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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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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 September 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 - September 30, 2004 and December 31, 2003.................. 3
Consolidated Statements of Operations for the Three and Nine Months Ended
September 30, 2004 and 2003........................................................... 4
Consolidated Statements of Comprehensive (Loss) Income for the Three and Nine
Months Ended September 30, 2004 and 2003.............................................. 5
Consolidated Statements of Cash Flows for the Nine Months Ended September 30,
2004 and 2003......................................................................... 6
Consolidated Statement of Partners' Capital for the Nine Months Ended September 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 2. Unregistered Sales of Equity Securities and Use of Proceeds............................. N/A
Item 3. Defaults Upon Senior Securities......................................................... N/A
Item 4. Submission of Matters to a Vote of Security Holders..................................... N/A
Item 5. Other Information....................................................................... N/A
Item 6. Exhibits................................................................................ 33
SIGNATURES........................................................................................ 33
-2-
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
(Unaudited)
September 30, December 31,
2004 2003
------------- ------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents................................................. $ 905 $ 2,869
Accounts receivable -
Trade.................................................................. 74,536 66,732
Related party.......................................................... 1,101 -
Inventories............................................................... 2,375 1,546
Insurance receivable...................................................... 1,191 15,524
Other..................................................................... 2,117 1,540
------------- -------------
Total current assets................................................... 82,225 88,211
FIXED ASSETS, at cost......................................................... 74,765 70,695
Less: Accumulated depreciation........................................... (38,368) (36,724)
------------- -------------
Net fixed assets....................................................... 36,397 33,971
CO2 ASSETS, net of amortization............................................... 26,999 24,073
OTHER ASSETS, net of amortization............................................. 1,604 860
------------- -------------
TOTAL ASSETS.................................................................. $ 147,225 $ 147,115
============= =============
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable -
Trade.................................................................. $ 78,215 $ 60,108
Related party.......................................................... 534 7,067
Accrued liabilities....................................................... 5,183 20,069
------------- -------------
Total current liabilities.............................................. 83,932 87,244
LONG-TERM DEBT................................................................ 15,000 7,000
COMMITMENTS AND CONTINGENCIES (Note 11)
MINORITY INTERESTS............................................................ 517 517
PARTNERS' CAPITAL
Common unitholders, 9,314 units issued and outstanding.................... 46,813 51,299
General partner........................................................... 963 1,055
------------- -------------
Total partners' capital................................................ 47,776 52,354
------------- -------------
TOTAL LIABILITIES AND PARTNERS' CAPITAL....................................... $ 147,225 $ 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 Nine Months
Ended September 30, Ended September 30,
2004 2003 2004 2003
------------- ------------- -------------- --------------
REVENUES:
Crude oil gathering and marketing......................... $ 244,377 $ 153,441 $ 663,245 $ 468,283
Crude oil pipeline:
Unrelated parties...................................... 3,787 3,653 11,958 11,163
Related parties........................................ 277 - 277 -
CO2 revenues.............................................. 2,295 - 6,275 -
------------- ------------- -------------- --------------
Total revenues......................................... 250,736 157,094 681,755 479,446
COSTS AND EXPENSES:
Crude oil costs:
Unrelated parties...................................... 214,862 136,685 573,161 411,246
Related parties........................................ 25,092 12,738 76,491 41,604
Field operating........................................ 3,473 2,815 9,711 8,373
Crude oil pipeline operating costs........................ 1,463 3,453 6,124 8,258
CO2 transportation costs - related party.................. 752 - 2,031 -
General and administrative................................ 2,639 1,938 7,825 6,574
Depreciation and amortization............................. 2,599 943 5,773 3,085
Net loss (gain) on disposal of surplus assets............. 10 (69) (65) (116)
Change in fair value of derivatives....................... 2 - (16) -
------------- ------------- -------------- --------------
OPERATING (LOSS) INCOME....................................... (156) (1,409) 720 422
OTHER INCOME (EXPENSE):
Interest income........................................... 9 6 37 21
Interest expense.......................................... (212) (162) (738) (877)
-------------- ------------- -------------- --------------
(LOSS) INCOME FROM CONTINUING OPERATIONS...................... (359) (1,565) 19 (434)
(Loss) income from operations of discontinued Texas
System................................................. (35) 352 (319) 1,990
