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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
--------------------------------
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2004
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-12295
GENESIS ENERGY, L.P.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 76-0513049
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
500 DALLAS, SUITE 2500, HOUSTON, TEXAS 77002
(Address of principal executive offices) (Zip Code)
(713) 860-2500
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined by Rule 12b-2 of the Exchange Act.)
Yes [ ] No [X]
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This report contains 33 pages
GENESIS ENERGY, L.P.
FORM 10-Q
INDEX
Page
----
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets - June 30, 2004 and December 31, 2003.............................. 3
Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2004
and 2003.................................................................................... 4
Consolidated Statements of Comprehensive Income for the Three and Six Months Ended
June 30, 2004 and 2003...................................................................... 5
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2004 and 2003.......... 6
Consolidated Statement of Partners' Capital for the Six Months Ended June 30, 2004............. 7
Notes to Consolidated Financial Statements..................................................... 8
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.......... 18
Item 3. Quantitative and Qualitative Disclosures about Market Risk..................................... 32
Item 4. Controls and Procedures........................................................................ 32
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.............................................................................. 32
Item 6. Exhibits and Reports on Form 8-K............................................................... 33
SIGNATURES.............................................................................................. 33
-2-
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
(Unaudited)
June 30, December 31,
2004 2003
-------- ----------
ASSETS
CURRENT ASSETS
Cash and cash equivalents...................................... $ 1,732 $ 2,869
Accounts receivable-trade...................................... 77,227 66,732
Inventories.................................................... 1,165 1,546
Insurance receivable........................................... 1,363 15,524
Other.......................................................... 1,119 1,540
---------- ----------
Total current assets........................................ 82,606 88,211
FIXED ASSETS, at cost............................................. 72,654 70,695
Less: Accumulated depreciation................................ (38,336) (36,724)
----------- ----------
Net fixed assets............................................ 34,318 33,971
CO2 ASSETS, net of amortization................................... 22,937 24,073
OTHER ASSETS, net of amortization................................. 1,516 860
---------- ----------
TOTAL ASSETS...................................................... $ 141,377 $ 147,115
========== ==========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable -
Trade....................................................... $ 66,381 $ 60,108
Related party............................................... 10,665 7,067
Accrued liabilities............................................ 8,717 20,069
---------- ----------
Total current liabilities................................... 85,763 87,244
LONG-TERM DEBT.................................................... 5,500 7,000
COMMITMENTS AND CONTINGENCIES (Note 11)
MINORITY INTERESTS................................................ 517 517
PARTNERS' CAPITAL
Common unitholders, 9,314 units issued and outstanding......... 48,597 51,299
General partner................................................ 1,000 1,055
---------- ----------
Total partners' capital..................................... 49,597 52,354
---------- ----------
TOTAL LIABILITIES AND PARTNERS' CAPITAL........................... $ 141,377 $ 147,115
========== ==========
The accompanying notes are an integral part of these consolidated
financial statements.
-3-
GENESIS ENERGY, L.P.
STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
(Unaudited)
Three Months Ended June 30, Six Months Ended June 30,
2004 2003 2004 2003
------------ ----------- ------------ ------------
REVENUES:
Crude oil gathering and marketing................. $ 225,872 $ 143,149 $ 418,868 $ 314,842
Crude oil pipeline................................ 4,086 3,521 8,171 7,510
CO2 revenues...................................... 2,149 - 3,980 -
------------ ----------- ------------ ------------
Total revenues................................. 232,107 146,670 431,019 322,352
COSTS AND EXPENSES:
Crude oil costs:
Unrelated parties.............................. 192,327 123,682 358,299 274,561
Related parties................................ 28,424 13,684 51,399 28,866
Field operating................................ 3,195 2,716 6,238 5,558
Crude oil pipeline operating costs................ 2,429 2,327 4,661 4,805
CO2 transportation costs - related party.......... 688 - 1,279 -
General and administrative........................ 2,022 2,359 5,186 4,636
Depreciation and amortization..................... 1,627 998 3,174 2,142
Net gain on disposal of surplus assets............ (75) (3) (75) (47)
Change in fair value of derivatives............... (18) - (18) -
------------- ----------- ------------ ------------
OPERATING INCOME..................................... 1,488 907 876 1,831
OTHER INCOME (EXPENSE):
Interest income................................... 4 7 28 15
Interest expense.................................. (332) (165) (526) (715)
------------- ----------- ------------- ------------
Income from continuing operations.................... 1,160 749 378 1,131
(Loss) income from operations of discontinued
Texas System................................... (61) 1,141 (284) 1,638
------------- ----------- ------------- ------------
NET INCOME........................................... $ 1,099 $ 1,890 $ 94 $ 2,769
============= =========== ============= ============
NET INCOME (LOSS) PER COMMON UNIT - BASIC AND
DILUTED:
Income from continuing operations................. $ 0.12 $ 0.08 $ 0.04 $ 0.12
Income (loss) income from discontinued operations. 0.00 0.13 (0.03) 0.19
------------- ----------- ------------- ------------
NET INCOME........................................... $ 0.12 $ 0.21 $ 0.01 $ 0.31
============= =========== ============= ============
WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING.. 9,314 8,625 9,314 8,625
============= =========== ============= ============
The accompanying notes are an integral part of these consolidated
financial statements.
-4-
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
(Unaudited)
Three Months Ended June 30, Six Months Ended June 30,
2004 2003 2004 2003
------------ ----------- ------------ ------------
NET INCOME........................................... $ 1,099 $ 1,890 $ 94 $ 2,769
OTHER COMPREHENSIVE INCOME:
Change in fair value of derivatives used for
hedging purposes............................ - - - 39
------------ ----------- ------------ ------------
COMPREHENSIVE INCOME................................. $ 1,099 $ 1,890 $ 94 $ 2,808
============ =========== ============ ============
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,
2004 2003
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income...................................................................... $ 94 $ 2,769
Adjustments to reconcile net income to net cash provided by operating
activities -
Depreciation................................................................. 2,038 2,678
Amortization of CO2 contracts and covenant not-to-compete.................... 1,136 206
Amortization and write-off of credit facility issuance costs................. 194 841
Change in fair value of derivatives.......................................... (18) 39
Gain on asset disposals...................................................... (75) (47)
Other non-cash charges....................................................... 592 -
Changes in components of working capital -
Accounts receivable....................................................... (10,495) 3,869
Inventories............................................................... (529) 3,027
Other current assets...................................................... 14,582 1,141
Accounts payable.......................................................... 9,871 (7,358)
Accrued liabilities....................................................... (11,926) (916)
--------- ---------
Net cash provided by operating activities......................................... 5,464 6,249
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment............................................. (1,479) (3,509)
Change in other assets.......................................................... (11) (2)
Proceeds from sale of assets.................................................... 79 87
--------- ---------
Net cash used in investing activities............................................. (1,411) (3,424)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net borrowings (repayments) of debt............................................. (1,500) 500
Credit facility issuance fees................................................... (839) (1,093)
Distributions to common unitholders............................................. (2,794) (431)
Distributions to General Partner................................................ (57) (9)
--------- ---------
Net cash used in financing activities............................................. (5,190) (1,033)
--------- ---------
Net (decrease) increase in cash and cash equivalents.............................. (1,137) 1,792
Cash and cash equivalents at beginning of year.................................... 2,869 1,071
--------- ---------
Cash and cash equivalents at end of period........................................ $ 1,732 $ 2,863
========= =========
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
---------------------------------------------------
Number of
Common Common General
Units Unitholders Partner Total
---------- ----------- --------- ---------
Partners' capital at January 1, 2004................... 9,314 $ 51,299 $ 1,055 $ 52,354
Net income for the six months ended June 30, 2004...... - 92 2 94
Distributions to partners during the six months ended
June 30, 2004........................................ - (2,794) (57) (2,851)
----- ----------- --------- ---------
Partners' capital at June 30, 2004..................... 9,314 $ 48,597 $ 1,000 $ 49,597
===== =========== ========= =========
The accompanying notes are an integral part of these consolidated
financial statements.
-7-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
Organization
Genesis Energy, L.P. (GELP or the Partnership) is a publicly traded
Delaware limited partnership engaged in gathering, marketing and transportation
of crude oil and wholesale marketing of carbon dioxide (CO2). We were formed in
December 1996 through an initial public offering of 8.6 million Common Units,
representing limited partner interests in GELP of 98%. The General Partner of
GELP is Genesis Energy, Inc. (the General Partner) which owns a 2% general
partner interest in GELP. The General Partner is owned by Denbury Gathering &
Marketing, Inc. a subsidiary of Denbury Resources Inc. Denbury and its
subsidiaries are hereafter referred to as Denbury.
In November 2003, an additional 0.7 million Common Units were sold to our
general partner in a private placement. These Common Units are not registered
with the Securities and Exchange Commission. See Note 4.
Genesis Crude Oil, L.P. is the operating limited partnership and is owned
99.99% by GELP and 0.01% by the General Partner. Genesis Crude Oil, L.P. has two
subsidiary partnerships, Genesis Pipeline Texas, L.P. and Genesis Pipeline USA,
L.P. Genesis Crude Oil, L.P. and its subsidiary partnerships will be referred to
as GCOLP.
Basis of Presentation
The accompanying financial statements and related notes present the
consolidated financial position as of June 30, 2004 and December 31, 2003 for
GELP, its results of operations and changes in comprehensive income for the
three and six months ended June 30, 2004 and 2003, and its cash flows and
changes in partners' capital for the six months ended June 30, 2004 and 2003.
The financial statements included herein have been prepared by us without
audit pursuant to the rules and regulations of the Securities and Exchange
Commission (SEC). Accordingly, they reflect all adjustments (which consist
solely of normal recurring adjustments) which are, in the opinion of management,
necessary for a fair presentation of the financial results for interim periods.
