSETS...................................................... $ 143,593 $ 137,537
========== ==========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable -
Trade....................................................... $ 88,790 $ 82,640
Related party............................................... 5,928 4,746
Accrued liabilities............................................ 8,640 8,834
---------- ----------
Total current liabilities................................... 103,358 96,220
LONG-TERM DEBT.................................................... 3,500 5,500
COMMITMENTS AND CONTINGENCIES (Note 10)
MINORITY INTERESTS................................................ 515 515
PARTNERS' CAPITAL
Common unitholders, 8,625 units issued and outstanding......... 35,488 34,626
General partner................................................ 732 715
Accumulated other comprehensive income......................... - (39)
---------- ----------
Total partners' capital..................................... 36,220 35,302
---------- ----------
TOTAL LIABILITIES AND PARTNERS' CAPITAL........................... $ 143,593 $ 137,537
========== ==========
The accompanying notes are an integral part of these
consolidated financial statements.
4
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
(Unaudited)
Three Months Ended March 31,
2003 2002
------------ ------------
REVENUES:
Gathering and marketing revenues
Unrelated parties......................................................... $ 255,964 $ 231,891
Related parties........................................................... - 3,036
Pipeline revenues............................................................ 5,918 4,312
------------ ------------
Total revenues......................................................... 261,882 239,239
COST OF SALES AND OPERATIONS (excluding depreciation):
Crude costs, unrelated parties............................................... 233,110 226,817
Crude costs, related parties................................................. 15,182 -
Field operating costs........................................................ 4,139 3,990
Pipeline operating costs..................................................... 4,196 2,994
------------ ------------
Total cost of sales and operations (excluding depreciation)............... 256,627 233,801
------------ ------------
GROSS MARGIN (excluding depreciation)........................................... 5,255 5,438
EXPENSES:
General and administrative................................................... 2,363 2,088
Depreciation and amortization................................................ 1,515 1,423
Other........................................................................ (44) -
------------ ------------
OPERATING INCOME................................................................ 1,421 1,927
OTHER INCOME (EXPENSE):
Interest income.............................................................. 8 5
Interest expense............................................................. (550) (405)
Change in fair value of derivatives.......................................... - (702)
Gain on disposals of surplus assets.......................................... - 489
------------ ------------
Income before minority interests ............................................... 879 1,314
Minority interests.............................................................. - -
------------ ------------
NET INCOME...................................................................... $ 879 $ 1,314
============ ============
NET INCOME PER COMMON UNIT - BASIC AND DILUTED.................................. $ 0.10 $ 0.15
============ ============
WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING............................. 8,625 8,625
============ ============
The accompanying notes are an integral part of these
consolidated financial statements.
5
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
(Unaudited)
Three Months Ended March 31,
2003 2002
------------ ------------
NET INCOME...................................................................... $ 879 $ 1,314
OTHER COMPREHENSIVE INCOME:
Change in fair value of derivatives used for hedging purposes............. 39 -
------------ ------------
COMPREHENSIVE INCOME............................................................ $ 918 $ 1,314
============ ============
The accompanying notes are an integral part of these
consolidated financial statements.
6
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
Three Months Ended March 31,
2003 2002
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income...................................................................... $ 879 $ 1,314
Adjustments to reconcile net income to net cash provided by operating
activities -
Depreciation................................................................. 1,309 1,211
Amortization of covenant not-to-compete...................................... 206 212
Amortization and write-off of credit facility issuance costs................. 750 159
Change in fair value of derivatives.......................................... 39 702
Gain on asset disposals...................................................... (44) (489)
Other noncash charges........................................................ - 810
Changes in components of working capital -
Accounts receivable....................................................... (7,997) 81,853
Inventories............................................................... 3,550 2,540
Other current assets...................................................... 226 3,766
Accounts payable.......................................................... 7,332 (87,660)
Accrued liabilities....................................................... (194) (3,219)
--------- ---------
Net cash provided by operating activities......................................... 6,056 1,199
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment............................................. (2,195) (749)
Change in other assets.......................................................... - 1
Proceeds from sale of assets.................................................... 84 1,703
--------- ---------
Net cash (used in) provided by investing activities............................... (2,111) 955
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net repayments of debt.......................................................... (2,000) (7,400)
Credit facility issuance fees................................................... (1,093) -
--------- ---------
Net cash used in financing activities............................................. (3,093) (7,400)
--------- ---------
Net increase (decrease) in cash and cash equivalents.............................. 852 (5,246)
Cash and cash equivalents at beginning of period.................................. 1,071 5,777
--------- ---------
Cash and cash equivalents at end of period........................................ $ 1,923 $ 531
========= =========
The accompanying notes are an integral part of these
consolidated financial statements.
7
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 three months ended March 31, 2003... $ 862 $ 17 $ - $ 879
Change in fair value of derivatives used for hedging
purposes............................................. - - 39 39
---------- --------- ------------- -------------
Partners' capital at March 31, 2003.................... $ 35,488 $ 732 $ - $ 36,220
========== ========= ============= =============
The accompanying notes are an integral part of these
consolidated financial statements.
8
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Partnership Structure
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 of 98%. The General Partner of GELP is Genesis
Energy, Inc. (the "General Partner") and owns a 2% general partner interest in
GELP. The General Partner is owned by Denbury Gathering & Marketing, Inc. a
subsidiary of Denbury Resources Inc.
Genesis Crude Oil, L.P. is the operating limited partnership and is owned
99.99% by GELP and 0.01% by the General Partner. Genesis Crude Oil, L.P. has two
subsidiary partnerships, Genesis Pipeline Texas, L.P. and Genesis Pipeline USA,
L.P. Genesis Crude Oil, L.P. and its subsidiary partnerships will be referred to
as GCOLP.
2. Basis of Presentation
The accompanying financial statements and related notes present the
consolidated financial position as of March 31, 2003 and December 31, 2002 for
GELP, its results of operations and cash flows for the three months ended March
31, 2003 and 2002, and changes in its partners' capital for the three months
ended March 31, 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 accounting principles generally
accepted in the United States of America 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 months ended March 31, 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 either 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
In June, 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." 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. The standard is effective for Genesis on January 1, 2003.
With respect to its pipelines, federal regulations will require GELP to
purge the crude oil from its pipelines when the pipelines are retired. The
Partnership's right of way agreements do not require it to remove pipe or
otherwise perform remediation upon taking the pipelines out of service. Many of
its truck unload stations are on leased sites that require that the Partnership
remove our 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.
9
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities," which addresses accounting for
restructuring and similar costs. SFAS No. 146 supersedes previous accounting
guidance, principally EITF Issue No. 94-3. The Partnership will adopt the
provisions of SFAS No. 146 for restructuring activities initiated after December
31, 2002. SFAS No. 146 requires that the liability for costs associated with an
exit or disposal activity be recognized when the liability is incurred. Under
Issue No. 94-3, a liability for an exit cost was recognized at the date of
commitment to an exit plan. SFAS No. 146 also establishes that the liability
should initially be measured and recorded at fair value. Accordingly, SFAS No.
