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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-Q
[X] QUARTERLY REPORT UNDER SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-12295
GENESIS ENERGY, L.P.
(Exact name of registrant as specified in its charter)
Delaware 76-0513049
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
500 Dallas, Suite 2500, Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
(713) 860-2500
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes X No
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This report contains 23 pages
2
GENESIS ENERGY, L.P.
Form 10-Q
INDEX
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements Page
----
Consolidated Balance Sheets - June 30, 2002 and
December 31, 2001 3
Consolidated Statements of Operations for the Three and
Six Months Ended June 30, 2002 and 2001 4
Consolidated Statements of Cash Flows for the Six Months
Ended June 30, 2002 and 2001 5
Consolidated Statement of Partners' Capital for the Six
Months Ended June 30, 2002 6
Notes to Consolidated Financial Statements 7
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations 13
Item 3. Quantitative and Qualitative Disclosures about Market Risk 22
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 22
Item 6. Exhibits and Reports on Form 8-K 23
3
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
June 30, December 31,
2002 2001
-------- --------
ASSETS (Unaudited)
CURRENT ASSETS
Cash and cash equivalents $ 5,934 $ 5,777
Accounts receivable:
Trade 72,508 160,734
Related party - 1,064
Inventories 61 3,737
Other 5,015 10,788
-------- --------
Total current assets 83,518 182,100
FIXED ASSETS, at cost 115,313 115,336
Less: Accumulated depreciation (71,979) (69,626)
-------- --------
Net fixed assets 43,334 45,710
OTHER ASSETS, net of amortization 675 2,303
-------- --------
TOTAL ASSETS $127,527 $230,113
======== ========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable -
Trade $ 77,428 $172,848
Related party 2,866 697
Accrued liabilities 9,789 10,144
-------- --------
Total current liabilities 90,083 183,689
LONG-TERM DEBT 1,500 13,900
COMMITMENTS AND CONTINGENCIES (Note 10)
MINORITY INTERESTS 515 515
PARTNERS' CAPITAL
Common unitholders, 8,625 units issued and
outstanding 34,712 31,361
General partner 717 648
-------- --------
Total partners' capital 35,429 32,009
-------- --------
TOTAL LIABILITIES AND PARTNERS' CAPITAL $127,527 $230,113
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
4
GENESIS ENERGY, L.P.
STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2002 2001 2002 2001
-------- -------- -------- ----------
REVENUES:
Gathering and marketing revenues
Unrelated parties $235,890 $917,192 $467,781 $1,817,885
Related parties - - 3,036 25,900
Pipeline revenues 4,879 3,687 9,191 7,387
-------- -------- -------- ----------
Total revenues 240,769 920,879 480,008 1,851,172
COST OF SALES:
Crude costs, unrelated parties 223,892 908,575 450,709 1,799,093
Crude costs, related parties 4,385 - 4,385 28,700
Field operating costs 4,014 3,890 8,004 7,963
Pipeline operating costs 2,256 2,623 5,250 5,000
-------- -------- -------- ----------
Total cost of sales 234,547 915,088 468,348 1,840,756
-------- -------- -------- ----------
GROSS MARGIN 6,222 5,791 11,660 10,416
EXPENSES:
General and administrative 2,204 2,999 4,292 5,726
Depreciation and amortization 1,475 1,870 2,898 3,767
-------- -------- -------- ----------
OPERATING INCOME 2,543 922 4,470 923
OTHER INCOME (EXPENSE):
Interest income 10 48 15 119
Interest expense (278) (167) (683) (373)
Change in fair value of derivatives (355) 1,679 (1,057) 5,088
Gain on asset disposals 186 19 675 148
-------- -------- -------- ----------
Income before minority interest and
cumulative effect of change in
accounting principle 2,106 2,501 3,420 5,905
Minority interest - 1 - 1
-------- -------- -------- ----------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE 2,106 2,500 3,420 5,904
Cumulative effect of adoption of
accounting principle, net of minority
interest effect - - - 467
-------- -------- -------- ----------
NET INCOME $ 2,106 $ 2,500 $ 3,420 $ 6,371
======== ======== ======== ==========
NET INCOME PER COMMON UNIT - BASIC AND DILUTED:
Income before cumulative effect of
change in accounting principle $ 0.24 $ 0.28 $ 0.39 $ 0.67
======== ======== ======== ==========
Cumulative effect of change in
accounting principle, net of minority
interest effect $ - $ - $ - $ 0.05
======== ======== ======== ==========
Net Income $ 0.24 $ 0.28 $ 0.39 $ 0.72
======== ======== ======== ==========
WEIGHTED AVERAGE NUMBER OF COMMON UNITS
OUTSTANDING 8,625 8,624 8,625 8,624
======== ======== ======== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
5
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
Six Months Ended
June 30,
2002 2001
-------- -------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 3,420 $ 6,371
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation 2,474 3,108
Amortization of intangible assets 424 659
Cumulative effect of adoption of accounting principle - (467)
Change in fair value of derivatives 1,057 (5,088)
Minority interest's equity in earnings - 1
Gain on asset disposals (675) (148)
Other noncash charges 810 30
Changes in components of working capital -
Accounts receivable 89,290 3,416
Inventories 3,676 879
Other current assets 5,773 (1,140)
Accounts payable (93,251) 2,060
Accrued liabilities (1,412) 7,351
-------- -------
Net cash provided by operating activities 11,586 17,032
-------- -------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (1,212) (351)
Change in other assets 1 (3)
Proceeds from sales of assets 2,182 433
-------- -------
Net cash provided by investing activities 971 79
-------- -------
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of debt (12,400) (1,000)
Distributions to common unitholders - (3,449)
Distributions to general partner - (70)
-------- -------
Net cash used in financing activities (12,400) (4,519)
-------- -------
Net increase in cash and cash equivalents 157 12,592
Cash and cash equivalents at beginning of period 5,777 5,508
-------- -------
Cash and cash equivalents at end of period $ 5,934 $18,100
======== =======
The accompanying notes are an integral part of these consolidated
financial statements.
6
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
(In thousands)
(Unaudited)
Partners' Capital
---------------------------------
Common General
Unitholders Partner Total
----------- ------- -------
Partners' capital at December 31, 2001 $ 31,361 $ 648 $32,009
Net income for the six months ended
June 30, 2002 3,351 69 3,420
----------- ------- -------
Partners' capital at June 30, 2002 $ 34,712 $ 717 $35,429
=========== ======= =======
The accompanying notes are an integral part of these consolidated
financial statements.