Certain information and notes normally included in financial statements prepared
in accordance with generally accepted accounting principles have been condensed
or omitted pursuant to such rules and regulations. However, we believe that the
disclosures are adequate to make the information presented not misleading. These
financial statements should be read in conjunction with the financial statements
and notes thereto included in our Annual Report on Form 10-K for the year ended
December 31, 2003 filed with the SEC.
All significant intercompany transactions have been eliminated. Certain
reclassifications were made to prior period amounts to conform to current period
presentation. Such reclassifications had no effect on reported net income, total
assets, total liabilities or partners' equity.
No provision for income taxes related to the operation of GELP is included
in the accompanying consolidated financial statements; as such income will be
taxable directly to the partners holding partnership interests in the
Partnership.
2. NEW ACCOUNTING PRONOUNCEMENTS
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities" (FIN 46), which requires the consolidation of
variable interest entities, as defined. FIN 46, as revised, was applicable to
financial statements of companies that have interests in "special purpose
entities", as defined, during 2003. FIN 46 is applicable to financial statements
of companies that have interests in all other types of entities, in the first
quarter of 2004. We did not have any variable interest entities that were
required to be consolidated as a result of FIN 46.
3. DEBT
On June 1, 2004, we finalized a $100 million senior secured bank credit
facility with a group of five lenders (New Credit Facility). The New Credit
Facility consists of a $50 million revolving line of credit for acquisitions and
-8-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
a $50 million working capital revolving credit facility. The facility matures in
June 2008. This facility replaced our existing $65 million facility.
The working capital portion of the New Credit Facility has a sublimit of
$15 million for working capital loans with the remainder of the $50 million
portion available for letters of credit.
The key terms of the New Credit Facility are as follows:
- Letter of credit fees are based on the usage of the working
capital portion of the New Credit Facility in relation to the
borrowing base and will range from 1.75% to 2.75%. At June 30,
2004, the rate was 2.25%.
- The interest rate on working capital borrowings is also based
on the usage of the New Credit Facility in relation to the
borrowing base. Loans may be 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 0.25% to the prime
rate plus 1.25%. The interest rate for LIBOR-based loans can
range from the LIBOR rate plus 1.75% to the LIBOR rate plus
2.75%. At June 30, 2004, we borrowed at the prime rate plus
0.75%.
- The interest rate on acquisition borrowings may be based on
the prime rate or the LIBOR rate, at our option. The interest
rate on prime rate loans will be the prime rate plus 1.50%.
The interest rate for LIBOR-based loans will be the LIBOR rate
plus 3.00%. At June 30, 2004, we had no debt outstanding under
this portion of the New Credit Facility.
- We pay a commitment fee on the unused portion of the $100
million commitment. The commitment fee on the working capital
portion is based on the usage of that portion of the New
Credit Facility in relation to the borrowing base and will
range from 0.375% to 0.50%. At June 30, 2004, the commitment
fee rate was 0.50%. The commitment fee rate on the acquisition
portion is 0.50%.
- 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 is defined in
the New Credit Facility generally to include cash balances,
net accounts receivable and inventory, less deductions for
certain accounts payable, and is calculated monthly. The
Borrowing Base is limited to $50 million. At June 30, 2004,
the Borrowing Base was $50 million.
- Collateral under the New Credit Facility consists of our
accounts receivable, inventory, cash accounts, margin accounts
and fixed assets.
- The New Credit Facility contains covenants requiring a minimum
current ratio, a minimum leverage ratio, a minimum cash flow
coverage ratio, a maximum ratio of indebtedness to
capitalization, and a minimum EBITDA (earnings before
interest, taxes, depreciation and amortization).
At June 30, 2004, we had $5.5 million outstanding under the working
capital portion of the New Credit Facility. Due to the revolving nature of loans
under the New Credit Facility, additional borrowings and periodic repayments and
re-borrowings may be made until the maturity date of June 1, 2008. At June 30,
2004, we had letters of credit outstanding under the New Credit Facility
totaling $20.6 million, comprised of $10.0 million and $9.8 million for crude
oil purchases related to June 2004 and July 2004, respectively and $0.8 million
related to other business obligations.
We have no limitations on making distributions in our New Credit
Agreement, except as to the effects of distributions in covenant calculations.
The New Credit Agreement requires we maintain a cash flow coverage ratio of 1.1
to 1.0. In general, this calculation compares operating cash inflows, as
adjusted in accordance with the New Credit Agreement, less maintenance capital
expenditures to the sum of interest expense and distributions. At June 30, 2004,
the calculation resulted in a ratio of 1.2 to 1.0.
-9-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. PARTNERS' CAPITAL AND DISTRIBUTIONS
Partners' Capital
Until November 2003, partnership equity consisted of the general partner
interest of 2% and 8.6 million Common Units representing limited partner
interests of 98%. The Common Units were sold to the public in an initial public
offering in December 1996. In November 2003, we issued 688,811 additional Common
Units to our General Partner. At June 30, 2004, a total of 9,313,811 Common
Units were outstanding.
The general partner interest is held by our General Partner. The
Partnership is managed by the General Partner. The General Partner also holds a
0.01% general partner interest in GCOLP, which is reflected as a minority
interest in the consolidated balance sheet at June 30, 2004.
The Partnership Agreement authorizes the General Partner to cause GCOLP to
issue additional limited partner interests and other equity securities, the
proceeds from which could be used to provide additional funds for acquisitions
or other GCOLP needs.
Distributions
Generally, we will distribute 100% of our Available Cash within 45 days
after the end of each quarter to Unitholders of record and to the General
Partner. Available Cash consists generally of all of our cash receipts less cash
disbursements adjusted for net changes to reserves. The target minimum quarterly
distribution (MQD) for each quarter is $0.20 per unit. For the first three
quarters of 2003, we paid a regular quarterly distribution of $0.05 per unit
($0.4 million in total per quarter). Beginning with the fourth quarter of 2003,
we increased our quarterly distribution to $0.15 per unit ($1.4 million in
total). We have declared a $0.15 per unit distribution for the second quarter of
2004, payable on August 13, 2004 to unitholders of record on July 30, 2004.
Our general partner is entitled to receive incentive distributions if the
amount we distribute with respect to any quarter exceeds levels specified in our
partnership agreement. Under the quarterly incentive distribution provisions,
the general partner generally is entitled to receive 13.3% of any distributions
in excess of $0.25 per unit, 23.5% of any distributions in excess of $0.28 per
unit and 49% of any distributions in excess of $0.33 per unit without
duplication. We have not paid any incentive distributions through June 30, 2004.
-10-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Net Income Per Common Unit
The following table sets forth the computation of basic net income per
Common Unit.
Three Months Ended June 30, Six Months Ended June 30,
2004 2003 2004 2003
------- ------- ------- -------
(in thousands, except per unit amounts)
Numerators for basic and diluted net income per
common unit:
Income from continuing operations ............. $ 1,160 $ 749 $ 378 $ 1,131
Less general partner 2% ownership ............. 23 15 8 23
------- ------- ------- -------
Income from continuing operations available
for common unitholders ...................... $ 1,137 $ 734 $ 370 $ 1,108
======= ======= ======= =======
(Loss) income from discontinued operations .... $ (61) $ 1,141 $ (284) $ 1,638
Less general partner 2% ownership ............. (1) 23 (6) 33
------- ------- ------- -------
(Loss) income from discontinued operations
available for common unitholders ............ $ (60) $ 1,118 $ (278) $ 1,605
======= ======= ======= =======
Denominator for basic and diluted per Common Unit
- weighted average number of Common Units
outstanding ................................... 9,314 8,625 9,314 8,625
======= ======= ======= =======
Basic and diluted net income (loss) per Common
Unit:
Income from continuing operations ............ $ 0.12 $ 0.08 $ 0.04 $ 0.12
Income (Loss) from discontinued operations ... 0.00 0.13 (0.03) 0.19
------- ------- ------- -------
Net income ................................... $ 0.12 $ 0.21 $ 0.01 $ 0.31
======= ======= ======= =======
5. BUSINESS SEGMENT INFORMATION
Our operations consist of three operating segments: (1) Crude Oil
Gathering and Marketing - the purchase and sale of crude oil at various points
along the distribution chain; (2) Crude Oil Pipeline Transportation - interstate
and intrastate crude oil pipeline transportation; and (3) CO2 marketing - the
sale of CO2 acquired under a volumetric production payment to industrial
customers. Prior to 2003, we managed our crude oil gathering, marketing and
pipeline operations as a single segment. The tables below reflect all periods
presented as though the current segment designations had existed, and include
only continuing operations data.
We evaluate segment performance based on segment margin before
depreciation and amortization. All of our revenues are derived from, and all of
our assets are located in the United States.