146 may affect the timing of recognizing future restructuring costs as well as
the amounts recognized. The impact that SFAS No. 146 will have on the
consolidated financial statements will depend on the circumstances of any
specific exit or disposal activity.
In November 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others". This interpretation of SFAS No. 5, 57 and
107, and rescission of FASB Interpretation No. 34 elaborates on the disclosures
to be made by a guarantor in its interim and annual financial statements about
its obligations under certain guarantees that it has issued. It also clarifies
that a guarantor is required to recognize, at the inception of a guarantee, a
liability for the fair value of the obligation undertaken in issuing the
guarantee. The initial recognition and initial measurement provisions of this
interpretation are applicable on a prospective basis to guarantees issued or
modified after December 31, 2002. The disclosure requirements in this
interpretation are effective for financial statements of interim or annual
periods after December 15, 2002 and are included in Note 10.
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation-Transition and Disclosure," which provides alternative methods of
transition from a voluntary change to the fair value based method of accounting
for stock-based employee compensation. In addition, SFAS No. 148 amends the
disclosure requirements of SFAS No. 123 in both annual and interim financial
statements. SFAS No. 148 is effective for financial statements for fiscal years
ending after December 15, 2002, and financial reports containing condensed
financial statements for interim periods beginning after December 15, 2002. At
this time, there are no outstanding grants of Partnership units under the
Partnership's Restricted Unit Plan (see Note 15). Therefore, the adoption of
this statement had no effect on either the financial position, results of
operations, cash flows or disclosure requirements of the Partnership.
4. Business Segment and Customer Information
Based on its management approach, the Partnership believes that all of its
material operations revolve around the gathering and marketing of crude oil, and
it currently reports its operations, both internally and externally, as a single
business segment. Marathon Ashland Petroleum LLC, ExxonMobil Corporation and
Shell Oil Company accounted for 25%, 14% and 14%, respectively, of revenues in
the first quarter of 2003. ExxonMobil Corporation and Marathon Ashland Petroleum
LLC accounted for 14% and 13%, respectively, of revenues in the first quarter of
2002.
5. Inventory Reduction
Due to operational changes made by the Partnership to reduce credit usage
during 2002, 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. The Partnership realized additional gross margin
(excluding depreciation) of approximately $337,000 during the first quarter of
2002 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.
10
The key terms of the Fleet Agreement are as follows:
o Letter of credit fees are based on the Applicable Usage Level
("AUL") (as defined in the Fleet Agreement) and will range from
2.00% to 3.00%. During the first six months of the facility, the
rate will be 2.50%. The AUL is a function of the facility usage to
the borrowing base on that day.
o The interest rate on working capital borrowings is also based on the
AUL and allows for loans based on the prime rate or the LIBOR rate
at our 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 rate will be the LIBOR rate plus 2.50%.
o The Partnership pays a commitment fee on the unused portion of the
$65 million commitment. This commitment fee is also based on the AUL
and will range from 0.375% to 0.50%. During the first six months of
the facility, the commitment fee will be 0.50%.
o The amount that the Partnership may have outstanding in working
capital borrowings and letters of credit is subject to a Borrowing
Base calculation. The Borrowing Base (as defined in the Fleet
Agreement) generally includes 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
property and equipment.
o The Fleet Agreement contains covenants requiring a Current Ratio (as
defined in the Fleet Agreement), a Leverage Ratio (as defined in the
Fleet Agreement), a Cash Flow Coverage Ratio (as defined in the
Fleet Agreement), a Funded Indebtedness to Capitalization Ratio (as
defined in the Fleet Agreement), Minimum EBITDA (as defined in the
Fleet Agreement), and limitations on distributions to Unitholders.
Under the Fleet Agreement, distributions to Unitholders and the General
Partner can only be made if the Borrowing Base exceeds the usage (working
capital borrowings plus outstanding letters of credit) under the Fleet Credit
Facility by at least $10 million plus the distribution, measured once each
month. See additional discussion below under "Distributions".
At March 31, 2003, the Partnership had $3.5 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 March 31, 2003, the Partnership
had letters of credit outstanding under the Fleet Agreement totaling $30.0
million, comprised of $16.1 million and $13.1 million for crude oil purchases
related to March 2003 and April 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 Available Cash.
Distributions
Generally, GCOLP will distribute 100% of its Available Cash within 45
days after the end of each quarter to Unitholders of record and to the General
Partner. Available Cash consists generally of all of the cash receipts less cash
disbursements of GCOLP adjusted for net changes to reserves. Currently, the
target minimum quarterly distribution ("MQD") for each quarter is $0.20 per
unit.
Under the Fleet Agreement, distributions to Unitholders and the General
Partner can only be made if the Borrowing Base exceeds the usage (working
capital borrowings plus outstanding letters of credit) under the Fleet Agreement
by at least $10 million plus the distribution, measured once each month.
11
For the first quarter of 2002, the Partnership did not pay a
distribution as the excess of the Borrowing Base over the usage dropped below
required levels. During the first quarter of 2003, the Partnership met the test
in the Fleet Agreement and has declared a distribution of $0.05 per unit payable
on May 15, 2003 to Unitholders of record on April 30, 2003.
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.
7. Transactions with Related Parties
Sales, purchases and other transactions with affiliated companies, except
for guarantee fees paid 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
A summary of sales to and purchases from related parties of crude oil is
as follows (in thousands).
Three Months Three Months
Ended Ended
March 31, March 31,
2003 2002
----------- ------------
Purchases from Denbury..................... $ 15,182 $ -
Sales to Salomon affiliates................ $ - $ 3,036
Denbury became a related party in May 2002. Purchases from Denbury
during the three months ended March 31, 2002 before it became an affiliate were
$6.0 million. Purchases from Denbury are secured by letters of credit.
Salomon ceased to be a related party in May 2002. The related party
sales in the three months ended March 31, 2002 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. Those functions are provided by the General Partner. The
Partnership reimburses the General Partner for all direct and indirect costs of
these services. Total costs reimbursed to the General Partner by the Partnership
were $3,992,000 and $4,776,000 for the three months ended March 31, 2003 and
2002, respectively.
Directors' Fees
The Partnership paid $30,000 to Denbury in the first quarter of 2003 for
the services of four of Denbury's officers as directors of the General Partner.
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. In the three months ended March 31, 2002 the
Partnership incurred letter of credit fees, interest and commitment fees
totaling $283,000 under the Credit Agreement. In 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 three
months ended March 31, 2002, the Partnership paid Salomon $47,000 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.
12
8. Supplemental Cash Flow Information
Cash received by the Partnership for interest was $9,000 and $5,000 for the
three months ended March 31, 2003 and 2002, respectively. Payments of interest
and commitment fees were $130,000 and $142,000 for the three months ended March
31, 2003 and 2002, respectively.