7
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Formation and Offering
Genesis Energy, L.P. ("GELP" or the "Partnership") was formed in December
1996 as an initial public offering of 8.6 million Common Units, representing
limited partner interests in GELP of 98%. The general partner of GELP is
Genesis Energy, Inc. (the "General Partner") which owns a 2% general partner
interest in GELP. The General Partner is owned by Denbury Gathering &
Marketing, Inc., a wholly-owned subsidiary of Denbury Resources Inc.,
("Denbury"). Denbury acquired the General Partner from Salomon Smith Barney
Holdings Inc. ("Salomon") and Salomon Brothers Holding Company Inc. on May 14,
2002. On May 15, 2002, Denbury converted Genesis Energy, L.L.C., a limited
liability company, into Genesis Energy, Inc., a Delaware corporation.
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 consolidated financial statements and related notes present
the financial position as of June 30, 2002 and December 31, 2001 for GELP, the
results of operations for the three and six months ended June 30, 2002 and
2001, cash flows for the six months ended June 30, 2002 and 2001 and changes
in partners' capital for the six months ended June 30, 2002.
The financial statements included herein have been prepared by the
Partnership without audit pursuant to the rules and regulations of the
Securities and Exchange Commission ("SEC"). Accordingly, they reflect all
adjustments (which consist solely of normal recurring adjustments) which are,
in the opinion of management, necessary for a fair presentation of the
financial results for interim periods. Certain information and notes normally
included in financial statements prepared in accordance with generally
accepted accounting principles have been condensed or omitted pursuant to such
rules and regulations. However, the Partnership believes that the disclosures
are adequate to make the information presented not misleading. These
financial statements should be read in conjunction with the financial
statements and notes thereto included in the Partnership's Annual Report on
Form 10-K for the year ended December 31, 2001 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 June 30, 2002 and 2001 was
8,625,000 and 8,624,000, respectively. For the 2002 and 2001 six month
periods, the weighted average number of Common Units outstanding was 8,625,000
and 8,624,000, respectively. For this purpose, the 2% General Partner
interest is excluded from net income. Diluted net income per Common Unit did
not differ from basic net income per Common Unit for any period presented.
3. New Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("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 is
effective for fiscal years beginning after June 15, 2002, with earlier
application encouraged. The Partnership is currently evaluating the effect on
its financial statements of adopting SFAS No. 143 and plans to adopt the
statement effective January 1, 2003.
SFAS No. 142, "Goodwill and Other Intangible Assets", and SFAS No. 144,
"Accounting for Impairment on Disposal of Long-Lived Assets", were adopted by
the Partnership effective January 1, 2002. These statements had no effect on
the consolidated financial statements of the Partnership.
In April 2002 the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." SFAS No. 145 rescinds SFAS No. 4, "Reporting Gains and Losses
from Extinguishment of Debt" and an amendment of that statement, SFAS No. 64,
"Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements." SFAS No.
145 also rescinds SFAS No. 44, "Accounting for Intangible Assets of Motor
Carriers." SFAS No. 145 also amends SFAS No. 13, "Accounting for Leases," to
eliminate an inconsistency between the required accounting for sale-leaseback
transactions and the required accounting for certain lease modifications that
have economic effects that are similar to sale-leaseback transactions. SFAS
No. 145 also amends other existing authoritative pronouncements to make
various technical corrections, clarify meanings, or describe their
applicability under changed conditions. The provisions related to the
rescission of SFAS No. 4 shall be applied in fiscal years beginning after May
15, 2002. The provisions related to SFAS No. 13 shall be effective for
transactions occurring after May 15, 2002. All other provisions shall be
effective for financial statements issued on or after May 15, 2002, with early
application encouraged. The Partnership does not believe that SFAS No. 145
will have a material effect on its results of operations.
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 Partnership
has not completed its analysis of the impact that SFAS No. 146 will have on
its consolidated financial statements.
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. ExxonMobil Corporation and Marathon Ashland
Petroleum LLC accounted for 15% and 15%, respectively, of revenues in the
first six months of 2002. No customer accounted for more than 10% of the
Partnership's revenues in the same period in 2001.
5. Inventory Reduction
As a result of a change in the Partnership's operations to focus on its
gathering activities, and due to changes made in its gathering business as a
result of changes in its credit facilities, the Partnership determined that
the volume of crude oil needed to ensure efficient and uninterrupted operation
of its gathering business should be reduced. These crude oil volumes had been
carried at their weighted average cost and classified as fixed assets. In the
first six months of 2002, the Partnership realized additional gross margin of
approximately $337,000 as a result of the sale of these volumes.
6. Credit Resources and Liquidity
In 2001, Genesis had a $300 million Master Credit Support Agreement
("Guaranty Facility") with Salomon and a $25 million working capital facility
("WC Facility") with BNP Paribas.
Effective December 19, 2001, GCOLP entered into a two-year $130 million
Senior Secured Revolving Credit Facility ("Credit Agreement") with Citicorp
North America, Inc. ("Citicorp"). Citicorp and Salomon, the former owner of
the Partnership's General Partner, are both wholly-owned subsidiaries of
Citigroup Inc. The Credit Agreement replaced the Guaranty Facility and the WC
Facility.
In May 2002, the Partnership elected, under the terms of the Credit
Agreement, to amend the Credit Agreement to reduce the maximum facility amount
to $80 million. The Credit Agreement has a $25 million sublimit for working
capital loans. Any amount not being used for working capital loans is
available for letters of credit to support crude oil purchases.
During the first four months of 2002, Salomon continued to provide
guaranties to the Partnership's counterparties under a transition arrangement
between Salomon, Citicorp and the Partnership. For crude oil purchases in
January 2002 through April 2002, a maximum of $100 million, respectively, in
guaranties were available to be issued under the Salomon guaranty facility.
Beginning with May 2002, Citicorp provided letters of credit to the
Partnership's counterparties.
The key terms of the amended Credit Agreement are as follows:
* Letter of credit fees are based on the Applicable Leverage Level
("ALL") and will range from 1.50% to 2.75%. At June 30, 2002, the rate
was 2.25%. The ALL is a function of GCOLP's average daily debt to its
earnings before interest, depreciation and amortization for the four
preceding quarters.
* The interest rate on working capital borrowings is also based on the
ALL and allows for loans based on the prime rate or the LIBOR rate at
the Partnership's option. The interest rate on prime rate loans can
range from the prime rate to the prime rate plus 1.25%. The interest
rate for LIBOR-based loans can range from the LIBOR rate plus 1.50% to
the LIBOR rate plus 2.75%. At June 30, 2002, the interest rate on the
Partnership's borrowings was 4.75%.