-11-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Crude Oil
-------------------------
Gathering and CO2
Marketing Pipeline Marketing Total
--------- -------- --------- -----
(in thousands)
Three Months Ended June 30, 2004
Revenues:
External Customers ...................... $225,872 $ 3,206 $ 2,149 $231,227
Intersegment (a) ........................ - 880 - 880
-------- -------- -------- --------
Total revenues of reportable segments ... $225,872 $ 4,086 $ 2,149 $232,107
======== ======== ======== ========
Segment margin excluding
depreciation and amortization (b) ..... $ 1,944 1,657 $ 1,461 $ 5,062
Capital expenditures .................... $ 24 $ 1,055 $ - $ 1,079
Maintenance capital
expenditures .......................... $ 24 $ 231 $ - $ 255
Three Months Ended June 30, 2003
Revenues:
External Customers ...................... $143,149 $ 2,472 $ - $145,621
Intersegment (a) ........................ - 1,049 - 1,049
-------- -------- -------- --------
Total revenues of reportable segments ... $143,149 $ 3,521 $ - $146,670
======== ======== ======== ========
Segment margin excluding
depreciation and amortization (b) ..... $ 3,067 1,194 $ - $ 4,261
Capital expenditures .................... $ 186 $ 565 $ - $ 751
Maintenance capital
expenditures .......................... $ 186 $ 565 $ - $ 751
Six Months Ended June 30, 2004
Revenues:
External Customers ...................... $418,868 $ 6,469 $ 3,980 $429,317
Intersegment (a) ........................ - 1,702 - 1,702
-------- -------- -------- --------
Total revenues of reportable segments ... $418,868 $ 8,171 $ 3,980 $431,019
======== ======== ======== ========
Segment margin excluding
depreciation and amortization (b) ..... $ 2,950 3,510 $ 2,701 $ 9,161
Capital expenditures .................... $ 75 $ 1,404 $ - $ 1,479
Maintenance capital
expenditures .......................... $ 75 $ 335 $ - $ 410
Net fixed and other long-term
assets ................................ $ 6,654 $ 29,181 $ 22,937 $ 58,772
Six Months Ended June 30, 2003
Revenues:
External Customers ...................... $314,842 $ 5,683 $ - $320,525
Intersegment (a) ........................ - 1,827 - 1,827
-------- -------- -------- --------
Total revenues of reportable segments ... $314,842 $ 7,510 $ - $322,352
======== ======== ======== ========
Segment margin excluding
depreciation and amortization (b) ..... $ 5,857 2,705 $ - $ 8,562
Capital expenditures .................... $ 322 $ 1,377 $ - $ 1,699
Maintenance capital
expenditures .......................... $ 322 $ 1,377 $ - $ 1,699
a) Intersegment sales were conducted on an arm's length basis.
-12-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
b) Segment margin was calculated as revenues less cost of sales and operations
expense. A reconciliation of segment margin to operating income from
continuing operations for period presented is as follows:
Three Months Ended June 30, Six Months Ended June 30,
2004 2003 2004 2003
------- ------- ------- -------
(in thousands)
Segment margin excluding depreciation and
amortization ................................ $ 5,062 $ 4,261 $ 9,161 $ 8,562
General and administrative expenses ........... 2,022 2,359 5,186 4,636
Depreciation, amortization and impairment ..... 1,627 998 3,174 2,142
Net gain on disposal of surplus assets ........ (75) (3) (75) (47)
------- ------- ------- -------
Operating income from continuing operations ... $ 1,488 $ 907 $ 876 $ 1,831
======= ======= ======= =======
6. DISCONTINUED OPERATIONS
In the fourth quarter of 2003, we sold a significant portion of our Texas
Pipeline System and the related crude oil gathering and marketing operations to
TEPPCO Crude Oil, L.P. Additionally we sold other segments of our Texas Pipeline
System that had been idled in 2002 to Blackhawk Pipeline, L.P., an affiliate of
Multifuels, Inc. Some remaining segments not sold to these parties were
abandoned in place.
Costs incurred to dismantle abandoned segments during the first and second
quarters of 2004 are included in discontinued operations. For the three and six
months ended June 30, 2003, discontinued operations includes the operating
results of the assets sold or abandoned in the fourth quarter of 2003.
Operating results from the discontinued operations for the three and six
months ended June 30, 2004 and 2003 were as follows:
Three Months Ended June 30, Six Months Ended June 30,
2004 2003 2004 2003
------------ ----------- ------------ ------------
(in thousands)
Revenues:
Crude oil gathering and marketing................. $ - $ 71,383 $ - $ 155,654
Crude oil pipeline................................ - 1,896 - 3,825
------------ ----------- ------------ ------------
Total revenues................................. - 73,279 - 159,479
Costs and expenses:
Crude oil costs................................... - 68,946 - 151,176
Field operating costs............................. 1 1,312 8 2,609
Crude oil pipeline operating costs................ 60 1,423 276 3,141
General and administrative........................ - 86 - 173
Depreciation and amortization..................... - 371 - 742
------------ ----------- ------------ ------------
Total costs and expenses....................... 61 72,138 284 157,841
------------ ----------- ------------ ------------
(Loss) income from operations from discontinued Texas
System before minority interests................. $ (61) $ 1,141 $ (284) $ 1,638
============ =========== ============ ============
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.
-13-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Purchases of Crude Oil
Purchases of crude oil from Denbury for the six months ended June 30, 2004
and 2003 were $51.4 million and $28.9 million, respectively. Purchases from
Denbury are partially secured by letters of credit.
General and Administrative Services
We do not directly employ any persons to manage or operate our business.
Those functions are provided by the General Partner. We reimburse the General
Partner for all direct and indirect costs of these services. Total costs
reimbursed to the General Partner by us were $6.7 million and $7.9 million for
the six months ended June 30, 2004 and 2003, respectively.
Due to Related Parties
At June 30, 2004 and December 31, 2003, we owed Denbury $10.2 million and
$6.9 million, respectively, for purchases of crude oil. Additionally, we owed
Denbury $0.5 million and $0.1 million for CO2 transportation services at June
30, 2004 and December 31, 2003, respectively. We had advanced $0.4 million to
the General Partner at June 30, 2004 for administrative services. We owed the
General Partner $0.1 million at December 31, 2003 for administrative services.
Directors' Fees
In each of the six months ended June 30, 2004 and 2003, we paid $60,000 to
Denbury for the services of four of Denbury's officers who serve as directors of
the General Partner, the same rate at which our independent directors were paid.
CO2 Volumetric Production Payment and Transportation
We acquired a volumetric production payment from Denbury in November 2003
for $24.4 million. Denbury charges us a transportation fee of $0.16 per Mcf
(adjusted for inflation) to deliver the CO2 for us to our customers. For the six
months ended June 30, 2004, we incurred $1.2 million for transportation services
related to our sales of CO2.
Financing
Our general partner guarantees our obligations under the New Credit
Facility. Our general partner is a wholly-owned subsidiary of Denbury. The
obligations are not guaranteed by Denbury or any of its other subsidiaries.
8. MAJOR CUSTOMERS AND CREDIT RISK
We derive our revenues from customers primarily in the crude oil industry.
This industry concentration has the potential to impact our overall exposure to
credit risk, either positively or negatively, in that our customers could be
affected by similar changes in economic, industry or other conditions. However,
we believe that the credit risk posed by this industry concentration is offset
by the creditworthiness of our customer base. Our portfolio of accounts
receivable is comprised in large part of major international corporate entities
with stable payment experience. The credit risk related to contracts which are
traded on the NYMEX is limited due to the daily cash settlement procedures and
other NYMEX requirements.
We have established various procedures to manage our credit exposure,
including initial credit approvals, credit limits, collateral requirements and
rights of offset. Letters of credit, prepayments and guarantees are also
utilized to limit credit risk to ensure that our established credit criteria are
met.
Occidental Energy Marketing, Inc. and Marathon Ashland Petroleum LLC
accounted for 16% and 15% of total revenues for the six months ended June 30,
2004. Marathon Ashland Petroleum LLC, ExxonMobil Corporation and Shell Oil
Company accounted for 25%, 14% and 12% of total revenues during the first six
months of 2003. The majority of the revenues from these four customers in both
periods relate to our crude oil gathering and marketing operations.
-14-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9. SUPPLEMENTAL CASH FLOW INFORMATION
Cash received by the Partnership for interest was $28,000 and $15,000 for
the six months ended June 30, 2004 and 2003, respectively. Payments of interest
and commitment fees were $214,000 and $170,000 for the six months ended June 30,
2004 and 2003, respectively.
10. DERIVATIVES
Our market risk in the purchase and sale of crude oil contracts is the
potential loss that can be caused by a change in the market value of the asset
or commitment. In order to hedge our exposure to such market fluctuations, we
may enter into various financial contracts, including futures, options and
swaps. Historically, any contracts we have used to hedge market risk were less
than one year in duration.
We may utilize crude oil futures contracts and other financial derivatives
to reduce our exposure to unfavorable changes in crude oil prices. Every
derivative instrument (including certain derivative instruments embedded in
other contracts) must be recorded in the balance sheet as either an asset or
liability measured at its fair value. Changes in the derivative's fair value
must be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a derivative's
gains and losses to offset related results on the hedged item in the income
statement. Companies must formally document, designate and assess the
effectiveness of transactions that receive hedge accounting.
We mark to fair value our derivative instruments at each period end with
changes in fair value of derivatives not designated as hedges being recorded as
unrealized gains or losses. Such unrealized gains or losses will change, based
on prevailing market prices, at each balance sheet date prior to the period in
which the transaction actually occurs. Unrealized gains or losses on derivative
transactions qualifying as hedges are reflected in other comprehensive income.
We regularly review our contracts to determine if the contracts qualify
for treatment as derivatives. At June 30, 2004, we had one swap contract
qualifying as a derivative that did not meet the criteria for hedge accounting.
The fair value of this contract was determined based on quoted prices from
independent sources. We marked this contract to fair value at June 30, 2004, and
recorded income of $18,000 which is included in the consolidated statement of
operations under the caption "Change in Fair Value of Derivatives". The
consolidated balance sheet includes $18,000 in other current assets as a result
of recording the fair value of this derivative contract. The contract will
settle in October 2004. We determined that the remainder of our derivative
contracts qualified for the normal purchase and sale exemption and were
designated as such at June 30, 2004 and December 31, 2003.
11. CONTINGENCIES
Guarantees
We have guaranteed $3.4 million of residual value related to our leases of
tractors and trailers. We believe the likelihood that we would be required to
perform or otherwise incur any significant losses associated with this guarantee
is remote.