9. Derivatives
The Partnership's market risk in the purchase and sale of its crude oil
contracts is the potential loss that can be caused by a change in the market
value of the asset or commitment. In order to hedge its exposure to such market
fluctuations, the Partnership enters into various financial contracts, including
futures, options and swaps. Normally, any contracts used to hedge market risk
are less than one year in duration.
The Partnership utilizes crude oil futures contracts and other financial
derivatives to reduce its exposure to unfavorable changes in crude oil prices.
On January 1, 2001, the Partnership adopted the provisions of SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities", which
established new accounting and reporting guidelines for derivative instruments
and hedging activities. SFAS No. 133 established accounting and reporting
standards requiring that every derivative instrument (including certain
derivative instruments embedded in other contracts) be recorded in the balance
sheet as either an asset or liability measured at its fair value. SFAS No. 133
requires that changes in the derivative's fair value be recognized currently in
earnings unless specific hedge accounting criteria are met. Accounting for
qualifying hedges allows a derivative's gains and losses to offset related
results on the hedged item in the income statement. Companies must formally
document, designate and assess the effectiveness of transactions that receive
hedge accounting.
Under SFAS No. 133, the Partnership marks to fair value its derivative
instruments at each period end with changes in fair value of derivatives not
designated as hedges being recorded as unrealized gains or losses. Such
unrealized gains or losses will change, based on prevailing market prices, at
each balance sheet date prior to the period in which the transaction actually
occurs. Unrealized gains or losses on derivative transaction qualifying as
hedges are reflected in other comprehensive income.
The Partnership regularly reviews its contracts to determine if the
contracts qualify for treatment as derivatives in accordance with SFAS No. 133.
At March 31, 2003, the Partnership had no contracts outstanding that qualified
for derivative treatment under SFAS NO. 133. At December 31, 2002, the
Partnership determined that the only contract qualifying as a derivative was a
qualifying cash flow hedge. The decrease of $39,000 in the fair value of this
hedge was recorded in other comprehensive income and as accumulated other
comprehensive income in the consolidated balance sheet. No hedge ineffectiveness
was recognized during 2002. The anticipated transaction (crude oil sales)
occurred in January 2003, and all related amounts held in other comprehensive
income at December 31, 2002, were reclassified to the income statement in the
first quarter of 2003. The Partnership determined that its other derivative
contracts qualified for the normal purchase and sale exemption at March 31,
2003. The decrease in fair value of the Partnership's net asset for derivatives
not qualifying as hedges in the first quarter of 2002 was $0.7 million. This
decrease in fair value of $0.7 million is recorded as a loss in the consolidated
statements of operations under the caption "Change in fair value of
derivatives".
10. Contingencies
Guarantees
The Partnership has guaranteed $5.2 million of residual value related to
the leases of tractors and trailers. Management of the Partnership believes the
likelihood the Partnership would be required to perform or otherwise incur any
significant losses associated with this guaranty is remote.
GELP has guaranteed crude oil purchases of GCOLP. These guarantees,
totaling $9.9 million, were provided to counterparties. To the extent
liabilities exist under the contracts subject to these guarantees, such
liabilities are included in the consolidated balance sheet.
13
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 March 31, 2003, were $3.5
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 the restructuring
and seeking damages. Defendants named in the complaint include the Partnership,
Genesis Energy L.L.C., members of the board of directors of Genesis Energy,
L.L.C., and Salomon Smith Barney Holdings Inc. The plaintiff alleges numerous
breaches of fiduciary duty loyalty owed by the defendants to the purported class
in connection with making a proposal for restructuring. In November 2000, the
plaintiff amended its complaint. In response, the defendants removed the amended
complaint to federal court. On March 27, 2002, the federal court dismissed the
suit; however, the plaintiff filed a motion to alter or amend the judgment. On
May 15, 2002, the federal court denied the motion to alter or amend. The time
for an appeal to be taken expired without an appeal being filed. On June 11,
2002, the plaintiff refiled the original complaint in the Delaware Court of
Chancery, No. 19694-NC. On July 19, 2002, the defendants moved to dismiss the
complaint for failure to state a claim upon which relief can be granted. The
court has not ruled on that motion. Management of the General Partner believes
that the complaint is without merit and intends to vigorously defend the action.
Management of the Partnership believes that any potential liability will be
covered by insurance.
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 ourselves 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 ourselves 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 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. As a result of this crude oil spill, certain federal and state
regulatory agencies will likely impose fines and penalties that would 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's management has made an assessment of its potential environmental
exposure, and as a result of the spill from the Mississippi System, a total
accrual of $3.0 million was recorded during 2002 and 2001.
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.
14
11. Subsequent Event
On April 14, 2003, the Board of Directors of the General Partner declared a
cash distribution of $0.05 per Unit for the quarter ended March 31, 2003. The
distribution will be paid May 15, 2003, to the General Partner and all Common
Unitholders of record as of the close of business on April 30, 2003.
15
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Included in Management's Discussion and Analysis are the following sections:
o Results of Operations
o Outlook for the Remainder of 2003 and Beyond
o Liquidity and Capital Resources
o Other Matters
o New Accounting Pronouncements
o Forward Looking Statements
Results of Operations
Selected financial data for this discussion of the results of operations
follows, in thousands, except volumes per day.
Three Months Ended March 31,
2003 2002
----------- ------------
Gross margin (excluding depreciation)
Gathering and marketing..................................... $ 3,533 $ 4,120
Pipeline.................................................... $ 1,722 $ 1,318
General and administrative expenses............................ $ 2,363 $ 2,088
Depreciation and amortization.................................. $ 1,515 $ 1,423
Operating income............................................... $ 1,421 $ 1,927
Interest income (expense), net................................. $ (542) $ (400)
Change in fair value of derivatives............................ $ - $ (702)
Net gain on disposals of surplus assets........................ $ - $ 489
Volumes per day
Wellhead.................................................... 61,499 67,466
Bulk and exchange........................................... 22,555 67,115
Pipeline.................................................... 71,392 75,409
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 along the Distribution Chain 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. We then
transport the crude along the Distribution Chain 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. Prior to the
first quarter of 2002, we purchased crude oil in bulk at major pipeline terminal
points. These bulk and exchange transactions were characterized by large volumes
and narrow profit margins on purchases and sales.
16
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.
Gathering and marketing gross margin (excluding depreciation). Gross margin
(excluding depreciation) from gathering and marketing operations was $3.5
million for the quarter ended March 31, 2003, as compared to $4.1 million for
the quarter ended March 31, 2002.