* The Partnership will pay a commitment fee on the unused portion of the
$80 million commitment. This commitment fee is also based on the ALL
and will range from 0.375% to 0.50%. At June 30, 2002, the commitment
fee was 0.375%.
* The amount that the Partnership 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
Credit Agreement) generally includes the Partnership's cash balances,
net accounts receivable and inventory, less deductions for certain
accounts payable, and is calculated monthly.
* Collateral under the Credit Agreement consists of all of the
Partnership's accounts receivable, inventory, cash accounts, margin
accounts and property and equipment.
* The Credit Agreement contains covenants requiring a Current Ratio (as
defined in the Credit Agreement), a Leverage Ratio (as defined in the
Credit Agreement), an Interest Coverage Ratio (as defined in the
Credit Agreement) and limitations on distributions to Unitholders.
The terms above reflect the terms in the amended Credit Agreement. That
amendment also provides that, should the Credit Agreement not be syndicated to
reduce Citicorp's participation to $20 million by September 30, 2002, the
interest rates, commitment fee rates and letter of credit fees will revert to
those in the original Credit Agreement executed on December 19, 2001. The
maximum rates in that agreement were 4.50% for letter of credit fees, LIBOR
plus 4.50% for LIBOR-based loans, the prime rate plus 1.25% for prime rate
loans and 0.75% for commitment fees.
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 Credit Agreement for every day of the quarter by
at least $20 million. The Partnership did not meet this test in the first two
quarters of 2002; therefore, no distributions have been or will be paid for
those quarters. See additional discussion below under "Distributions".
At June 30, 2002, the Partnership had $1.5 million of loans outstanding
under the Credit Agreement. The outstanding loan balance is to be repaid by
December 31, 2003; however, due to the revolving nature of the loans,
additional borrowings and periodic repayments and re-borrowings may be made
until that date. At June 30, 2002, the Partnership had letters of credit
outstanding of $14.1 million and $13.4 million under the Credit Agreement
related to June 2002 and July 2002, respectively, for crude oil purchases.
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. As a result
of the restructuring approved by Unitholders in December 2000, the target
minimum quarterly distribution ("MQD") for each quarter was reduced to $0.20
per unit. The Partnership has not made distributions since the fourth quarter
of 2001 due to covenants in the Credit Agreement.
Under the terms of the Credit Agreement, the Partnership may not pay a
distribution for any quarter unless the Borrowing Base exceeded the usage
under the Credit Agreement (working capital loans plus outstanding letters of
credit) for every day of the quarter by at least $20 million. For the first
and second quarters of 2002, the Partnership did not and will not pay a
distribution as the excess of the Borrowing Base over the usage did not exceed
$20 million for every day in the quarter. It is unclear when the Partnership
will meet the distribution test in the Citicorp Credit Facility or when
distributions will resume. Should distributions resume, the distribution per
common unit may be less than $0.20 per unit.
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, in the
opinion of management, are conducted under terms no more or less favorable
than those conducted with unaffiliated parties. Salomon was a related party
during 2001 and through May 14, 2002. Denbury became a related party on May
14, 2002, when it acquired the General Partner. The amounts below include
transactions during the periods when Salomon and Denbury were related parties.
Sales and Purchases of Crude Oil
A summary of sales to and purchases from related parties of crude oil is
as follows (in thousands).
Six Months Six Months
Ended Ended
June 30, June 30,
2002 2001
------ -------
Sales to Salomon affiliates $3,036 $25,900
Purchases from Salomon affiliates $ - $28,700
Purchases from Denbury affiliates $4,385
Purchases from Denbury are secured by letters of credit.
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 $8,970,000 and $9,422,000 for the six months ended June 30,
2002 and 2001, respectively.
Credit Facilities
As discussed in Note 6, Citicorp provides a Credit Agreement to the
Partnership. During the first four months of 2002, Salomon provided
guaranties under a transition arrangement. For the six months ended June 30,
2002 and 2001, the Partnership incurred $61,000 and $423,000, respectively,
for guarantee fees under the Guaranty Facility. From January 1, 2002, until
May 14, 2002, when Citicorp ceased to be a related party, the Partnership
incurred letter of credit fees, interest and commitment fees totaling $396,000
under the Credit Agreement.
8. Supplemental Cash Flow Information
Cash received by the Partnership for interest was $15,000 and $140,000 for
the six months ended June 30, 2002 and 2001, respectively. Payments of
interest were $338,000 and $283,000 for the six months ended June 30, 2002 and
2001, respectively.
9. Derivatives
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" (as amended and
interpreted), 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. Special accounting for qualifying hedges allows a derivative's gains
and losses to offset related results on the hedged item in the income
statement. Companies must formally document, designate and assess the
effectiveness of transactions that receive hedge accounting.
Under SFAS No. 133, the Partnership marks to fair value all of its
derivative instruments at each period end with changes in fair value 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. The initial adoption of
SFAS No. 133 required that the difference between the fair value of derivative
instruments and the previous carrying amount of those derivatives be recorded
in net income or other comprehensive income, as appropriate, as the cumulative
effect of a change in accounting principle.
On January 1, 2001, the Partnership recorded a cumulative gain for the
effect of the adoption of SFAS No. 133, net of minority interest of $0.5
million.
The fair value of the Partnership's net asset for derivatives had decreased
by $1.1 million for the six months ended June 30, 2002, which is reported as a
loss in the consolidated statement of operations under the caption "Change in
fair value of derivatives." The consolidated balance sheet includes $1.5
million in other current assets and $0.5 million in accrued liabilities as a
result of recording the fair value of derivatives. In 2002 and 2001, the
Partnership did not designate any of its derivatives as hedging instruments
under SFAS No. 133.
10. Contingencies
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. Management of the
General Partner believes that the complaint is without merit and intends to
vigorously defend the action.
Pennzoil Lawsuit
The Partnership has been named one of the defendants in a complaint filed
by Thomas Richard Brown on January 11, 2001, in the 125th District Court of
Harris County, cause No. 2001-01176. Mr. Brown, an employee of Pennzoil-
Quaker State Company ("PQS"), seeks damages for burns and other injuries
suffered as a result of a fire and explosion that occurred at the Pennzoil
Quaker State refinery in Shreveport, Louisiana, on January 18, 2000. On
January 17, 2001, PQS filed a Plea in Intervention in the cause filed by Mr.