GELP has guaranteed crude oil purchases of GCOLP. These guarantees,
totaling $12.4 million, were provided to counterparties. To the extent
liabilities exist under the contracts subject to these guarantees, such
liabilities are included in the consolidated balance sheet.
GELP, the General Partner and the subsidiaries of GCOLP have guaranteed
the payments by GCOLP to the bank under the terms of the New Credit Facility
related to borrowings and letters of credit. Borrowings at June 30, 2004 were
$5.5 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.
Pennzoil Litigation
We were named a defendant in a complaint filed on January 11, 2001, in the
125th District Court of Harris County, Texas, Cause No. 2001-01176. From
Genesis, Pennzoil-Quaker State Company (PQS) was seeking
-15-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
property damages, loss of use and business interruption suffered as a result of
a fire and explosion that occurred at the Pennzoil Quaker State refinery in
Shreveport, Louisiana, on January 18, 2000. PQS claimed the fire and explosion
were caused, in part, by Genesis selling to PQS crude oil that was contaminated
with organic chlorides. In December 2003, our insurance carriers settled this
litigation for $12.8 million. The settlement was funded in February 2004, with
certain insurance companies directly funding $5.9 million of the payment and
$6.9 million was funded by us. We received reimbursement of the $6.9 million
from the insurance company on May 3, 2004.
PQS is also a defendant in five suits brought by neighbors living in the
vicinity of the PQS Shreveport, Louisiana refinery in the First Judicial
District Court, Caddo Parish, Louisiana, Cause Nos. 455,647-A. 455,658-B,
455,655-A, 456,574-A, and 458,379-C. PQS has brought a third party demand
against Genesis and others for indemnity with respect to the fire and explosion
of January 18, 2000. We believe that the demand against Genesis is without merit
and intend to vigorously defend ourselves in this matter.
Environmental
On December 20, 1999, we had a release of crude oil from our Mississippi
System. Approximately 8,000 barrels of oil were released from the pipeline near
Summerland, Mississippi, and entered a creek nearby. A portion of the oil then
flowed into the Leaf River. The clean up of the release is covered by insurance
and the direct financial impact to us of the cost of the clean-up has not been
material. Included in insurance receivable on the consolidated balance sheet at
June 30, 2004 and December 31, 2003 is $1.4 million and $2.8 million,
respectively, related to this release. Management of the Partnership reached an
agreement with the US Environmental Protection Agency and the Mississippi
Department of Environmental Quality for the payment of fines of $3.0 million
under environmental laws with respect to this oil spill. The consent order to
these fines was entered on July 27, 2004. In 2001 and 2002, a total accrual of
$3.0 million was recorded for these fines. The fines will not be covered by
insurance. In addition to the fines, we have other obligations under the consent
order to restore the environment to a condition it was in prior to the release.
Management believes such costs are covered by insurance and are included in the
insurance receivable described above.
In 1992, Howell Crude Oil Company (Howell) entered into a sublease (the
Sublease) with Koch Industries, Inc., (Koch) of land located in Santa Rosa
County, Florida to operate a crude oil trucking station (the Jay Station). The
Sublease provided that Howell would indemnify Koch for environmental
contamination on the property under certain circumstances. Howell operated Jay
Station from 1992 until December of 1996 when this operation was sold to us. We
operated Jay Station as a crude oil trucking station until 2003. Koch has
indicated that they may make a claim against us under the indemnification
provisions of the Sublease for environmental contamination on the site and
surrounding areas.
Genesis and Howell, now a subsidiary of Anadarko Petroleum Corporation,
are investigating whether Genesis and/or Howell may have liability for this
contamination, and if so, to what extent. Based upon the early stage of this
investigation, and subject to resolution of the allocation of responsibility
between us and Howell and the method and timing of any required remediation,
currently we have no reason to believe that this matter would have a material
financial effect on our financial position, results of operations, or cash
flows.
We are subject to various environmental laws and regulations. Policies and
procedures are in place to monitor compliance and to detect and address any
releases of crude oil from our pipelines or other facilities, however no
assurance can be made that such environmental releases may not substantially
affect our business.
Other Matters
We have taken additional security measures since the terrorist attacks of
September 11, 2001 in accordance with guidance provided by the Department of
Transportation and other government agencies. We cannot assure you that these
security measures would prevent our facilities from a concentrated attack. Any
future attacks on us or our customers or competitors could have a material
effect on our business, whether insured or not. We believe we are adequately
insured for public liability and property damage to others and that our coverage
is similar to other companies with operations similar to ours. No assurance can
be made that we will be able to maintain adequate insurance in the future at
premium rates that we consider reasonable.
-16-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We are subject to lawsuits in the normal course of business and
examination by tax and other regulatory authorities. Such matters presently
pending are not expected to have a material adverse effect on our financial
position, results of operations or cash flows.
12. SUBSEQUENT EVENT
On July 16, 2004, the Board of Directors of the General Partner declared a
cash distribution of $0.15 per Unit for the quarter ended June 30, 2004. The
distribution will be paid August 13, 2004, to the General Partner and all Common
Unitholders of record as of the close of business on July 30, 2004.
-17-
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Included in Management's Discussion and Analysis are the following
sections:
- Overview
- Results of Operations and Outlook for the Remainder of 2004
and Beyond
- Liquidity and Capital Resources
- Commitments and Off-Balance Sheet Arrangements
- Other Matters
In the discussions that follow, we will focus on two measures that we use
to manage the business and to review the results of our operations. Those two
measures are segment margin and available cash. Our profitably depends to a
significant extent upon our ability to maximize segment margin. Segment margin
is calculated as revenues less costs of sales and operating expense, and does
not include depreciation and amortization. A reconciliation of Segment Margin (a
non-GAAP financial measure) to operating income from continuing operations is
included in our segment disclosures in Note 5 to the consolidated financial
statements. Available Cash is a non-GAAP liquidity measure calculated as net
income with several adjustments, the most significant of which are the
elimination of gains and losses on asset sales, except those from the sale of
surplus assets, the addition of non-cash expenses such as depreciation and
amortization, and the subtraction of maintenance capital expenditures, which are
expenditures to sustain existing cash flows but not to provide new sources of
revenues. For additional information on Available Cash and a reconciliation of
this measure to cash flows from operations, see "Non-GAAP Financial Measure"
below.
OVERVIEW
We operate in three business segments - crude oil gathering and marketing,
crude oil pipeline transportation and CO2 marketing. Our revenues are earned by
selling crude oil and CO2 and by charging fees for transportation of crude oil
through our pipelines. Our focus is on the margin we earn on these revenues,
which is calculated by subtracting the costs of the crude oil, the costs of
transporting the crude oil and CO2 to the customer, and the costs of operating
our assets.
Our primary goal is to generate Available Cash for distribution to our
unitholders. For the first six months of 2004, we have generated $0.6 million
more Available Cash before reserves than the distributions we have paid or are
paying with respect to those six months.
In June 2004, we obtained a new $100 million bank credit facility that
replaced our existing $65 million facility. This facility provides a total of
$50 million for working capital borrowings and letters of credit and $50 million
for acquisitions. This facility provides us with financing for growth
opportunities.
We have a stock appreciation rights plan under which employees and
directors are granted rights to receive cash upon exercise for the difference
between the strike price of the rights and the market price for our units at the
time of exercise. These rights vest over several years. As of June 30, 2004, no
rights were vested. As the market price for our units increases or decreases, we
record an increase or a decrease in our liability under this plan. In the first
half of 2004, our unit price increased 15%. As our unit price rose from $9.80 at
December 31, 2003 to $12.45 per unit at March 31, 2004, we increased our
liability during the first quarter from $0.2 million to $1.3 million, recording
a charge of $1.1 million. In the second quarter of 2004, the unit price declined
from $12.45 at March 31, 2004 to $11.25 per unit at June 30, 2004. As a result,
we reduced our liability to $0.8 million during the second quarter and
recognized a reduction in expense of $0.5 million. In total for the six month
period, we increased the liability by $0.6 million and recorded expense of the
same amount.
RESULTS OF OPERATIONS AND OUTLOOK FOR THE REMAINDER OF 2004 AND BEYOND
CRUDE OIL GATHERING AND MARKETING OPERATIONS
The key drivers affecting our crude oil gathering and marketing
segment margin include production volumes, volatility of P-Plus, volatility of
grade differentials, inventory management, field operating costs, and credit
costs.
-18-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Segment margins from gathering and marketing operations are a
function of volumes purchased and the difference between the price of crude oil
at the point of purchase and the price of crude oil at the point of sale, minus
the associated costs of aggregation and transportation. The absolute price
levels for crude oil do not necessarily bear a relationship to segment margin as
absolute price levels normally impact revenues and cost of sales by equivalent
amounts. Because period-to-period variations in revenues and cost of sales are
not generally meaningful in analyzing the variation in segment margin for
gathering and marketing operations, such changes are not addressed in the
following discussion.
Some 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 certain market indices for crude oil. Often the pricing
in a contract to purchase crude oil will consist of the market price component
and a bonus, which is generally a fixed amount ranging from a few cents to
several dollars. Under some contracts, 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 index. This floating index is usually the
price quoted by Platt's for WTI "P-Plus". When the bonus for purchases of crude
oil is fixed and P-Plus floats in the sales contracts, the margin on individual
transactions can vary from month-to-month depending on changes in the P-Plus
component. When the purchase and sale contracts both have bonuses that float
with changes in P-Plus, that margin is generally fixed and our volatility caused
by price changes is reduced.
P-Plus does not consistently move in correlation with the price of
crude oil in the market. P-Plus is affected by numerous factors such as future
expectations for changes in crude oil prices that can cause the variance from
current changes in crude oil prices.