The factors affecting gross margin (excluding depreciation) were:
o an increase in gross margin (excluding depreciation) of $2.9 million
due to 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;
o a 38 percent decrease in wellhead, bulk and exchange purchase
volumes between 2002 and 2003, resulting in a decrease in gross
margin (excluding depreciation) of $2.9 million;
o an increase of $0.2 million in credit costs primarily due to the
use of letters of credit in 2003 at a higher cost than the Salomon
guaranties used during the first quarter of 2002;
o a $0.3 million increase in gross margin (excluding depreciation) in
the 2002 period as a result of the sale of crude oil that was no
longer needed to ensure efficient and uninterrupted operations; and
o an increase of $0.1 million in field operating costs, primarily from
a $0.2 million increase in repair costs and a $0.1 million increase
in fuel costs. Offsetting these increases was a $0.2 million
decrease in payroll and benefit costs. The increase in repair costs
is attributable primarily to painting and repairs at truck unloading
stations. The increased fuel costs are due to the increase in market
costs for petroleum products as a result of the higher crude oil
prices in 2003. The decrease in personnel costs is due to a
reduction in the number of drivers as we reduced volumes where
margin on a transaction did not support related costs.
During the first quarter of 2002, we reviewed our wellhead purchase
contracts to determine whether margins under these contracts would support
higher credit costs per barrel. In some cases where contracts could not be
renegotiated to improve margins after considering the higher cost of credit,
contracts were cancelled. During this same period we reviewed our exchange
transactions with parties requiring credit support from us and eliminated those
transactions with margins that would be insufficient to provide for the cost of
a letter of credit.
17
Pipeline gross margin excluding depreciation. Pipeline gross margin
excluding depreciation was $1.7 million for the quarter ended March 31, 2003 as
compared to $1.3 million for the first quarter of 2002. The factors affecting
pipeline gross margin (excluding depreciation) were:
o an increase in revenues of $0.2 million from recognition of pipeline
loss allowance barrels primarily as a result of revising pipeline
tariffs to increase the amount of the pipeline loss allowance
imposed on shippers,, as well as the sale of volumes in inventory at
December 31, 2002;
o an increase of 56 percent in the average tariff on shipments
resulting in an increase in revenue of $1.6 million;
o a decrease in throughput of 5 percent between the two periods,
resulting in a revenue decrease of $0.2 million, due primarily to
lower volumes on the Texas System partly as a result of stopping
shipments while a pressure test was performed on a segment of the
pipeline; and
o an increase in pipeline operating costs of $1.2 million in the first
quarter of 2003. Personnel and benefits costs increased $0.1
million primarily as a result of additions to the operations staff
in Mississippi and additions of staff engineers, and costs
associated with work vehicles for the new staff added $0.1 million.
Costs associated with maintenance of right of ways including
clearing of tree canopies and costs associated with residential and
commercial development around our pipelines and testing under
pipeline integrity regulations by pressure testing part of the
Texas System increased a combined $0.1 million. Expenses for
maintenance of pumps and meters increased $0.2 million. Expenses
for purging lines increased $0.1 million. In 2003, we increased
safety training for our pipeline operations personnel by a cost of
$0.2 million. During the third quarter of 2002, we undertook a
project to add Global Positioning Satellite information to our
pipeline maps as required pursuant to pipeline safety regulations.
Expenses incurred on this project in the first quarter of 2003
totaled $0.3 million. Insurance costs increased by $0.1 million due
to the combination of insurance market conditions and our loss
history. Other operating costs, including power costs and corrosion
control, increased by $0.1 million. Our remote monitoring and
control costs were lower by $0.1 million as we completed the
transition in early 2002 from a more expensive service.
General and administrative expenses. General and administrative expenses
were $2.4 million for the three months ended March 31, 2003, which was an
increase of $0.3 million from the 2002 period. The increase in general and
administrative expenses is primarily attributable to the write-off of $0.2
million of unamortized legal and consultant costs related to the Citicorp
Agreement. We experienced increases in some recurring items such as audit and
tax expenses, legal fees, insurance expense, travel and entertainment totaling
$0.4 million which were partially offset by reductions totaling $0.3 million in
salaries and benefits and subscriptions for pricing services that were
eliminated during the first quarter of 2002 when we exited the bulk business.
Depreciation and amortization. Depreciation and amortization in the 2003
quarter increased by $0.1 million when compared to the 2002 period due to
property additions made during 2002.
Interest expense. Interest expense increased $0.1 million due to the
write-off of $0.4 million of unamortized facility costs related to the Citicorp
Agreement which was replaced with the Fleet Facility, offset by lower commitment
fees in the 2003 period. From January 1, 2003 through March 13, 2003, we paid
commitment fees on the unused portion of the $80 million facility with Citicorp
and from March 14, 2003 through the end of the quarter, we paid commitment fees
on the unused portion of the $65 million Fleet Agreement.. In the 2002 quarter,
we paid commitment fees on the unused portion of our $130 million Credit
Agreement with Citicorp.
Change in fair value of derivatives. As a result of a review of contracts
existing at March 31, 2003, we determined that our contracts do not meet the
requirement for treatment as derivative contracts under SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" (as amended and
interpreted). The contracts were designated as normal purchases and sales under
the provisions for that treatment in SFAS No. 133.
The fair value of the Partnership's net asset for derivatives had decreased
by $0.7 million for the three months ended March 31, 2002.
Gain on disposal of surplus assets. 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").
18
Outlook for the Remainder of 2003 and Beyond
The information below is provided as an update to the "Outlook for 2003
and Beyond" section of our Annual Report on Form 10-K for the year ended
December 31, 2002.
Gathering and Marketing Operations
The key drivers affecting our gathering and marketing gross margin
(excluding depreciation) include production volumes, volatility of P-Plus
margins, volatility of grade differentials, inventory management, and credit
costs.
A significant factor affecting our gathering and marketing gross
margins (excluding depreciation) is changes in the domestic production of crude
oil. Short-term and long-term price trends impact the amount of capital that
producers have available to maintain existing production and to invest in
developing crude reserves, which in turn impacts the amount of crude oil that is
available to be gathered and marketed by us and our competitors. The volatility
in prices over the last four years makes it very difficult to estimate the
volume of crude oil available to purchase. We expect to continue to be subject
to volatility and long-term declines in the availability of crude oil production
for purchase by us.
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 quarter.
Most of our contracts for the purchase and sale of crude oil have
components in the pricing provisions such that the price paid or received is
adjusted for changes in the market price for crude oil, so that the changes in
prices do not necessarily have a direct impact on our profitability. Often the
pricing in a contract to purchase crude oil will consist of the market price
component and a bonus, which is generally a fixed amount ranging from a few
cents to several dollars. Typically the pricing in a contract to sell crude oil
will consist of the market price component and a bonus that is not fixed, but
instead is based on another market factor. This floating bonus market factor in
the sales contracts is usually the price quoted by Platt's for WTI "P-Plus".
Because the bonus for purchases of crude oil is fixed and P-Plus floats in the
sales contracts, the margin on an individual transaction can vary from
month-to-month depending on changes in the P-Plus component.