Brown. PQS seeks property damages, loss of use and business interruption.
Both plaintiffs claim the fire and explosion was caused, in part, by Genesis
selling to PQS crude oil that was contaminated with organic chlorides.
Management of the Partnership believes that the suit is without merit and
intends to vigorously defend itself in this matter. Management of the
Partnership believes that any potential liability will be covered by
insurance.
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
primarily as a result of the spill from the Mississippi System, an accrual of
$1.5 million was recorded for the year ended December 31, 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
consolidated financial position, results of operations or cash flows of the
Partnership.
11. Subsequent Event
On July 31, 2002, Genesis Energy, Inc. ("Genesis") amended Section 11.2 of
the Second Amended and Restated Agreement of Limited Partnership of Genesis
Energy, L.P. ("the Partnership Agreement") to broaden the right of the Common
Unitholders to remove the general partner of Genesis Energy, L.P. ("GELP").
Prior to this amendment, the general partner could only be removed for cause
and with approval by holders of two-thirds or more of the outstanding limited
partner interests in GELP. As amended, the Partnership Agreement provides
that, with the approval of at least a majority of the limited partners in
GELP, the general partner also may be removed without cause. Any limited
partner interests held by the general partner and its affiliates are to be
excluded from such a vote.
The amendment further provides that if it is proposed that the removal is
without cause and an affiliate of Denbury is the general partner to be removed
and not proposed as a successor, then any action for removal must also provide
for Denbury to be granted an option effective upon its removal to purchase
GELP's Mississippi pipeline system at a price that is 110 percent of its fair
market value at that time. Fair value is to be determined by agreement of two
independent appraisers, one chosen by the successor general partner and the
other by Denbury or if they are unable to agree, the mid-point of the values
determined by them.
The amendment was negotiated on behalf of GELP by the audit committee of the
board of directors of Genesis. Upon determination of its fairness, including
obtaining an opinion from the investment banking firm of the GulfStar Group as
to the amendment's fairness to the Common Unitholders of GELP and an opinion
from Delaware legal counsel as to the form of the amendment, the audit
committee recommended approval of the amendment to the board of directors of
Genesis.
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Genesis Energy, L.P., operates crude oil common carrier pipelines and is an
independent gatherer and marketer of crude oil in North America, with
operations concentrated in Texas, Louisiana, Alabama, Florida and Mississippi.
The following review of the results of operations and financial condition
should be read in conjunction with the Consolidated Financial Statements and
Notes thereto.
Results of Operations
Selected financial data for this discussion of the results of operations
follows, in thousands, except barrels per day.
Three Months Ended Six Months Ended
June 30, June 30,
2002 2001 2002 2001
------- -------- ------- --------
Gross margin
Gathering and marketing $ 3,599 $ 4,727 $ 7,719 $ 8,029
Pipeline $ 2,623 $ 1,064 $ 3,941 $ 2,387
General and administrative expenses $ 2,204 $ 2,999 $ 4,292 $ 5,726
Depreciation and amortization $ 1,475 $ 1,870 $ 2,898 $ 3,767
Operating income (loss) $ 2,543 $ 922 $ 4,470 $ 923
Interest income (expense), net $ (268) $ (119) $ (668) $ (254)
Change in fair value of derivative $ (355) $ 1,679 $(1,057) $ 5,088
Gain on asset disposals $ 186 $ 19 $ 675 $ 148
Barrels per day
Wellhead 65,497 83,916 66,476 88,480
Bulk and exchange 38,338 293,589 52,647 281,085
Pipeline 75,576 87,114 75,493 88,280
The profitability of Genesis depends to a significant extent upon its
ability to maximize gross margin. Gross margins from gathering and marketing
operations are a function of volumes purchased and the difference between the
price of crude oil at the point of purchase and the price of crude oil at the
point of sale, minus the associated costs of aggregation and transportation.
The absolute price levels for crude oil do not necessarily bear a relationship
to gross margin as absolute price levels normally impact revenues and cost of
sales by equivalent amounts. Because period-to-period variations in revenues
and cost of sales are not generally meaningful in analyzing the variation in
gross margin for gathering and marketing operations, such changes are not
addressed in the following discussion.
In our gathering and marketing business, Genesis seeks to purchase and sell
crude oil at points along the Distribution Chain where we can achieve positive
gross margins. Genesis generally purchases crude oil at prevailing prices
from producers at the wellhead under short-term contracts. Genesis then
transports the crude along the Distribution Chain for sale to or exchange with
customers. Additionally, Genesis enters into exchange transactions with third
parties. Genesis generally enters 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, Genesis often exchanges
one grade of crude oil for another to maximize margins or meet contract
delivery requirements. Prior to the first quarter of 2002, Genesis purchased
crude oil in bulk at major pipeline terminal points. These bulk and exchange
transactions are characterized by large volumes and narrow profit margins on
purchases and sales.
Generally, as Genesis purchases crude oil, it simultaneously establishes a
margin by selling crude oil for physical delivery to third party users, such
as independent refiners or major oil companies. Through these transactions,
Genesis seeks 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 the policy of Genesis 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 margins are primarily a function of the level of
throughput and storage activity and are generated by the difference between
the regulated published tariff and the fixed and variable costs of operating
the pipeline. Changes in revenues, volumes and pipeline operating costs,
therefore, are relevant to the analysis of financial results of Genesis'
pipeline operations and are addressed in the following discussion of pipeline
operations of Genesis.
Six Months Ended June 30, 2002 Compared with Six Months Ended June 30, 2001
Gross margin from gathering and marketing operations was $7.7 million for
the six months ended June 30, 2002, as compared to $8.0 million for the six
months ended June 30, 2001.
The factors affecting gross margin were:
* a decrease of 68 percent in wellhead, bulk and exchange purchase
volumes between 2001 and 2002, resulting in a decrease in gross margin
of $11.4 million;
* an increase in gross margin of $10.2 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;
* a $0.3 million increase in gross margin in the 2002 period as a result
of the sale of crude oil that is no longer needed to ensure efficient
and uninterrupted operations; and
* a decrease of $0.6 million in credit costs due primarily to the
reduction in bulk and exchange transactions.