Another factor that can contribute to volatility in our earnings is
inventory management. Generally contracts for the purchase of crude oil will
state that we will buy all of the production for the month from a particular
well. We generally aggregate the volumes purchased from numerous wells and
deliver it into a pipeline where we sell the crude oil to a third party. While
oil producers can make estimates of the volume of oil that their wells will
produce in a month, they cannot state absolutely how much oil will be produced.
Our sales contracts typically state a specific volume to be sold. Consequently,
if a well produces more than expected, we will purchase volumes in a month that
we have not contracted to sell. These volumes are then held as inventory and are
sold in a later month. Should the market price of crude oil decline below its
cost while we have these inventory volumes, we would have to recognize a loss in
our financial statements. Should market prices rise, we will realize a gain when
we sell the unexpected volume of inventory in a later month at higher prices. We
make every effort to limit our exposure to these price fluctuations by
minimizing inventory builds and draws.
Field operating costs primarily consist of the costs to operate our
fleet of 51 trucks used to transport crude oil, and the costs to maintain the
trucks and assets used in the crude oil gathering operation. Approximately 55%
of these costs are variable and increase and decrease with volumetric changes.
Such costs include payroll and benefits (as drivers are paid on a commission
basis based on volumes), maintenance costs for the trucks (as we lease the
trucks under full service maintenance contracts under which we pay a maintenance
fee per mile driven), and fuel costs. Fuel costs also fluctuate based on changes
in the market price of diesel fuel. Fixed costs include the base lease payment
for the vehicle, insurance costs and costs for environmental and safety related
operations.
-19-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Operating results from continuing operations for our crude oil
gathering and marketing segment were as follows:
Three Months Ended June 30, Six Months Ended June 30,
2004 2003 2004 2003
------------ ----------- ------------ ------------
(in thousands, except volumes per day)
Revenues ........................................... $ 225,872 $ 143,149 $ 418,868 $ 314,842
Crude oil costs...................................... 220,751 137,366 409,698 303,427
Field operating costs................................ 3,195 2,716 6,238 5,558
Change in fair value of derivatives.................. (18) - (18) -
------------ ----------- ------------ ------------
Segment margin.................................... $ 1,944 $ 3,067 $ 2,950 $ 5,857
============ =========== ============ ============
Volumes per day from continuing operations:
Crude oil wellhead - barrels...................... 49,128 42,701 48,787 44,276
Crude oil total - barrels......................... 65,164 53,697 62,877 54,998
Crude oil gathering and marketing segment margins from continuing
operations decreased $1.1 million or 37% for the three months ended June 30,
2004, as compared to the three months ended June 30, 2003. Contributing to this
reduction in segment margin were three primary factors as follows:
- A $1.6 million decrease in the average difference between the
price of crude oil at the point of purchase and the price of
crude oil at the point of sale. During the second half of
2003, we changed the pricing structure on a significant
portion of our wellhead volume purchase contracts from a fixed
bonus to a bonus that floats with changes in P-Plus in order
to reduce volatility in segment margin to changes in P-Plus.
We realized larger margins on these volumes during the first
two months of the second quarter of 2003 when P-Plus prices
increased more than the fixed price bonuses.
- A $0.5 million increase in field operating costs, from
increased fuel costs to operate our tractor/trailers,
additional employee compensation and benefit costs due to
additional volumes, and higher insurance costs. Although we
reduced operations in 2004 from 2003 levels with the sale of a
large part of our Texas operations, our insurance costs did
not decline proportionately. Competitive pressures made it
difficult to reduce crude oil purchase prices to offset the
increases in field operating costs.
- A reduction in crude oil inventory volumes during 2003, at a
time when posted prices and P-Plus were rising, contributed
$0.2 million to 2003 segment margin that did not recur in
2004.
Partially offsetting these decreases was a 21% increase in wellhead,
bulk and exchange purchase volumes between the second quarters of 2003 and 2004,
resulting in a $1.2 million increase in segment margin.
For the six month periods, crude oil gathering and marketing segment
margins from continuing operations decreased $2.9 million in 2004 from the prior
year period. Contributing to this reduction in segment margin were the following
three factors:
- A $2.8 million decrease in the average difference between the
price of crude oil at the point of purchase and the price of
crude oil at the point of sale;
- A $0.7 million increase in field operating costs, again from
higher fuel costs, higher employee costs and higher insurance
costs; and
- A reduction in crude oil inventory volumes of 130,000 barrels
in 2003 from December 31, 2002 volumes, at a time when posted
prices rose over $3 per barrel and P-Plus rose over $1 per
barrel. The sale of this inventory in the 2003 first quarter
contributed more than $1.0 million to 2003 in segment margin.
There was no such inventory sale in the 2004 period.
-20-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Partially offsetting this decrease was an increase in purchase
volumes. Volumes increased 7,879 barrels per day, or 15%, adding $1.6 million to
segment margin. Volumes purchased at the wellhead contributed 4,511 barrels per
day of that increase.
Outlook
We expect volatility in our gathering and marketing segment margins
to continue. During 2004, we expect our crude oil gathering and marketing
business to generate less segment margin than it did in 2003. Additionally we
are reviewing our costs and operating methods to reduce costs and increase
efficiencies.
Beginning in September 2004, we expect Denbury to begin shipping on
our Mississippi pipeline rather than selling the crude oil to us to ship. After
this point, our relationship with Denbury will primarily be one of providing
transportation services on a fee basis. This change will reduce our crude oil
gathering and marketing volumes and revenues. We do not expect this change to
materially adversely affect segment gross margin.
CRUDE OIL PIPELINE OPERATIONS
We operate three common carrier pipeline systems in a five state
area. We refer to these pipelines as our Texas System, Mississippi System and
Jay System. Average volumes shipped on these systems for the three months and
six months ended June 30, 2004 and 2003 are as follows:
Three Months Ended June 30, Six Months Ended June 30,
2004 2003 2004 2003
------------ ----------- ------------ ------------
(barrels per day)
Texas - continuing operations........................ 39,672 45,850 40,939 44,521
Florida ............................................ 15,523 13,723 15,702 14,485
Mississippi.......................................... 11,961 8,133 11,228 8,711
Volumes on our Texas System averaged 39,672 barrels per day during
the second quarter of 2004. The crude oil that enters our system comes to us at
West Columbia where we have a connection to TEPPCO's South Texas System and at
Webster where we have connections to two other pipelines. One of these
connections at Webster is with ExxonMobil Pipeline and is used to receive
volumes that originate from TEPPCO's pipelines. Under the terms of our 2003 sale
of portions of the pipeline to TEPPCO, we have a joint tariff with TEPPCO
through September 2004 under which we earn $0.40 per barrel on the majority of
the barrels we deliver to the shipper's facilities and $0.50 per barrel on
heavier crude oil we deliver. The volumes received from ExxonMobil's pipeline
are subject to a joint tariff with TEPPCO and ExxonMobil. Most of the volume
being shipped on our Texas System goes to three refineries on the Texas Gulf
Coast. We are still transporting approximately 90% of the volumes that we were
shipping before the sale to TEPPCO, however our tariff revenue is much less than
before the sale, as we ship the crude oil over a shorter distance.
The Mississippi System is best analyzed in two segments. The first
segment is the portion of the pipeline that begins in Soso, MS and extends to
Liberty, MS. At Liberty, shippers can transfer the crude oil to a connection to
Capline, a pipeline system that moves crude oil from the Gulf Coast to
refineries in the Midwest. The segment from Soso to Liberty has been improved to
handle the increased volumes produced by Denbury and transported on the
pipeline. In order to handle future increases in production volumes in the area
that are expected, we have made capital expenditures for tank, station and
pipeline improvements and we intend to make further improvements. See Capital
Expenditures under "Liquidity and Capital Resources" below.
The second segment of the pipeline from Liberty to near Baton Rouge,
LA has been out of service since February 1, 2002. A connecting carrier tested
its pipeline and decided not to reactivate its pipeline at this time. During the
second quarter of 2004 we displaced the crude oil in this segment with inhibited
water until the connecting carrier either repairs its system or we identify an
alternative use for this segment. In 2004 and 2003, this segment made no
contribution to pipeline revenues. Any future plans for this segment will
require sufficient economic activity to justify the costs to perform integrity
testing as required under integrity management program
-21-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
regulations and upgrades that may be necessary as a result of that testing.
Future plans for this segment may include connecting the segment to alternative
transportation services or selling the right-of-way to other parties.
The Jay pipeline system in Florida/Alabama ships crude oil from
fields with relatively short remaining production lives. Volumes between the
first halves of 2004 and 2003 have increased approximately 1,200 barrels per
day, due to increases in production in one field connected to the pipeline.
Historically, the largest operating costs in our crude oil pipeline
segment have consisted of personnel costs, power costs, maintenance costs and
costs of regulatory compliance. Some of these costs are not predictable, such as
failure of equipment, or are not within our control, like power cost increases.
We perform regular maintenance on our assets to keep them in good operational
condition to minimize cost increases.
Operating results from continuing operations for our crude oil
pipeline segment were as follows:
Three Months Ended June 30, Six Months Ended June 30,
2004 2003 2004 2003
------------ ----------- ------------ ------------
(in thousands, except volumes per day)
Revenues ............................................ $ 4,086 $ 3,521 $ 8,171 $ 7,510
Pipeline operating costs............................. 2,429 2,327 4,661 4,805
------------ ----------- ------------ ------------
Segment margin.................................... $ 1,657 $ 1,194 $ 3,510 $ 2,705
============ =========== ============ ============
Volumes per day from continuing operations:
Crude oil pipeline - barrels...................... 67,156 67,706 67,869 67,717
Pipeline segment margin increased $0.5 million or 39% to $1.7
million for the three months ended June 30, 2004, as compared to $1.2 million
for the three months ended June 30, 2003. The increase in pipeline segment
margin is primarily attributable to an increase in pipeline revenues. Revenues
increased $0.4 million in the 2004 second quarter compared to the prior year
period due to the combination of higher tariffs, offset by a slight decline in
volume. Higher crude oil prices increased the sales price of volumetric gain
volumes, resulting in an increase of $0.2 million in revenues.