P-Plus does not necessarily move in correlation with the price of oil
in the market. P-Plus is affected by numerous factors such as future
expectations for changes in crude oil prices, such that crude oil prices can be
rising, but P-Plus can be decreasing. The table below shows the average P-Plus
and the average posted price for West Texas Intermediate (WTI) as posted by Koch
Supply & Trading, L.P. for December 2002 and the first quarter of 2003.
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
We were able to sell some crude oil while P-Plus was increasing that
was purchased at fixed bonuses. However should P-Plus remain at these high
levels, some producers will ask that we adjust the fixed bonuses in our
contracts with them such that the differences between P-Plus and the fixed
bonuses will decline which will adversely affect gross margin (excluding
depreciation).
19
Our purchase and sales contracts are primarily "Evergreen" contracts
which means they continue from month to month unless one of the parties to the
contract gives 30-days notice of cancellation. In order to change the pricing in
a fixed bonus contract, we would have to give 30-days notice that we want to
cancel and renegotiate the contract. This notice requirement, therefore, means
that at least a month will pass before the fixed bonus can be reduced to
correspond with a decrease in the P-Plus component of the related sales
contract. In this case our margin would be reduced until such a change is made.
Because of the volatility of P-Plus, it is not practical to renegotiate every
purchase contract for every change in P-Plus. So margins from the sale of the
crude oil can be volatile as a result of these timing differences. Because of
the increase in P-Plus in the last quarter of 2002 and first quarter of 2003, we
have adjusted bonuses on some contracts. Should P-Plus decline to levels more
consistent with the first five months of 2002 when P-Plus ranged from $2.744 to
$3.1005, we could experience declines in margins until we are able to give the
required notice and renegotiate the purchase contract bonuses.
We also saw fluctuations in grade differentials during the first
quarter 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 who
ultimately process the oil. We may buy oil under a contract where we considered
the typical grade differences in the market when we set the fixed bonus. If we
then sell the oil under a contract with a floating grade differential in the
formula, and that grade differential fluctuates, then we can experience an
increase or decrease in our 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 quarter of 2003 and the differential
between West Texas Intermediate grade crude oil and Light Louisiana Sweet grade
crude oil for the same periods.
WTI/WTS WTI/LLS
Month Differential Differential
----- ------------ ------------
December $(2.243) $(0.008)
January $(1.569) $ 0.510
February $(1.404) $ 0.692
March $(4.109) $ 0.178
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 generally aggregate the volumes purchased from numerous wells and
deliver it into a pipeline where we sell the crude oil to a third party. While
oil producers can make estimates of the volume of oil that their wells will
produce in a given month, they cannot state absolutely 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 thus required to hedge the value of our
inventory. 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.
Both gathering and marketing volumes and margins are expected to be
lower during 2003 as compared to 2002 as this business is likely to be subject
to market volatility. Additionally, this business may be constrained by the need
for trade credit if crude oil prices increase above current levels on a
sustained basis or should credit demands from producers increase. During 2003,
we expect gathering and marketing gross margins (excluding depreciation) to
decline relative to 2002 due to an expected decrease in the volume of crude oil
to be gathered during 2003.
20
Pipeline Operations
Volumes on our pipeline systems declined during the first quarter of
2003 as compared to the same period in 2002. We expect this volumetric loss to
continue during the remainder of 2003.
During the first quarter of 2003, volumes averaged 71,392 barrels per
day, with 46,842 barrels per day of that volume on the Texas System, 9,295
barrels per day on the Mississippi System and 15,255 barrels per day on the Jay
System. The Texas System volume was negatively impacted during the first quarter
due to the cessation of deliveries to Marathon Ashland Petroleum LLC for almost
a month while we conducted a pressure test of our pipeline and Marathon
performed routine major maintenance. We expect volumes to return to
approximately the average in the fourth quarter of 2002 on the Texas System of
49,531 barrels per day.
The volumes on the Mississippi System of 9,295 barrels per day were
less than the fourth quarter average of 9,915 barrels per day. During the first
quarter of 2003, volumes from parties other than Denbury Resources Inc.
declined. We expect Mississippi System volumes for the remainder of 2003 to
average between 9,000 and 10,000 barrels per day. We had anticipated 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, to begin shipping again during the latter half of 2003. It now appears
unlikely that shipments of any significance on this segment will begin before
2004 as sufficient volumes do not appear to be available for shipment.
The volumes on the Jay System were 15,255 barrels per day for the first
quarter of 2003. During the fourth quarter of 2002, volumes on this system
averaged 14,748 barrels. We were recently advised by a producer near our
pipeline that their development plans for their fields in the area have been
postponed until the fourth quarter of 2003, so it is unlikely that we will see
any increase in volume on this system until late in 2003.
The tariff increases we obtained in 2002 should continue to benefit
2003's pipeline revenues. Gross margin (excluding depreciation) from pipeline
operations was positively impacted by the recognition of revenue from volumes
related to the pipeline loss allowances and quality deductions from shipper
volumes in excess of volumetric measurement losses. During the first quarter of
2003, we recognized revenue of $1.0 million related to these deductions from
shippers net of losses, which totaled approximately 35,000 barrels. Additionally
we realized $0.4 million of revenue from the sale of volumes in inventory at
December 31, 2002 due to the rise in prices. If crude oil market prices continue
the recent trend to decline, revenues from these net deductions may be less.
We expect our pipeline operating costs to be higher for the remainder
of 2003 than in 2002 as we continue testing under the IMP program, perform
testing of tanks and painting projects at pipeline stations. Pipeline gross
margin (excluding depreciation) should decline slightly in 2003 as compared to
2002.
We are currently reviewing strategic opportunities for the Texas
System. While the tariff increases in 2002 have improved the outlook for this
system, we continue to examine opportunities for every part of the system to
determine if each segment should be sold, abandoned or invested in for further
growth. As part of this examination, we must consider the ability to increase
tariffs, which involves reviewing the alternatives available to shippers to move
the oil on other pipelines or by truck, production and drilling in the area
around the pipeline, the costs to test and improve our pipeline under integrity
management regulations, and other maintenance and capital expenditure
expectations.
Our Mississippi pipeline is adjacent to several of Denbury's existing
and prospective oil fields. There may be mutual benefits to Denbury and us due
to this common production and transportation area. Because of this relationship,
we may be able to obtain certain commitments for increased crude oil volumes,
while Denbury may obtain the certainty of transportation for its oil production
at competitive market rates. As Denbury continues to acquire and develop old oil
fields using carbon dioxide (CO2) based tertiary recovery operations, Denbury
would expect to add crude oil gathering and CO2 supply infrastructure to these
fields. Further, as the fields are developed over time, it may create increased
demand for our crude oil transportation services.
General and Administrative Expenses
General and administrative expenses increased slightly in the first
quarter of 2003 due to the write-off of the unamortized legal and consultant
costs related to the Citicorp Agreement that totaled $0.2 million. This
write-off was necessitated by the replacement of the Citicorp Agreement with the
Fleet Agreement. We also expect to incur cost increases for insurance and other
costs to comply with SEC regulations mandated by the Sarbanes-Oxley Act in 2003.