Pipeline gross margin was $3.9 million for the six months ended June 30,
2002, as compared to $2.4 million for the six months in 2001. The factors
affecting pipeline gross margin were:
* an increase in revenues from sales of pipeline loss allowance barrels
of $1.1 million primarily as a result of higher crude prices;
* an increase of 29 percent in the average tariff on shipments
resulting in an increase in revenue of $1.6 million;
* a decrease in throughput of 14% between the two periods, resulting in
a revenue decrease of $1.0 million; and
* an increase in pipeline operating costs of $0.2 million in the 2002
period primarily due to increased insurance costs of $0.1 million and
increases in contract service costs totaling $0.3 million, offset by
reduced power costs of $0.2 million due to electricity deregulation
in Texas.
General and administrative expenses decreased $1.4 million between the
2002 and 2001 six month periods. This decrease is primarily attributable to
the elimination of personnel and costs involved in bulk and exchange
activities totaling $0.8 million, and a change to the Partnership's bonus
program to eliminate bonuses unless distributions are being paid which
resulted in no accrual in the 2002 period. An accrual of $0.6 million was
recorded for bonus expense in the 2001 period.
Depreciation and amortization expense declined $0.9 million between the
six month periods. As a result of the impairment of the pipeline assets in
2001, the value to be depreciated was reduced.
Interest expense increased $0.4 million due to an increase in commitment
fees. In 2001, the Partnership paid commitment fees on the unused portion of
its $25 million facility with BNP Paribas. In the 2002 period, the
Partnership paid commitment fees on the unused portion of the Credit Agreement
with Citicorp. From January 1, 2002, until May 3, 2002, that facility maximum
was $130 million. At May 3, 2002, the Credit Agreement was reduced to a
maximum of $80 million.
The fair value of the Partnership's net asset for derivatives had decreased
by $1.1 million for the six months ended June 30, 2002. The fair value of
derivative contracts at June 30, 2002, was determined using the sources for
fair value as shown in the table below (in thousands).
Fair Value of Contracts at Period-End
--------------------------------------------
Maturity Maturit Maturity in
less than 3-6 Excess of Total
Source of Fair Value 3 Months Months 6 Months Fair Value
-------------------- -------- -------- ---------- ---------
Prices actively quoted $ 950 $ - $ - $ 950
Prices provided by other
external sources - - - -
Prices based on models and
other valuation methods 87 - - 87
-------- -------- ---------- ---------
Total $ 1,037 $ - $ - $ 1,037
======== ======== ========== =========
The consolidated balance sheet includes $1.5 million in other current assets
and $0.5 million in accrued liabilities as a result of recording the fair
value of derivatives. The Partnership has not designated any of its
derivatives as hedging instruments.
The gain on asset disposals in the 2002 period resulted primarily from
the sale of the Partnership's memberships in the New York Mercantile Exchange
("NYMEX") and the sale of excess land and a building. The gain on asset
disposals in the 2001 period included a gain of $0.1 million as a result of
the sale of excess tractors.
Three Months Ended June 30, 2002 Compared with Three Months Ended June 30,
2001
Gross margin from gathering and marketing operations was $3.6 million for
the quarter ended June 30, 2002, as compared to $4.7 million for the quarter
ended June 30, 2001.
The factors affecting gross margin were:
* a decrease of 72 percent in wellhead, bulk and exchange purchase
volumes between 2001 and 2002, resulting in a decrease in gross
margin of $6.5 million;
* a increase in gross margin of $5.3 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;
* a decrease of $0.2 million in credit costs due primarily to the
reduction in bulk and exchange transactions; and
* an increase of $0.1 million in field costs due to increased personnel
costs.
Pipeline gross margin was $2.6 million for the quarter ended June 30,
2002, as compared to $1.1 million for the second quarter of 2001. The factors
affecting pipeline gross margin were:
* a decrease in throughput of 13 percent between the two periods,
resulting in a revenue decrease of $0.4 million;
* an increase in revenues from sales of pipeline loss allowance barrels
of $0.1 million primarily as a result of higher crude prices;
* an increase of 54 percent in the average tariff on shipments
resulting in an increase of $1.5 million in revenue; and
* a decrease in pipeline operating costs of $0.3 million in the 2002
period primarily due to reduced power costs of $0.1 million due to
electricity deregulation in Texas, decreased maintenance and repair
costs totaling $0.2 million, decreases in other operating costs
totaling $0.1 million, offset by an increase in insurance costs of
approximately $0.1 million.
General and administrative expenses decreased $0.8 million during the
three months ended June 30, 2002 as compared to the same period in 2001. The
primary factors in this decrease were the elimination of personnel and costs
involved in bulk and exchange activities and the change to the Partnership's
bonus program.
Interest costs were $0.1 million higher in the 2002 quarter due primarily
to the increased commitment under credit facilities for which commitment fees
were owed.
Liquidity and Capital Resources
Cash Flows
Cash flows provided by operating activities were $11.6 million for the
six months ended June 30, 2002. In the 2001 six-month period, cash flows
provided by operating activities were $17.0 million. The change between the
two periods is primarily due to the timing of payment for NYMEX transactions
and related margin calls in 2001.
For the six months ended June 30, 2002 and 2001, cash flows provided by
investing activities were $1.0 million and $0.1 million, respectively. In
2002, the Partnership received cash totaling $2.2 million from the sale of the
NYMEX seats and a surplus building and land. The Partnership expended $1.2
million for property additions, primarily on its pipeline systems. In 2001,
the Partnership received $0.4 million from the sale of surplus assets, most of
which was used for property and equipment additions related primarily to
pipeline operations.
Cash flows used in financing activities by the Partnership during the
first six months of 2002 totaled $12.4 million. The Partnership reduced the
balance owed under the Credit Agreement by $12.4 million. In the prior year
period, the Partnership paid distributions to the common unitholders and the
general partner totaling $3.5 million and repaid debt of $1.0 million.
Working Capital and Credit Resources
Effective December 19, 2001, GCOLP entered into a two-year $130 million
Senior Secured Revolving Credit Facility ("Credit Agreement") with Citicorp.
Citicorp and Salomon, the former owner of the Partnership's General Partner,
are both wholly-owned subsidiaries of Citigroup Inc.
In May 2002, Genesis elected, under the terms of the Credit Agreement, to
amend the Credit Agreement to reduce the maximum facility amount to $80
million. The Credit Agreement has a $25 million sublimit for working capital
loans. Any amount not being used for working capital loans is available for
letters of credit to support crude oil purchases.
During the first four months of 2002, Salomon continued to provide
guaranties to the Partnership's counterparties under a transition arrangement
between Salomon, Citicorp and the Partnership. For crude oil purchases in
January 2002 through April 2002, a maximum of $100 million in guaranties were
available to be issued under the Salomon Guaranty Facility. Beginning with
May 2002, Citicorp provided letters of credit to the Partnership's
counterparties.