For the six months ended June 30, 2004, pipeline segment margin
increased $0.8 million or 30%, as compared to the same period in 2003. Revenues
increased due to higher tariffs in the 2004 period, which contributed $0.3
million. An increase in volumes of 152 barrels per day provided additional
revenues of $0.1 million. Higher sales prices for crude oil, which increased the
revenues from volumetric gain barrels, resulted in a $0.3 million increase in
revenues.
Outlook
Through September 2004, we will continue to receive a tariff of
$0.40 on the volumes shipped from the ExxonMobil connection in Texas. After
September 2004, we expect to receive less tariff income from those shipments
than we are receiving under the current joint tariff with TEPPCO and ExxonMobil.
The light crude oil volumes that we currently receive from TEPPCO at
West Columbia are expected to be received through the ExxonMobil connection at
Webster after September 2004. We are currently reviewing the costs for testing,
repairs and system modifications to continue to use the West Columbia to Webster
segment for transportation of heavy crude oil. We expect to complete that
evaluation during the third quarter. We are also examining strategic
opportunities to place the remaining segments in alternative service after the
arrangement with TEPPCO expires.
We anticipate that volumes on the Texas System may decline as
refiners on the Texas Gulf Coast compete for crude oil with other markets
connected to TEPPCO's pipeline systems.
Denbury is the largest oil and gas producer in Mississippi. Our
Mississippi pipeline is adjacent to several of Denbury's existing and
prospective oil fields. There are mutual benefits to Denbury and us due to this
common production and transportation area. As Denbury continues to acquire and
develop old oil fields using CO2 based
-22-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
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. Beginning in September 2004, we expect Denbury to begin
shipping on our Mississippi pipeline rather than selling the crude oil to us to
ship. We are also restructuring our Mississippi tariffs to provide additional
return on the investments we have made and will continue to make in the
Mississippi System.
The production shipped from oil fields surrounding our Jay system
comes from a combination of new fields with estimated short production lives and
older fields that have been producing for twenty to thirty years and are in the
later stages of their economic lives. We believe that the highest and best use
of the Jay system would be to convert it to natural gas service. We continue to
review strategic alternatives to develop this opportunity. This initiative is in
a very preliminary stage. Part of the process will involve finding alternative
methods for us to continue to provide crude oil transportation services in the
area. While we believe this initiative has long-term potential, it is not
expected to have a substantial impact on us during 2004 or 2005.
Pipeline segment margins from continuing operations for 2004 should
improve over margins for the 2003 period. We expect volume increases on the
Mississippi system and the tariff increases on the Jay and Mississippi systems
to substantially offset increases in fixed costs, including the costs for
testing under the integrity management program.
CARBON DIOXIDE (CO2) OPERATIONS
In November 2003, we acquired a volumetric production payment of
167.5 Bcf of CO2 from Denbury. Denbury owns 1.6 trillion cubic feet of estimated
proved reserves of CO2 in the Jackson Dome area near Jackson, Mississippi. In
addition to the production payment, Denbury also assigned to us three of their
existing long-term CO2 contracts with industrial customers. Denbury owns the
pipeline that is used to transport the CO2 to our customers as well as to its
own tertiary recovery operations.
The industrial customers treat the CO2 and transport it to their own
customers. The primary industrial applications of CO2 by these customers include
beverage carbonation and food chilling and freezing. Based on Denbury's
experience, we can expect some seasonality in our sales of CO2, as the dominant
months for beverage carbonation and freezing food are from April to October,
when warm weather drives up demand for beverages and the approaching holidays
increase demand for frozen foods.
Operating results from continuing operations for our CO2 marketing
segment were as follows:
Three Months Ended June 30, Six Months Ended June 30,
2004 2003 2004 2003
------------ ----------- ------------ ------------
(in thousands, except volumes per day)
Revenues ............................................ $ 2,149 $ - $ 3,980 $ -
CO2 transportation and other costs................... 688 - 1,279 -
------------ ----------- ------------ ------------
Segment margin.................................... $ 1,461 $ - $ 2,701 $ -
============ =========== ============ ============
Volumes per day from continuing operations:
CO2 marketing - Mcf............................... 45,480 - 42,164 -
Volumes sold by Denbury during the three months and six months ended
June 30, 2003 under the contracts that we acquired averaged 42,223 and 39,819
Mcf per day. The increase in volume in the second quarter was expected due to
the seasonality discussed above. We paid Denbury $0.16 per Mcf, or $0.7 million
for the three months and $1.2 million for the six months, to transport the CO2
to our customers on Denbury's pipeline.
Outlook
We expect to generate approximately $5.0 million of annual segment
margin from this business during each of the first five years. The purchase of
these assets provides us with diversity in our asset base and a stable long-term
source of cash flow. The remaining volume due under the production payment at
June 30, 2004, was 155.0 Bcf.
-23-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
DISCONTINUED OPERATIONS
In the fourth quarter of 2003, we sold a significant portion of our
Texas Pipeline System and related crude oil gathering and marketing operations
to TEPPCO Crude Oil, L.P. Additionally we sold other segments of our Texas
Pipeline System that had been idled in 2002 to Blackhawk Pipeline, L.P., an
affiliate of Multifuels, Inc. Other remaining segments not sold to these parties
were abandoned in place.
During the three and six months ended June 30, 2004, we incurred
costs totaling $0.1 million and $0.3 million, respectively, related to the
dismantlement of assets that we abandoned. During the three and six months ended
June 30, 2003, the assets we sold during the fourth quarter of 2003 generated
$1.1 million and $1.6 million of segment margin, respectively.
OTHER COSTS AND INTEREST
General and administrative expenses were as follows:
Three Months Ended June 30, Six Months Ended June 30,
2004 2003 2004 2003
------- ------- ------- -------
(in thousands)
Expenses excluding effect of stock appreciation
rights plan ....................................... $ 2,534 $ 2,359 $ 4,594 $ 4,636
Stock appreciation rights plan expense (credit) ..... (512) - 592 -
------- ------- ------- -------
Total general and administrative expenses ......... $ 2,022 $ 2,359 $ 5,186 $ 4,636
======= ======= ======= =======
General and administrative expenses, excluding the effects of our
stock appreciation rights (SAR) plan, increased $0.2 million in the 2004 second
quarter as compared to these costs in the 2003 period. In the second quarter of
2004, we incurred expenses of $0.4 million for professional services to assist
us in the internal control documentation and assessment provisions of the
Sarbanes-Oxley Act. Offsetting this increase was a decline in the amount accrued
for the quarter under our employee bonus plan.
For each of the six months ended June 30, 2004 and 2003, general and
administrative expenses excluding the effects of our SAR plan were $4.6 million.
While we incurred costs of $0.5 million in the six month 2004 period related to
the internal control documentation project, we reduced bonus plan expense by
$0.2 million. Legal fees were $0.3 million less in the 2004 period, primarily
due to a charge that we took in the 2003 period for unamortized legal and
consultant costs related to a credit facility that was replaced.
During the second quarter of 2004, we reduced by $0.5 million the
expense recorded in the first quarter related to our SAR plan for employees and
directors in the first quarter of 2004. This plan is a long-term incentive plan
whereby rights are granted for the grantee to receive cash equal to the
difference between the grant price and Common Unit price at date of exercise.
The rights vest over several years. Our unit price rose 27% from $9.80 at
December 31, 2003 to $12.45 at March 31, 2004 resulting in a $1.1 million
increase to the accrual for this liability in the first quarter of 2004. The
unit price declined to $11.25 at June 30, 2004, resulting in the reduction in
expense in the second quarter. For the year total expense related to the SAR
plan is $0.6 million.
Excluding the effect of changes in our unit price on our accrual for
our stock appreciation rights plan, we expect general and administrative
expenses in 2004 to be higher than those of 2003, primarily due to the increased
costs for consultants to assist in the internal control documentation project
and fees related to the audit of those internal controls.
-24-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Interest expense, net was as follows:
Three Months Ended June 30, Six Months Ended June 30,
2004 2003 2004 2003
----- ----- ----- -----
(in thousands)
Interest expense, including commitment fees .... $ 258 $ 91 $ 378 $ 185
Amortization and write-off of facility fees .... 74 74 148 530
Interest income ................................ (4) (7) (28) (15)
----- ----- ----- -----
Net interest expense ......................... $ 328 $ 158 $ 498 $ 700
===== ===== ===== =====
Interest expense increased in the three and six months ended June
30, 2004 as compared to the same periods in 2003 due to variances in outstanding
debt, the increased commitment beginning June 1, 2004, and differences in rates.
The amortization of facility fees in the 2003 six month period
included the write-off of facility fees related to a credit agreement that was
replaced in March 2003.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL RESOURCES
In June 2004, we replaced our existing bank credit facility with a
group of banks led by Fleet National Bank as agent with a $100 million senior
secured bank credit facility (New Credit Facility) with a group of five lenders
including three of the previous banks. The New Credit Facility consists of a $50
million revolving line of credit for acquisitions and a $50 million working
capital revolving credit facility. The facility matures in June 2008.
The working capital portion of the New Credit Facility has a
sub-limit of $15 million for working capital loans with the remainder of the $50
million portion available for letters of credit.
Interest rates and fees under the New Credit Facility are slightly
better than the terms of the prior facility.