21
Capital Expenditures
An important factor affecting our outlook is capital expenditures. In
our 2002 Form 10-K, we indicated that we established a capital budget of $6.7
million for maintenance capital expenditures for 2003. During the first quarter
of 2003, we made capital expenditures totaling $2.2 million, with $1.6 million
of that total for maintenance capital expenditures. For the remainder of 2003,
we expect to expend $5.1 million for maintenance capital items. For 2004, we
expect to make capital expenditures of $8.4 million. After 2004, capital
expenditures are expected to return to a normal pattern of approximately $2.0
million per year.
Access to Capital
The most significant event in the first quarter of 2003 was replacement
of the credit facility with Citicorp North America, Inc. ("Citicorp") with a
three-year $65 million credit facility ("Fleet Agreement") with a group of
banks, with Fleet National Bank as agent.
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
similar to the terms in the Citicorp Agreement. The details of those terms are
described more fully below in "Liquidity and Capital Resources".
As a result of the replacement of the Citicorp Agreement, the
unamortized 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 in interest expense.
Distribution Expectations
As a master limited partnership, the key consideration of our
Unitholders is the amount of our distribution, its reliability and the prospects
for distribution growth. We made no regular distributions during 2002. On April
14, 2003, we declared a regular distribution of $0.05 per Unit for the first
quarter of 2003 payable on May 15, 2003 to Common Unitholders and the General
Partner of record on April 30, 2003. 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. Based on the need for larger than normal capital
expenditures to comply with the pipeline regulations during 2003 and 2004 and
the need to strengthen our balance sheet to improve our access to capital for
growth, and considering the restrictive covenant in our new credit facility, we
do not expect to restore the regular distribution to the targeted minimum
quarterly distribution amount of $0.20 per quarter for the next year or two.
However, if we exceed our expectations for improving the performance of the
business, if our capital projects cost less than we currently estimate, or if
our access to capital allows us to make accretive acquisitions, we may be able
to restore the targeted minimum quarterly distribution sooner.
Liquidity and Capital Resources
Cash Flows
During the first quarter of 2003, we generated cash flows from
operating activities of $6.0 million as compared to $1.2 million for the same
period in 2002. In 2003, we reduced our inventories by $3.6 million while the
other components of working capital increased $0.6 million. Net income was $0.9
million and depreciation of assets and amortization of assets and deferred
charges was $1.5 million. In the first quarter of 2002, net income was 1.3
million and depreciation and amortization was 1.6 million. The change in
components of working capital resulted in the utilization of $2.7 million of
cash. 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.
22
Cash flows used in investing activities in the first quarter of 2003
were $2.1 million as compared to cash flows provided by investing activities of
$1.0 million in the 2002 period. In 2003 we expended $2.2 million for property
and equipment additions. Maintenance capital expenditures totaling $1.6 million
included refurbishment of pipe in Mississippi and Texas, the addition of
equipment to allow us to switch to satellite monitoring of our pipelines and
additional upgrades to pipeline pumps and meters in Mississippi to handle larger
volumes of crude oil throughput. Additionally we purchased a condensate storage
facility in Texas for $0.6 million. Offsetting these expenditures in 2003, were
sales of surplus assets from which we received $0.1 million. In the first
quarter of 2002, we sold our two seats on the NYMEX for $1.7 million. These
seats had become surplus assets when the business model was changed to reduce
bulk and exchange activities, reducing the level of NYMEX activity that Genesis
would need. We also expended $0.8 million for property additions during that
period.
Net cash expended for financing activities was $3.1 million in the
first quarter of 2003. We expended $1.1 million for fees related to obtaining
the Fleet Agreement and we reduced the outstanding balance of our long-term debt
by $2.0 million. In the 2002 period, we repaid $7.4 million of debt under our
credit facility. No cash distributions were paid in either period.
Capital Expenditures
As discussed above, we expended $1.6 million in the first quarter of
2003 for maintenance capital expenditures on property and equipment. We spent
$0.5 million for capital expenditures on the Mississippi Pipeline System, $0.6
million on the Texas Pipeline System, and $0.5 million for computer hardware,
software, communication and other technological equipment used for pipeline and
trucking operations. The $0.5 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 Texas, we
continued to upgrade the West Columbia segment of the pipeline.
For the remainder of 2003, we estimate our capital expenditures will be
approximately $5.1 million. We expect $3.5 million of the $5.1 million will be
spent for capital improvements to our pipeline systems as result of the IMP
assessments. Of the remaining $1.6 million in capital expenditures,
substantially all of it will be spent on other pipeline improvements such as
tankage, equipment upgrades including a change to satellite monitoring, and
corrosion control.
In 2004, we expect the level of capital expenditures to be
approximately $8.4 million with $4.6 million for pipeline integrity improvements
and the balance of $3.8 million for tankage and other improvements. At the end
of 2004, we expect that we will have incurred most of the significant costs
related to the IMP regulatory compliance and expect to only spend $1.8 million
in 2005 for capital items, with $1.2 million related to IMP. Expenditures in
years after 2006 should remain in the $1.5 million to $2.5 million level as the
expected integrity improvements should not be as great on the remaining segments
of the pipelines.
Capital Resources
In March 2003, we replaced our credit agreement with Citicorp with a
$65 million three-year credit facility with a group of banks with Fleet National
Bank as agent ("Fleet Agreement"). The Fleet Agreement has a sublimit for
working capital loans in the amount of $25 million, with the remainder of the
facility available for letters of credit.
23
The key terms of the Fleet Agreement are as follows:
o Letter of credit fees are based on the Applicable Usage Level
("AUL") and will range from 2.00% to 3.00%. During the first six
months of the facility, the rate will be 2.50%. The AUL is a
function of the facility usage to the borrowing base on that day.
o The interest rate on working capital borrowings is also based on the
AUL and allows for loans based on the prime rate or the LIBOR rate
at our 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 rate will be the Libor rate plus 2.50%.
o We pay a commitment fee on the unused portion of the $65 million
commitment. This commitment fee is also based on the AUL and will
range from 0.375% to 0.50%. During the first six months of the
facility, the commitment fee will be 0.50%.
o The amount that we may have outstanding cumulatively in working
capital borrowings and letters of credit is subject to a Borrowing
Base calculation. The Borrowing Base (as defined in the Fleet
Agreement) generally includes our cash balances, net accounts
receivable and inventory, less deductions for certain accounts
payable, and is calculated monthly.
o Collateral under the Fleet Agreement consists of our accounts
receivable, inventory, cash accounts, margin accounts and property
and equipment.
o The Fleet Agreement contains covenants requiring a Current Ratio (as
defined in the Fleet Agreement), a Leverage Ratio (as defined in the
Fleet Agreement), a Cash Flow Coverage Ratio (as defined in the
Fleet Agreement), a Funded Indebtedness to Capitalization Ratio (as
defined in the Fleet Agreement), Minimum EBITDA, and limitations on
distributions to Unitholders.