The key terms of the amended Credit Agreement are as follows:
* Letter of credit fees are based on the Applicable Leverage Level
("ALL") and will range from 1.50% to 2.75%. At June 30, 2002, the
rate was 2.25%. The ALL is a function of GCOLP's average daily debt
to its earnings before interest, depreciation and amortization for
the four preceding quarters.
* The interest rate on working capital borrowings is also based on the
ALL and allows for loans based on the prime rate or the LIBOR rate at
the Partnership's option. The interest rate on prime rate loans can
range from the prime rate to the prime rate plus 1.25%. The interest
rate for LIBOR-based loans can range from the LIBOR rate plus 1.50%
to the LIBOR rate plus 2.75%. At June 30, 2002, the interest rate on
the Partnership's borrowings was 4.75%.
* The Partnership will pay a commitment fee on the unused portion of
the $80 million commitment. This commitment fee is also based on the
ALL and will range from 0.375% to 0.50%. At June 30, 2002, the
commitment fee was 0.375%.
* The amount that the Partnership 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
Credit Agreement) generally includes the Partnership's cash balances,
net accounts receivable and inventory, less deductions for certain
accounts payable, and is calculated monthly.
* Collateral under the Credit Agreement consists of all of the
Partnership's accounts receivable, inventory, cash accounts, margin
accounts and property and equipment.
* The Credit Agreement contains covenants requiring a Current Ratio (as
defined in the Credit Agreement), a Leverage Ratio (as defined in the
Credit Agreement), an Interest Coverage Ratio (as defined in the
Credit Agreement) and limitations on distributions to Unitholders.
The terms above reflect the terms in the amended Credit Agreement. That
amendment also provides that, should the Credit Agreement not be syndicated to
reduce Citicorp's participation to $20 million by September 30, 2002, the
interest rates, commitment fee rates and letter of credit fees will revert to
those in the original Credit Agreement executed on December 19, 2001. The
maximum rates in that agreement were 4.50% for letter of credit fees, LIBOR
plus 4.50% for LIBOR-based loans, the prime rate plus 1.25% for prime rate
loans and 0.75% for commitment fees.
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 Credit Agreement for every day of the
quarter by at least $20 million. See additional discussion below under
"Distributions".
Management of the Partnership believes that the terms of the Credit
Agreement with Citicorp are similar to the terms that could have been obtained
from a third party. The Credit Agreement terms are similar to the terms the
Partnership had discussed with other banks.
At June 30, 2002, the Partnership had $1.5 million of loans outstanding
under the Credit Agreement. The outstanding loan balance is to be repaid by
December 31, 2003; however, due to the revolving nature of the loans,
additional borrowings and periodic repayments and re-borrowings may be made
until that date. At June 30, 2002, the Partnership had letters of credit
outstanding totaling $14.1 million and $13.4 million under the Credit
Agreement for crude oil purchases related to June 2002 and July 2002,
respectively.
As a result of the Partnership's decision to reduce its level of bulk and
exchange transactions, management of the Partnership expects that the
Partnership's need for credit support in the form of letters of credit to be
less in 2002 than it was in 2001. However, 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 the Partnership's gathering and marketing activities due to the
limitations of the Credit Agreement and Borrowing Base. This situation could
in turn adversely affect the Partnership's ability to maintain or increase the
level of its purchasing and marketing activities or otherwise adversely affect
the Partnership's profitability and Available Cash.
Contractual Obligation and Commercial Commitments
In addition to the Credit Agreement discussed above, the Partnership has
contractual obligations under operating leases as well as commitments to
purchase crude oil. The table below summarizes these obligations and
commitments at June 30, 2002 (in thousands).
Payments Due by Period
-----------------------------------------------
Less than 1 - 3 4 - 5 After 5
Contractual Cash Obligations Total 1 Year Years Years Years
- ---------------------------- -------- -------- ------- ------ ------
Long-term Debt $ 1,500 $ - $ 1,500 $ - $ -
Operating Leases 26,985 5,894 11,377 4,703 5,011
Unconditional Purchase Obligations96,663 95,069 1,594 - -
-------- -------- ------- ------ ------
Total Contractual Cash Obligations $125,148 $100,963 $14,471 $4,703 $5,011
======== ======== ======= ====== ======
The unconditional purchase obligations included above are contracts to purchase crude oil, generally
at market-based prices. For purposes of this table, market prices at June 30, 2002, were used to
value the obligations, such that actual obligations may differ from the amounts included above.
Distributions
Generally, GCOLP will distribute 100% of its Available Cash within 45
days after the end of each quarter to Unitholders of record and to the General
Partner. Available Cash consists generally of all of the cash receipts less
cash disbursements of GCOLP adjusted for net changes to reserves. (A full
definition of Available Cash is set forth in the Partnership Agreement.) As a
result of the restructuring approved by Unitholders in December 2000, the
target minimum quarterly distribution ("MQD") for each quarter was reduced to
$0.20 per unit beginning with the distribution for the fourth quarter of 2000,
which was paid in February 2001.
Under the terms of the Credit Agreement, the Partnership may not pay a
distribution for any quarter unless the Borrowing Base exceeded the usage
under the Credit Agreement (working capital loans plus outstanding letters of
credit) for every day of the quarter by at least $20 million plus the total
amount of the distribution. In order to exceed the required total, the
Partnership will need to reduce working capital loans and/or the amount of
letters of credit issued on the Partnership's behalf by Citicorp.
For the first and second quarters of 2002, the Partnership will not pay a
distribution as the excess of the Borrowing Base over the usage dropped below
the required total. It is unclear when the Partnership will meet the
distribution test in the Citicorp Credit Facility and when distributions will
resume. Should distributions resume, the distribution per common unit may be
less than $0.20 per unit.
For each of the first two quarters of 2001, the Partnership paid a
distribution to the Common Unitholders and the General Partner of $0.20 per
unit.
Other Matters
Crude Oil Contamination
The Partnership has been named one of the defendants in a complaint filed
by Thomas Richard Brown on January 11, 2001, in the 125th District Court of
Harris County, cause No. 2001-01176. Mr. Brown, an employee of Pennzoil-
Quaker State Company ("PQS"), seeks damages for burns and other injuries
suffered as a result of a fire and explosion that occurred at the Pennzoil
Quaker State refinery in Shreveport, Louisiana, on January 18, 2000.