At June 30, 2004 we had borrowed $5.5 million under the working
capital portion of the New Credit Facility and had no obligations outstanding
under the acquisitions portion. Due to the revolving nature of loans under the
New Credit Facility, additional borrowings and periodic repayments and
re-borrowings may be made until the maturity date of June 1, 2008. At June 30,
2004, we had letters of credit outstanding under the New Credit Facility
totaling $20.6 million, comprised of $10.0 million and $9.8 million for crude
oil purchases related to June 2004 and July 2004, respectively and $0.8 million
related to other business obligations. Outstanding letters of credit issued to
Denbury for the purchase of crude oil at June 30, 2004, totaled $10.7 million,
and are included in the $20.6 million total above. When we no longer purchase
the crude oil from Denbury for shipment and Denbury begins shipping the oil on
our Mississippi System in the third quarter of 2004, we will no longer provide
Denbury with letters of credit.
-25-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
CAPITAL EXPENDITURES
A summary of our capital expenditures in the six months ended June
30, 2004 and 2003 is as follows:
Six Months Ended June 30,
-----------------------------
2004 2003
----------- ------------
(in thousands)
Maintenance capital expenditures:
Texas pipeline system................................................. $ 86 $ 1,366
Mississippi pipeline system........................................... 240 1,068
Jay pipeline system................................................... 9 184
Crude oil gathering assets............................................ - 144
Administrative assets................................................. 75 178
----------- ------------
Total maintenance capital expenditures............................. 410 2,940
Growth capital expenditures:
Mississippi pipeline system........................................... 1,069 -
Crude oil gathering assets............................................ - 569
----------- ------------
Total growth capital expenditures.................................. 1,069 569
----------- ------------
Total capital expenditures...................................... $ 1,479 $ 3,509
=========== ============
Maintenance capital expenditures in 2004 included station
improvements in Mississippi to handle increased volumes. Administrative assets
included computer software and hardware. In the 2003 period, maintenance capital
expenditures included installation of pipeline satellite monitoring equipment
and an upgrade to the West Columbia to Markham segment of our Texas pipeline.
The expenditures on the Mississippi system included additional improvements to
the pipeline from Soso to Gwinville, where the crude release had occurred in
December 1999, to restore this segment to service. In 2003, we also improved the
pipeline from Gwinville to Liberty to be able to handle increased volumes on
that segment by upgrading pumps and meters and completing additional tankage.
Growth capital expenditures in 2004 related to the acquisition of
right-of-way and the initial construction costs for a ten mile extension of our
crude oil pipeline and a CO2 pipeline extending from Denbury's CO2 pipeline to
Brookhaven field. This extension should be complete during the fourth quarter of
2004. We also started construction of a tank and initial right-of-way work
related to an extension from our existing crude oil pipeline to move crude oil
from Denbury's Smithdale/McComb fields. Growth capital expenditures in 2003
included the acquisition of a condensate storage facility in Texas that was
subsequently sold to TEPPCO.
Including the amounts expended through June 30, 2004 and based on
the information available to us at this time, we currently anticipate that our
maintenance capital expenditures will be as follows for the periods shown:
2004 2005 2006
---- ---- ----
(in thousands)
Maintenance capital expenditures:
Texas System........................... $ 88 $ 396 $ 199
Mississippi System..................... 817 685 465
Jay System............................. 39 145 75
Other.................................. 167 60 60
-------- --------- ---------
Total maintenance capital expenditures...... $ 1,111 $ 1,286 $ 799
======== ========= =========
In 2004, we expect the expenditures on our Texas system to relate
primarily to corrosion control and in 2005 and 2006, to improvements to our
control and monitoring system.
-26-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
The maintenance capital expenditure estimates for our Mississippi
system include corrosion control expenditures, minor facility improvements and
rehabilitation of the pipeline as a result of integrity management test results.
We have made commitments totaling $4.6 million related to the
construction of the pipelines to the Brookhaven field and the construction of
facilities related to the Smithdale/McComb project in Mississippi. Including
estimates of the other costs to complete the projects, we expect the total costs
of these two projects to be $7.7 million. Through June 30, 2004, we have
expended $1.0 million toward these projects. We are also in discussions to
acquire another CO2 production payment and industrial sales contract from
Denbury. We expect to fund these capital expenditures from our New Credit
Facility.
Expenditures for capital assets to grow the partnership distribution
will depend on our access to debt and capital discussed below in "Sources of
Future Capital." Denbury owns additional CO2 industrial sales contracts that we
may be able to purchase along with additional volume under our production
payment. We may also construct and operate additional CO2 pipelines next to
crude oil pipelines to supply Denbury's fields with the CO2 for tertiary
recovery and then to move the resulting crude oil production to market. We will
also look for opportunities to acquire assets from other parties that meet our
criteria for stable cash flows.
SOURCES OF FUTURE CAPITAL
Prior to 2003, we funded our capital commitments from operating cash
and borrowings under bank facilities. In 2003, we issued common units to our
general partner for cash and sold assets to fund growth. Our plans for the
future include a combination of borrowings and the issuance of additional common
units to the public.
The New Credit Facility provides us with $50 million of capacity for
acquisitions. We expect to use our acquisition facility for the projects
discussed under Capital Expenditures as well as other future projects. The
acquisition portion of the New Credit Facility is a revolving facility.
CASH FLOWS
Our primary sources of cash flows are operations and credit
facilities. Our primary uses of cash flows are capital expenditures and
distributions. A summary of our cash flows is as follows:
Six Months Ended June 30,
-----------------------------
2004 2003
----------- ------------
(in thousands)
Cash provided by (used in):
Operating activities.................................................. $ 5,464 $ 6,249
Investing activities.................................................. $ (1,411) $ (3,424)
Financing activities.................................................. $ (5,190) $ (1,033)
Operating. Net cash from operating activities for each period have
been comprised of the following:
Six Months Ended June 30,
-----------------------------
2004 2003
----------- ------------
(in thousands)
Net income............................................................ $ 94 $ 2,769
Depreciation and amortization......................................... 3,174 2,884
Gain on sales of assets............................................... (75) (47)
Other non-cash items.................................................. 768 880
Changes in components of working capital, net......................... 1,503 (237)
----------- ------------
Net cash from operating activities................................. $ 5,464 $ 6,249
=========== ============
Our operating cash flows are affected significantly by changes in
items of working capital. Affecting all periods is the timing of capital
expenditures and their effects on our recorded liabilities.
-27-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
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 $77.2 million aggregate
receivables on our consolidated balance sheet at June 30, 2004, approximately
$75.0 million, or 97%, were less than 30 days past the invoice date.
Investing. Cash flows used in investing activities in the first half
of 2004 were $1.4 million as compared to $3.4 million in 2003 period. As
discussed above, in 2004 we expended cash for the first phase of an addition to
our Mississippi System. We also expended funds to begin construction of a new
tank on the Mississippi System. We expended cash for other capital improvements
related to our corporate office and to handling the increased volumes on our
Mississippi System more efficiently. We received $0.1 million from the sale of
surplus assets.
In the first half of 2003 we expended $3.5 million for property and
equipment additions, and received $0.1 million from the sale of surplus assets.
The expenditures included replacement of pipe in Texas and satellite
communication equipment for our control and monitoring system for all three of
our pipelines, as well as improvements on the Mississippi System.
Financing. In the first half of 2004, financing activities utilized
net cash of $5.2 million. Our outstanding debt decreased $1.5 million.
Distributions to our partners utilized $2.9 million. We also incurred $0.8
million of costs related to our new credit facility.
Net cash expended for financing activities was $1.0 million in the
first half of 2003. In 2003 we reduced our outstanding long-term debt balance by
$0.5 million from the balance at December 31, 2002. We also paid $1.1 million in
credit facility issuance costs related to a credit facility put in place in
March 2003 and we paid distribution to our partners totaling $0.4 million.
DISTRIBUTIONS
As a master limited partnership, the key consideration of our
Unitholders is the amount of our distribution, its reliability and the prospects
for distribution growth. Normally we distribute 100% of our Available Cash
within 45 days after the end of each quarter to Unitholders of record and to the
General Partner. Available Cash consists generally of all of our cash receipts
less cash disbursements adjusted for net changes to reserves. The targeted
minimum quarterly distribution (MQD) for each quarter is $0.20 per unit.
Beginning with the distribution for the first quarter of 2003, we paid a regular
quarterly distribution of $0.05 per unit ($0.4 million in total per quarter).
For the fourth quarter of 2003, we increased our quarterly distribution to $0.15
per unit ($1.4 million in total), and have distributed $0.15 per unit for each
subsequent quarter.
We have no limitations on making distributions in our New Credit
Agreement, except as to the effects of distributions in covenant calculations.
The New Credit Agreement requires we maintain a cash flow coverage ratio of 1.1
to 1.0. In general, this calculation compares operating cash inflows, as
adjusted in accordance with the new Fleet Agreement, less maintenance capital
expenditures to the sum of interest expense and distributions. At June 30, 2004,
the calculation resulted in a ratio of 1.2 to 1.0.
Our general partner is entitled to receive incentive distributions
if the amount we distribute with respect to any quarter exceeds levels specified
in our partnership agreement. Under the quarterly incentive distribution
provisions, the general partner generally is entitled to receive 13.3% of any
distributions in excess of $0.25 per unit, 23.5% of any distributions in excess
of $0.28 per unit and 49% of any distributions in excess of $0.33 per unit
without duplication. We have not paid any incentive distributions through
December 31, 2003. The likelihood and timing of the payment of any incentive
distributions will depend on our ability to make accretive acquisitions and
generate cash flows from those acquisitions. We do not expect to make incentive
distributions during 2004.