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) of the Fleet Agreement by
at least $10 million plus the distribution measured once each month. See
additional discussion below under "Distributions".
At March 31, 2003, we had $3.5 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 31, 2006. At March 31, 2003, we had letters of
credit outstanding under the Fleet Agreement totaling $30.0 million, comprised
of $16.1 million and $13.1 million for crude oil purchases related to March 2003
and April 2003, respectively and $0.8 million related to other business
obligations.
Any significant decrease in our financial strength, regardless of the
reason for such decrease, may increase the number of transactions requiring
letters of credit, which could restrict our gathering and marketing activities
due to the limitations of the Fleet Agreement and Borrowing Base. This situation
could in turn adversely affect our ability to maintain or increase the level of
our purchasing and marketing activities or otherwise adversely affect our
profitability and Available Cash.
Working Capital
Our balance sheet reflects negative working capital of $6.2 million.
The majority of this difference can be attributed to the accrual for the fines
and penalties that we expect to pay to state and federal regulators related to
the December 1999 Mississippi oil spill. That accrual is $3.0 million. As we
have a working capital sublimit under the Fleet Agreement of $25 million and
have only borrowed $3.5 million at March 31, 2003, we have the ability to borrow
the funds to make the necessary payments.
24
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 March 31, 2003
(in thousands).
Payments Due by Period
-----------------------------------------------------------------------
Less than 1 - 3 4 - 5 After 5
Contractual Cash Obligations Total 1 Year Years Years Years
---------------------------- ------------ ------------ ----------- ------------ ------------
Operating Leases $ 14,744 $ 4,128 $ 6,437 $ 1,884 $ 2,295
Unconditional Purchase
Obligations (1) 140,384 139,991 393 - -
------------ ------------ ----------- ------------ ------------
Total Contractual Cash
Obligations $ 155,128 $ 144,119 $ 6,830 $ 1,884 $ 2,295
============ ============ =========== ============ ============
<FN>
(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 March 31,
2003, were used to value the obligations, such that actual
obligations may differ from the amounts included above.
</FN>
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. (A full definition of Available Cash is set forth
in the Partnership Agreement.) The Partnership Agreement indicates that the
target minimum quarterly distribution ("MQD") for each quarter is $0.20 per
unit.
Under the terms of the Fleet Agreement, we cannot pay a distribution
for any quarter unless the Borrowing Base exceeds the usage under the Fleet
Agreement (working capital loans plus outstanding letters of credit) for every
day of the quarter by at least $10 million plus the total amount of the
distribution.
Available cash before reserves for the quarter ended March 31, 2003, is
as follows (in thousands):
Net income..................................... $ 879
Depreciation and amortization.................. 1,515
Cash proceeds in excess of gain from
asset sales.................................. 40
Maintenance capital expenditures............... (1,644)
-----------
Available cash before reserves................. $ 790
===========
Available cash is a non-generally accepted accounting principle
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.
On April 14, 2003, we declared a distribution of $0.05 per unit payable
May 15, 2003 to Common Unitholders and the General Partner of record at the
close of business on April 30, 2003. We expect to continue regular quarterly
distributions during 2003 of at least $0.05 per unit. Any decision to restore
the distribution to the targeted minimum quarterly distribution will take into
account our ability to sustain the distribution on an ongoing basis with cash
generated by our existing asset base, capital requirements needed to maintain
and optimize the performance of our asset base, and our ability to finance our
existing capital requirements and accretive acquisitions.
Industry Credit Market Disruptions
Over the last two years there have been an unusual number of business
failures and large financial restatements by small as well as large companies in
the energy industry. Because the energy industry is very credit intensive, these
failures and restatements have focused attention on the credit risks of
companies in the energy industry by credit rating agencies, producers and
counterparties.
25
This focus on credit has affected us in two ways - requests for credit
from producers and extension of credit to counterparties. While we have seen
some increase in requests for credit support from producers (primarily in the
first quarter of 2002), we have been relatively successful in obtaining open
credit from most producers.
Because we are an aggregator of crude oil, sales of crude oil tend to
be large volume transactions. In transacting business with our counterparties,
we must decide how much credit to extend to each counterparty, as well as the
form and amount of financial assurance to obtain from counterparties when credit
is not extended. We have modified our credit arrangements with certain
counterparties that have been adversely affected by recent financial
difficulties in the energy industry.
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 $88.7 million aggregate receivables on
our consolidated balance sheet at March 31, 2003, approximately $88.1 million,
or 99.3%, were less than 30 days past the invoice date.
Non-GAAP Financial Measure
The non-generally accepted accounting principles financial measure of
available cash is presented in this Form 10-Q.. The amount included in this
measure is 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 or sustaining capital expenditures
are defined as capital expenditures (as defined by GAAP) which do not increase
the capacity of an asset or generate additional revenues or cash flow from
operations.
We believe that investors benefit from having access to the same financial
measures being utilized by management. Available cash is a liquidity measure
used by our management to compare cash flows generated by the partnership to the
cash distribution we pay to our limited partners and the general partner. This
is an important financial measure to our public unitholders since it is an
indicator of our ability to provide a cash return on their investment.
Specifically, this financial measure tells investors whether or not the
partnership is generating cash flows at a level that can support a quarterly
cash distribution to our partners. Lastly, available cash (also referred to as
distributable cash flow) is the quantitative standard used throughout the
investment community with respect to publicly-traded partnerships.
Several adjustments to net income are required to calculate available
cash. These adjustments include: (1) the addition of non-cash expenses such as
depreciation and amortization expense; (2) miscellaneous non-cash adjustments
such as the addition of decreases or the subtraction of increases in the value
of financial instruments; and (3) the subtraction of maintenance capital
expenditures.
The reconciliation of available cash (a non-GAAP liquidity measure) to
cash flow from operating activities for the quarter ended March 31, 2003, is as
follows (in thousands):
Cash flows from operating activities................. $ 6,056
Adjustments to reconcile operating activities
cash flows to available cash:
Maintenance capital expenditures................ (1,644)
Proceeds from asset sales....................... 84
Change in fair value of derivatives............. (39)
Amortization of credit facility issuance fees... (750)
Net effect of changes in operating accounts not
included in calculation of available cash..... (2,917)
-----------
Available cash before reserves....................... $ 790
===========
26
Other Matters
Crude Oil Contamination
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.
We believe that the suit is without merit and intend to vigorously defend
ourselves in this matter. We believe 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. We believe that the demand against Genesis is without merit
and intend to vigorously defend ourselves in this matter. We believe that any
potential liability will substantially be covered by insurance.
Insurance
We maintain insurance of various types that we consider adequate to
cover our operations and properties. The insurance policies are subject to
deductibles that we consider reasonable. The policies do not cover every
potential risk associated with operating our assets, including the potential for
a loss of significant revenues. Consistent with the coverage available in the
industry, our policies provide limited pollution coverage, with broader coverage
for sudden and accidental pollution events. Additionally, as a result of the
events of September 11, the cost of insurance available to the industry has
risen significantly, and insurers have excluded or reduced coverage for losses
due to acts of terrorism and sabotage.