-------------- ------------- -------------- --------------
NET (LOSS) INCOME............................................. $ (394) $ (1,213) $ (300) $ 1,556
============= ============= ============== ==============
NET (LOSS) INCOME PER COMMON UNIT -
BASIC AND DILUTED:
(Loss) income from continuing operations.................. $ (0.04) $ (0.18) $ 0.00 $ (0.05)
Income (loss) income from discontinued operations......... 0.00 0.04 (0.03) 0.23
------------- ------------- -------------- --------------
NET (LOSS) INCOME............................................. $ (0.04) $ (0.14) $ (0.03) $ 0.18
============= ============= ============== ==============
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 (LOSS) INCOME
(In thousands)
(Unaudited)
Three Months Nine Months
Ended September 30, Ended September 30,
2004 2003 2004 2003
------------- ------------- -------------- --------------
NET (LOSS) INCOME............................................. $ (394) $ (1,213) $ (300) $ 1,556
OTHER COMPREHENSIVE INCOME:
Change in fair value of derivatives used for
hedging purposes................................... - - - 39
------------- ------------- -------------- --------------
COMPREHENSIVE (LOSS) INCOME................................... $ (394) $ (1,213) $ (300) $ 1,595
============= ============= ============== ==============
The accompanying notes are an integral part of these
consolidated financial statements.
-5-
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
Nine Months Ended September 30,
2004 2003
---------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income............................................................................. $ (300) $ 1,556
Adjustments to reconcile net (loss) income to net cash provided by operating activities -
Depreciation.............................................................................. 3,976 4,038
Amortization of CO2 contracts and covenant not-to-compete................................. 1,797 206
Amortization and write-off of credit facility issuance costs.............................. 289 903
Change in fair value of derivatives....................................................... (16) 39
Gain on asset disposals................................................................... (65) (190)
Other non-cash charges.................................................................... 564 -
Changes in components of working capital -
Accounts receivable.................................................................... (8,905) 6,082
Inventories............................................................................ (1,679) 4,129
Other current assets................................................................... 13,756 66
Accounts payable....................................................................... 10,338 (8,187)
Accrued liabilities.................................................................... (15,476) (307)
---------- ----------
Net cash provided by operating activities....................................................... 4,279 8,335
---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment........................................................... (4,493) (4,136)
CO2 contract acquisition...................................................................... (4,702) -
Change in other assets........................................................................ (13) (100)
Proceeds from sale of assets.................................................................. 82 236
---------- ----------
Net cash used in investing activities........................................................... (9,126) (4,000)
---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net borrowings of debt........................................................................ 8,000 500
Credit facility issuance fees................................................................. (839) (1,093)
Distributions to common unitholders........................................................... (4,192) (862)
Distributions to General Partner.............................................................. (86) (18)
---------- ----------
Net cash provided by (used in) financing activities............................................. 2,883 (1,473)
---------- ----------
Net (decrease) increase in cash and cash equivalents............................................ (1,964) 2,862
Cash and cash equivalents at beginning of year.................................................. 2,869 1,071
---------- ----------
Cash and cash equivalents at end of period...................................................... $ 905 $ 3,933
========== ==========
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 loss for the nine months ended September 30, 2004.... - (294) (6) (300)
Distributions to partners during the nine months ended
September 30, 2004 .................................... - (4,192) (86) (4,278)
--------- ----------- -------- --------
Partners' capital at September 30, 2004 ................. 9,314 $ 46,813 $ 963 $ 47,776
========= =========== ======== ========
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
three subsidiary partnerships, Genesis Pipeline Texas, L.P., Genesis Pipeline
USA, L.P. and Genesis CO2 Pipeline, 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 September 30, 2004 and December 31, 2003
for GELP, its results of operations and changes in comprehensive income for the
three and nine months ended September 30, 2004 and 2003, and its cash flows and
changes in partners' capital for the nine months ended September 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 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%. The rate can fluctuate daily. At
September 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%. The rate can fluctuate daily. At September 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%. The rate can
fluctuate daily. At September 30, 2004, we borrowed at the prime rate
plus 1.50% 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 September 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. The
Borrowing Base is limited to $50 million and is calculated monthly.