We believe we will be able to sustain a regular quarterly
distribution at $0.15 per unit during 2004. We do not expect to be able to
restore the distribution to the targeted minimum quarterly distribution level of
$0.20 per unit until 2005. However, our ability to restore the distribution to
the targeted minimum quarterly distribution may depend in part on our success at
developing and executing capital projects and making accretive acquisitions.
-28-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Available Cash before reserves for the three and six months ended
June 30, 2004, is as follows (in thousands):
Three Six
Months Months
Ended Ended
June 30, June 30,
2004 2004
--------- ---------
AVAILABLE CASH BEFORE RESERVES:
Net income........................................................... $ 1,099 $ 94
Depreciation and amortization........................................ 1,627 3,174
Cash proceeds in excess of gains on asset sales...................... 4 4
Net non-cash (credits) charges....................................... (530) 574
Maintenance capital expenditures..................................... (255) (410)
--------- ---------
Available Cash before reserves....................................... $ 1,945 $ 3,436
========= =========
Distributions for the three and six month period total $1.4 million
and $2.9 million, respectively.
Available Cash (a non-GAAP liquidity measure) has been reconciled to
cash flow from operating activities (the GAAP measure) for the three and six
months ended June 30, 2004 below.
We believe that investors benefit from having access to the same
financial measures being utilized by management. Available Cash is a liquidity
measure used by our management to compare cash flows generated by the
Partnership to the cash distribution we pay to our limited partners and the
general partner. This is an important financial measure to our public
unitholders since it is an indicator of our ability to provide a cash return on
their investment. Specifically, this financial measure tells investors whether
or not the Partnership is generating cash flows at a level that can support a
quarterly cash distribution to our partners. Lastly, Available Cash (also
referred to as distributable cash flow) is a quantitative standard used
throughout the investment community with respect to publicly-traded
partnerships.
Several adjustments to net income are required to calculate
Available Cash. These adjustments include: (1) the addition of non-cash expenses
such as depreciation and amortization expense; (2) miscellaneous non-cash
adjustments such as the addition of increases and subtraction of decreases in
the accrual for our stock appreciation rights plan in excess of any actual cash
payments under the plan and changes in the fair value of derivatives; and (3)
the subtraction of maintenance capital expenditures. Maintenance capital
expenditures are capital expenditures (as defined by GAAP) to replace or enhance
partially or fully depreciated assets in order to sustain the existing operating
capacity or efficiency of our assets and extend their useful lives. See
"Distributions" above.
The reconciliation of Available Cash (a non-GAAP liquidity measure)
to cash flow from operating activities (the GAAP measure) for the three and six
months ended June 30, 2004, is as follows:
-29-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Three Six
Months Months
Ended Ended
June 30, June 30,
2004 2004
--------- ---------
Cash flows from operating activities................................. $ 9,067 $ 5,464
Adjustments to reconcile operating cash flows to Available Cash:
Maintenance capital expenditures................................. (255) (410)
Proceeds from asset sales........................................ 79 79
Amortization of credit facility issuance fees.................... (101) (194)
Net effect of changes in working capital accounts not
included in calculation of Available Cash..................... (6,845) (1,503)
--------- ---------
Available Cash before reserves....................................... $ 1,945 $ 3,436
========= =========
COMMITMENTS AND OFF-BALANCE SHEET ARRANGEMENTS
CONTRACTUAL OBLIGATION AND COMMERCIAL COMMITMENTS
In addition to the New Credit Facility discussed above, we have
contractual obligations under operating leases as well as commitments to
purchase crude oil. The table below summarizes our obligations and commitments
at June 30, 2004.
Payments Due by Period
-----------------------------------------------------------------------
Less than 1 - 3 4 - 5 After 5
Contractual Cash Obligations 1 Year Years Years Years Total
- ---------------------------- ------------ ------------ ----------- ------------ ------------
(in thousands)
Long-term Debt................. $ - $ - $ 5,500 $ - $ 5,500
Operating Leases............... 2,835 1,946 1,226 786 6,793
Mississippi oil spill fine..... 3,000 - - - 3,000
Offshore pipeline removal...... 1,130 - - - 1,130
Capital expenditure
commitments................ 6,700 - - - 6,700
Unconditional Purchase
Obligations ............... 100,287 - - - 100,287
------------ ------------ ----------- ------------ ------------
Total Contractual Cash
Obligations................ $ 113,952 $ 1,946 $ 6,726 $ 786 $ 123,410
============ ============ =========== ============ ============
OFF-BALANCE SHEET ARRANGEMENTS
We have no off-balance sheet arrangements, special purpose entities,
or financing partnerships, other than as disclosed in this section, nor do we
have any debt or equity triggers based upon our unit or commodity prices.
NEW ACCOUNTING PRONOUNCEMENTS
For information on new accounting pronouncements see Note 2 to the
consolidated financial statements.
FORWARD LOOKING STATEMENTS
The statements in this Quarterly Report on Form 10-Q that are not
historical information may be "forward looking statements" within the meaning of
the various provisions of the Securities Act of 1933 and the Securities Exchange
Act of 1934. All statements, other than historical facts, included in this
document that address activities,
-30-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
events or developments that we expect or anticipate will or may occur in the
future, including things such as plans for growth of the business, future
capital expenditures, competitive strengths, goals, references to future goals
or intentions and other such references are forward-looking statements. These
statements include, but are not limited to, statements identified by the words
"anticipate," "believe," "estimate," "expect," "plan," or "intend" and similar
expressions and statements regarding our business strategy, plans and objectives
of our management for future operations. These statements are made by us based
on our past experience and our perception of historical trends, current
conditions and expected future developments as well as other considerations we
believe are appropriate under the circumstances. Whether actual results and
developments in the future will conform to our expectations is subject to
numerous risks and uncertainties, many of which are beyond our control. These
risks and uncertainties include general economic conditions, market and business
conditions, opportunities that may be presented and pursued by us or the lack of
such opportunities, competitive actions by other companies in our industries,
changes in laws and regulations, access to capital, and other factors.
Therefore, all the forward-looking statements made in this document are
qualified in their entirety by these cautionary statements, and no assurance can
be made that our goals will be achieved or that expectations regarding future
developments will prove to be correct. Except as required by applicable
securities laws, we do not intend to update these forward-looking statements and
information.
-31-
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Price Risk Management and Financial Instruments
Our primary price risk relates to the effect of crude oil price
fluctuations on its inventories and the fluctuations each month in grade and
location differentials and their effects on future contractual commitments. We
utilize New York Mercantile Exchange (NYMEX) commodity based futures contracts
and forward contracts to hedge our exposure to these market price fluctuations
as needed. At June 30, 2004, the Partnership had entered into a swap agreement
in its hedging program that will be settled in October 2004. Information about
this contract is contained in the table set forth below.
Sell (Short) Buy (Long)
Contracts Contracts
--------- ---------
Crude Oil Inventory:
Volume (1,000 bbls)................................... 34
Carrying value (in thousands)......................... $ 1,109
Fair value (in thousands)............................. $ 1,141
Commodity Swap Agreement:
Contract volumes (1,000 bbls)......................... 62
Weighted average price per bbl........................ $ 37.50
Contract value (in thousands)......................... $ 2,325
Mark-to-market change (in thousands).................. (18)
-----------
Market settlement value (in thousands)................ $ 2,307
===========
The table above presents notional amounts in barrels, the weighted average
contract price, total contract amount 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, 2004 quoted market prices for the applicable
components of the price formula in the contract.
ITEM 4. CONTROLS AND PROCEDURES
We maintain disclosure controls and procedures and internal controls
designed to ensure that information required to be disclosed in our filings
under the Securities Exchange Act of 1934 is recorded, processed, summarized and
reported within the time periods specified in the Securities and Exchange
Commission's rules and forms. Our chief executive officer and chief financial
officer have evaluated our disclosure controls and procedures as of the end of
the period covered by this Quarterly Report on Form 10-Q and have determined
that such disclosure controls and procedures are adequate and effective in all
material respects in providing to them on a timely basis material information
relating to us (including our consolidated subsidiaries) required to be
disclosed in this quarterly report.
There have been no significant changes in our internal controls over
financial reporting during the three months ended June 30, 2004, that have
materially affected, or are reasonably likely to materially affect, our internal
controls over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See Part I. Item 1. Note 11 to the Consolidated Financial Statements
entitled "Contingencies", which is incorporated herein by reference.
-32-
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits.
Exhibit 10.1 Consent Decree with United States of America, The
Mississippi Commission on Environmental Quality, Genesis Energy,
Inc., Genesis Crude Oil, L.P. and Genesis Pipeline USA, L.P.
Exhibit 31.1 Certification by Chief Executive Officer Pursuant to
Rule 13a-14(a) under the Securities Exchange Act of 1934.
Exhibit 31.2 Certification by Chief Financial Officer Pursuant to
Rule 13a-14(a) under the Securities Exchange Act of 1934.
Exhibit 32.1 Certification by Chief Executive Officer Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit 32.2 Certification by Chief Financial Officer Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
(b) Reports on Form 8-K.
A report on Form 8-K was filed on May 4, 2004, which included a
press release of the Partnership's earnings for the quarter ended March 31,
2004.
A report on Form 8-K was filed on June 7, 2004, which included a
press release announcing that the Partnership replaced its existing $65 million
credit facility with a new $100 million facility.
A report on Form 8-K was filed on June 28, 2004, which included a
press release announcing a settlement with the Justice Department, the U.S.
Environmental Protection Agency, and the State of Mississippi for penalties and
natural resource restoration and damages resulting from the Leaf River oil spill
that occurred in Mississippi in December of 1999.
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, 2004 By: /s/ ROSS A. BENAVIDES
-----------------------------------------
Ross A. Benavides
Chief Financial Officer
-33-