Since September 11, 2001, warnings have been issued by various agencies
of the United States Government to advise owners and operators of energy assets
that those assets may be a future target of terrorist organizations. Any future
terrorist attacks on our assets, or assets of our customers or competitors could
have a material adverse affect on our business.
We believe that we are adequately insured for public liability and
property damage to others as a result of our operations. However, no assurances
can be given that an event not fully insured or indemnified against will not
materially and adversely affect our operations and financial condition.
Additionally, no assurance can be given that we will be able to maintain
insurance in the future at rates that we consider reasonable.
New Accounting Pronouncements
SFAS 143
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." 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 it is incurred.
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. The standard was effective for Genesis on
January 1, 2003.
27
With respect to our pipelines, federal regulations will require us to
purge the crude oil from our pipelines when the pipelines are retired. Our right
of way agreements do not require us to remove pipe or otherwise perform
remediation upon taking the pipelines out of service. Many of our truck unload
stations are on leased sites that require that we remove our improvements upon
expiration of the lease term. For our pipelines, we are unable to reasonably
estimate and record liabilities for the majority of our obligations that fall
under the provisions of this statement because we 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 we cannot reasonably
estimate when such notice would be given and when the obligations to remove our
improvements would be settled. We will record asset retirement obligations in
the period in which we determine the settlement dates.
SFAS 146
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities," which addresses accounting for
restructuring and similar costs. SFAS No. 146 supersedes previous accounting
guidance, principally EITF Issue No. 94-3. We will adopt the provisions of SFAS
No. 146 for restructuring activities initiated after December 31, 2002. SFAS No.
146 requires that the liability for costs associated with an exit or disposal
activity be recognized when the liability is incurred. Under Issue No. 94-3, a
liability for an exit cost was recognized at the date of commitment to an exit
plan. SFAS No. 146 also establishes that the liability should initially be
measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the
timing of recognizing future restructuring costs as well as the amounts
recognized. The impact that SFAS No. 146 will have on our consolidated financial
statements will depend on the circumstances of any specific exit or disposal
activity.
Interpretation No. 45
In November 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others". This interpretation of SFAS No. 5, 57 and
107, and rescission of FASB Interpretation No. 34 elaborates on the disclosures
to be made by a guarantor in its interim and annual financial statements about
its obligations under certain guarantees that it has issued. It also clarifies
that a guarantor is required to recognize, at the inception of a guarantee, a
liability for the fair value of the obligation undertaken in issuing the
guarantee. The initial recognition and initial measurement provisions of this
interpretation are applicable on a prospective basis to guarantees issued or
modified after December 31, 2002. The disclosure requirements in this
interpretation are effective for financial statements of interim or annual
periods after December 15, 2002.
SFAS 148
In December 2002, the FASB issued SFAS No. 148, "Accounting for
Stock-Based Compensation-Transition and Disclosure," which provides alternative
methods of transition from a voluntary change to the fair value based method of
accounting for stock-based employee compensation. In addition, SFAS No. 148
amends the disclosure requirements of SFAS No. 123 in both annual and interim
financial statements. SFAS No. 148 is effective for financial statements for
fiscal years ending after December 15, 2002, and financial reports containing
condensed financial statements for interim periods beginning after December 15,
2002. At this time, there are no outstanding grants of Partnership units under
our Restricted Unit Plan (see Note 15). Therefore, the adoption of this
statement had no effect on our financial position, results of operations, cash
flows or disclosure requirements.
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:
28
o changes in regulations;
o our success in obtaining additional lease barrels;
o changes in crude oil production volumes (both world-wide and in
areas in which we have operations);
o developments relating to possible acquisitions, dispositions or
business combination opportunities;
o volatility of crude oil prices, P-Plus and grade differentials;
o the success of the risk management activities;
o credit requirements by our counterparties;
o the cost of obtaining 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 the IMP and any rehabilitation required
as a result of that testing;
o estimated timing and amount of future capital expenditures;
o our success in increasing tariff rates on our common carrier
pipelines;
o results of current or threatened litigation; and
o conditions of capital markets and equity markets during the
periods covered by the forward looking statements.
All subsequent written or oral forward looking statements attributable
to us, or persons acting our behalf, are expressly qualified in their entirety
by the foregoing cautionary statements.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
Price Risk Management and Financial Instruments
The Partnership's primary price risk relates to the effect of crude oil
price fluctuations on its inventories and the fluctuations each month in grade
and location differentials and their effects on future contractual commitments.
Historically, the Partnership has utilized New York Mercantile Exchange
("NYMEX") commodity based futures contracts, forward contracts, swap agreements
and option contracts to hedge its exposure to market price fluctuations,
however, at March 31, 2003, no contracts were outstanding. Information about
inventory at March 31, 2003, is contained in the table set forth below.
Crude Oil Inventory
Volume (1,000 bbls)............................... 45
Carrying value (in thousands)..................... $ 1,275
Fair value (in thousands)......................... $ 1,376
Fair values were determined by using the notional amount in barrels
multiplied by published market closing prices for the applicable crude oil type
at March 31, 2003.
29
Item 4. Controls and Procedures
The Partnership has evaluated the effectiveness of the design and
operation of its disclosure controls and procedures as of a date within 90 days
prior to the filing of this quarterly report on Form 10-Q (the "Evaluation
Date"). 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, as of the Evaluation Date, the Partnership's disclosure
controls and procedures were effective. There have been no significant changes
in the Partnership's internal controls or other factors that could significantly
affect these controls subsequent to the date of their most recent evaluation.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
See Part I. Item 1. Note 10 to the Condensed Consolidated Financial
Statements entitled "Contingencies", which is incorporated herein by reference.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits.
Exhibit 99.1 Certification by Chief Executive Officer Pursuant to 18
U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
Exhibit 99.2 Certification by Chief Financial Officer Pursuant to 18
U.S.C. Section 1350, as Adopted 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 March 7, 2003, to file the press
release of the Partnership's earnings for the year ended December 31, 2002.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
GENESIS ENERGY, L.P.
(A Delaware Limited Partnership)
By: GENESIS ENERGY, INC., as
General Partner
Date: May 12, 2003 By: /s/ ROSS A. BENAVIDES
------------------------------
Ross A. Benavides
Chief Financial Officer
30
CERTIFICATIONS PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
CERTIFICATION
I, Mark J. Gorman, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Genesis Energy,
L.P.;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: May 12, 2003
/s/ Mark J. Gorman
-----------------------------------
Mark J. Gorman
President & Chief Executive Officer
31
CERTIFICATION
I, Ross A. Benavides, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Genesis Energy,
L.P.;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: May 12, 2003
/s/ Ross A. Benavides
-----------------------
Ross A. Benavides
Chief Financial Officer