On January 17, 2001, PQS filed a Plea in Intervention in the cause filed
by Mr. Brown. PQS seeks property damages, loss of use and business
interruption. Both plaintiffs claim the fire and explosion was caused, in
part, by Genesis selling to PQS crude oil that was contaminated with organic
chlorides. Management of the Partnership believes that the suit is without
merit and intends to vigorously defend itself in this matter. Management of
the Partnership believes that any potential liability will be covered by
insurance.
Crude Oil Spill
On December 20, 1999, the Partnership had a spill of crude oil from its
Mississippi System. Approximately 8,000 barrels of oil spilled from the
pipeline near Summerland, Mississippi, and entered a creek nearby. 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.
Sale of the General Partner by Salomon
On May 14, 2002, Salomon sold its 100% ownership interest in the General
Partner to a subsidiary of Denbury Resources, Inc. ("Denbury"). Denbury is an
independent oil and gas company.
Amendment to Partnership Agreement
On July 31, 2002, Genesis Energy, Inc. ("Genesis") amended Section 11.2
of the Second Amended and Restated Agreement of Limited Partnership of Genesis
Energy, L.P. ("the Partnership Agreement") to broaden the right of the Common
Unitholders to remove the general partner of Genesis Energy, L.P. ("GELP").
Prior to this amendment, the general partner could only be removed for cause
and with approval by holders of two-thirds or more of the outstanding limited
partner interests in GELP. As amended, the Partnership Agreement provides
that, with the approval of at least a majority of the limited partners in
GELP, the general partner also may be removed without cause. Any limited
partner interests held by the general partner and its affiliates are to be
excluded from such a vote.
The amendment further provides that if it is proposed that the removal is
without cause and an affiliate of Denbury is the general partner to be removed
and not proposed as a successor, then any action for removal must also provide
for Denbury to be granted an option effective upon its removal to purchase
GELP's Mississippi pipeline system at a price that is 110 percent of its fair
market value at that time. Fair value is to be determined by agreement of two
independent appraisers, one chosen by the successor general partner and the
other by Denbury or if they are unable to agree, the mid-point of the values
determined by them.
The amendment was negotiated on behalf of GELP by the audit committee of
the board of directors of Genesis. Upon determination of its fairness,
including obtaining an opinion from the investment banking firm of the
GulfStar Group as to the amendment's fairness to the Common Unitholders of
GELP, and an opinion from Delaware legal counsel as to the form of the
amendment, the audit committee recommended approval of the amendment to the
board of directors of Genesis.
New Accounting Standards
In June, 2001, the FASB issued FAS 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 is
effective for fiscal years beginning after June 15, 2002, with earlier
application encouraged. The Partnership is currently evaluating the effect on
its financial statements of adopting FAS No. 143 and plans to adopt the
statement effective January 1, 2003.
In April 2002 the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." SFAS No. 145 rescinds SFAS No. 4, "Reporting Gains and Losses
from Extinguishment of Debt" and an amendment of that statement, SFAS No. 64,
"Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements." SFAS No.
145 also rescinds SFAS No. 44, "Accounting for Intangible Assets of Motor
Carriers." SFAS No. 145 also amends SFAS No. 13, "Accounting for Leases," to
eliminate an inconsistency between the required accounting for sale-leaseback
transactions and the required accounting for certain lease modifications that
have economic effects that are similar to sale-leaseback transactions. SFAS
No. 145 also amends other existing authoritative pronouncements to make
various technical corrections, clarify meanings, or describe their
applicability under changed conditions. The provisions related to the
rescission of SFAS No. 4 shall be applied in fiscal years beginning after May
15, 2002. The provisions related to SFAS No. 13 shall be effective for
transactions occurring after May 15, 2002. All other provisions shall be
effective for financial statements issued on or after May 15, 2002, with early
application encouraged. The Partnership does not believe that SFAS No. 145
will have a material effect on its results of operations.
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 Partnership
has not completed its analysis of the impact that SFAS No. 146 will have on
its consolidated financial statements.
Outlook
Historically, the crude oil gathering and marketing business has been very
competitive with thin and volatile profit margins. The ability to generate
margin in the crude oil gathering and marketing business is not directly
related to the absolute level of crude oil prices, but is generated by the
difference between the price at which crude oil is sold and the price paid and
other costs incurred in the purchase and transportation of the crude oil, as
well as the volume of crude oil available for purchase. In order to maximize
gross margin, management has been and will continue to analyze all aspects of
its gathering and marketing business in order to make decisions associated
with managing its marketing operations, field operations and administrative
support.
Another factor affecting crude oil gathering and marketing gross margins is
changes in the domestic production of crude oil. Short-term and long-term
crude oil 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 Genesis and its competitors. During the period
from 1999 through 2001, crude oil prices were marked by significant volatility
which made it very difficult to estimate the amount of crude oil available to
purchase. Management expects to continue to be subject to volatility and
long-term declines in the availability of crude oil production for purchase by
Genesis.
Genesis' gathering and marketing operations are also impacted by credit
support costs in the form of letters of credit. As stated above, gathering
and marketing gross margins are not tied to the absolute prices of crude oil.
In contrast, the per barrel cost of credit is a function of the absolute price
of crude oil, such that, as crude oil prices rise, credit costs increase. In
anticipation of the change to a smaller credit facility during the first
quarter of 2002, management began making changes to its business model in the
latter half of 2001 in order to be able to operate with a much smaller
revolving credit facility with a higher per barrel cost. These changes
resulted in a substantial decrease in the Partnership's bulk and exchange
activity by the end of 2001. Had the Partnership continued to engage in its
bulk and exchange activity, management believes that increases in the related
cost of credit would have substantially offset the gross margin provided by
that activity. Additionally, the Partnership began reviewing its wellhead
purchase contracts to determine whether margins under those contracts would
support higher credit costs per barrel. In some cases where contract terms
could not be renegotiated to improve margins after considering the higher cost
of credit, contracts were cancelled.
The cost of credit is impacted by the extent to which trade counterparties
require credit support. In the aftermath of the Enron collapse, the
Partnership experienced increased demand for credit from producers. Genesis
then initiated a program to reduce the credit support provided to
counterparties. As a result, demand for credit support decreased. No
assurances can be made that such credit requirements will decrease further or
that such credit support requirements will not increase over time.
Like the gathering and marketing operations, prospects for Genesis' pipeline
operations also are impacted by production declines. Declining production in
the areas surrounding Genesis' pipelines have reduced tariff revenues while
costs are expected either to remain fixed or to increase due to various
conditions, including increasing insurance costs, new pipeline integrity
management regulations and commercial and residential development over our
pipeline right of ways. Consequently, pipeline gross margins are expected to
decline unless Genesis obtains substantial increases in its tariff rates.
Genesis increased tariffs beginning in May 2002 in some areas. It is
uncertain whether further increases can be obtained and whether the increases
that were made will be sufficient to offset production declines in the
pipeline operating areas and any increased maintenance and operating costs
related to its pipelines.
On May 14, 2002, Salomon sold its 100% ownership interest in the General
Partner to a subsidiary of Denbury. Genesis owns and operates a 261-mile
pipeline system in Mississippi adjacent to several of Denbury's existing and
prospective oil fields. Denbury is the largest oil and natural gas operator
in the state of Mississippi. There may be mutual benefits to Denbury and
Genesis due to this common production and transportation area. Because of the
new relationship, Genesis may 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. Genesis may be able to provide or acquire
this infrastructure and provide support to Denbury's development of these
fields. Further, as the fields are developed over time, it may create
increased demand for Genesis' crude oil transportation services.
In order to increase the effectiveness of the Denbury related strategic
opportunities, the Partnership continues to evaluate opportunities to dispose
of underperforming assets and increase operating income by reducing
nonessential expenditures. Since management believes that its most
significant growth opportunities will revolve around the Mississippi System
due to Denbury's ownership of its general partner, most of the asset
optimization analysis is currently focused on the Texas System and the Jay
System.
Management is reviewing strategic opportunities for the Texas System. While
recent tariff increases have improved the outlook for this system, management
continues to examine opportunities for every part of the system to determine
if each segment should be sold, abandoned, or invested in for further growth.
Management believes that the highest and best use of the Jay system in
Florida/Alabama would be to convert it to natural gas service. Genesis has
entered into strategic alliance with parties in the region to explore this
opportunity. Part of the process will involve finding alternative methods for
Genesis to continue to provide crude oil transportation services in the area.
While management believes this initiative has long-term potential, it is not
expected to have a substantial impact on the Partnership during 2002 or 2003.
The financial performance of the Partnership exceeded expectations for the
first half of 2002. Management expects similar results for the remainder of
this year. Based on the improved performance during the first half of the
year, the Partnership may meet the restrictive covenant in the Citicorp Credit
Agreement limiting its ability to make distributions as soon as the third
quarter of 2002. As discussed in Distributions above, the Partnership may not
pay a distribution for any quarter unless the Borrowing Base exceeded the
usage under the Credit Agreement (working capital loans plus outstanding
letters of credit) for every day of the quarter by at least $20 million plus
the total amount of the distribution. If the Partnership meets this
requirement, it may resume distributions sooner than previously expected. In
determining the amount of distribution for any future quarter, the Partnership
will consider its ability to sustain such distributions on a reasonable basis
with its existing asset base, capital requirements to maintain and optimize
the performance of its asset base, its ability to finance its existing capital
requirements and accretive acquisitions, and the potential for unitholders
being allocated taxable income from the Partnership. If distributions are
resumed, such distributions may be for amounts less that $0.20 per unit.
Forward Looking Statements
The statements in this 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
management of the General Partner believes that its expectations regarding
future events are based on reasonable assumptions, no assurance can be made
that the Partnership's 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:
* changes in regulations;
* the Partnership's success in obtaining additional lease barrels;
* changes in crude oil production volumes (both world-wide and in areas in
which the Partnership has operations);
* developments relating to possible acquisitions or business combination
opportunities;
* volatility of crude oil prices and grade differentials;
* the success of the risk management activities;
* credit requirements by the counterparties;
* the cost of obtaining liability and property insurance at a reasonable
cost;
* the Partnership's ability in the future to generate sufficient amounts
of Available Cash to permit the distribution to unitholders of at least
the minimum quarterly distribution;
* any requirements for testing or changes in the Mississippi pipeline
system as a result of the oil spill that occurred there in December
1999;
* any fines and penalties federal and state regulatory agencies may impose
in connection with the oil spill that would not be reimbursed by
insurance;
* the costs of testing under the Integrity Management Program and any
repairs required as a result of that testing;
* the Partnership's success in increasing tariff rates on its common
carrier pipelines and retaining the volumes shipped;
* the results of the Partnership's exploration of opportunities to convert
the Jay pipeline system to natural gas service and finding alternative
methods to continue crude oil service in the area;
* results of current or threatened litigation; and
* 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
the Partnership, or persons acting on the Partnership's 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. The Partnership utilizes New York Mercantile Exchange ("NYMEX")
commodity based futures contracts, forward contracts, swap agreements and
option contracts to hedge its exposure to these market price fluctuations.
Management believes the hedging program has been effective in minimizing
overall price risk. At June 30, 2002, the Partnership used forward contracts
in its hedging program with the latest contract being settled in July 2002.
Information about these contracts is contained in the table set forth below.
Sell (Short) Buy (Long)
Contracts Contracts
------- -------
Crude Oil Inventory:
Volume (1,000 bbls) 19
Carrying value (in thousands) $ 511
Fair value (in thousands) $ 501
Commodity Forward Contracts:
Contract volumes (1,000 bbls) 260 260
Weighted average price per bbl $ 25.46 $ 25.67
Contract value (in thousands) $ 6,619 $ 6,673
Mark-to-market change (in thousands) 180 174
------- -------
Market settlement value (in thousands) $ 6,799 $ 6,847
======= =======
The table above presents notional amounts in barrels, the weighted
average contract price, total contract amount in U.S. dollars and total fair
value amount in U.S. dollars. Fair values were determined by using the
notional amount in barrels multiplied by the June 30, 2002 closing prices of
the applicable NYMEX futures contract adjusted for location and grade
differentials, as necessary.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
See Part I. Item 1. Note 10 to the Consolidated Financial Statements
entitled "Contingencies", which is incorporated herein by reference.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits.
Exhibit 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 May 2, 2002 to announce a change
in Genesis' Certifying Accountants from Arthur Andersen LLP to Deloitte
& Touche LLP.
A report on Form 8-K was filed on May 6, 2002 announcing that
Denbury Resources Inc. would purchase the general partner of Genesis
Energy, L.P. from Salomon.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
GENESIS ENERGY, L.P.
(A Delaware Limited Partnership)
By: GENESIS ENERGY, INC, as
General Partner
Date: August 12, 2002 By: /s/ Ross A. Benavides
----------------------------
Ross A. Benavides
Chief Financial Officer