At September 30, 2004, the Borrowing Base was $34.2 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 September 30, 2004, we had $8.9 million outstanding under the working
capital portion and $6.1 million outstanding under the acquisition portion of
the New Credit Facility. Due to the revolving nature of loans under both
portions of the New Credit Facility, additional borrowings and periodic
repayments and re-borrowings may be made until the maturity date of June 1,
2008. At September 30, 2004, we had letters of credit outstanding under the New
Credit Facility totaling $15.3 million, comprised of $6.5 million and $8.0
million for crude oil purchases related to September 2004 and October 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 September 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 September 30, 2004, a total of 9,313,811 Common
Units and the general partner interest of 2% 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 September 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 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
for the quarter). We have declared a $0.15 per unit distribution for the third
quarter of 2004, payable on November 12, 2004 to unitholders of record on
November 3, 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 never paid any incentive distributions.
-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 Nine Months
Ended September 30, Ended September 30,
2004 2003 2004 2003
------- ------- ------- -------
(in thousands, except per unit amounts)
Numerators for basic and diluted net income per common unit:
Income (loss) from continuing operations ............ $ (359) $(1,565) $ 19 $ (434)
Less general partner 2% ownership ................... (8) (31) - (9)
------- ------- ------- -------
Income (loss) from continuing operations available
for common unitholders .......................... $ (351) $(1,534) $ 19 $ (425)
======= ======= ======= =======
(Loss) income from discontinued operations .......... $ (35) $ 352 $ (319) $ 1,990
Less general partner 2% ownership ................... - 7 (6) 40
------- ------- ------- -------
(Loss) income from discontinued operations available
for common unitholders .......................... $ (35) $ 345 $ (313) $ 1,950
======= ======= ======= =======
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 (loss) from continuing operations ............ $ (0.04) $ (0.18) $ 0.00 $ (0.05)
Income (loss) from discontinued operations .......... 0.00 0.04 (0.03) 0.23
------- ------- ------- -------
Net income (loss) ................................... $ (0.04) $ (0.14) $ (0.03) $ 0.18
======= ======= ======= =======
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 September 30, 2004
Revenues:
External Customers ...................... $244,377 $ 2,877 $ 2,295 $249,549
Intersegment (a) ........................ - 1,187 - 1,187
-------- -------- -------- --------
Total revenues of reportable segments ... $244,377 $ 4,064 $ 2,295 $250,736
======== ======== ======== ========
Segment margin excluding depreciation and
amortization (b) ..................... $ 948 2,601 $ 1,543 $ 5,092
Capital expenditures .................... $ 56 $ 4,173 $ 4,723 $ 8,952
Maintenance capital expenditures ........ $ 56 $ 161 $ - $ 217
Three Months Ended September 30, 2003
Revenues:
External Customers ...................... $153,441 $ 2,992 $ - $156,433
Intersegment (a) ........................ - 661 - 661
-------- -------- -------- --------
Total revenues of reportable segments ... $153,441 $ 3,653 $ - $157,094
======== ======== ======== ========
Segment margin excluding depreciation and
amortization (b) ..................... $ 1,203 $ 200 $ - $ 1,403
Capital expenditures .................... $ 206 $ 259 $ - $ 465
Maintenance capital expenditures ........ $ 206 $ 259 $ - $ 465
Nine Months Ended September 30, 2004
Revenues:
External Customers ...................... $663,245 $ 9,346 $ 6,275 $678,866
Intersegment (a) ........................ - 2,889 - 2,889
-------- -------- -------- --------
Total revenues of reportable segments ... $663,245 $ 12,235 $ 6,275 $681,755
======== ======== ======== ========
Segment margin excluding depreciation and
amortization (b) ..................... $ 3,898 6,111 $ 4,244 $ 14,253
Capital expenditures .................... $ 131 $ 5,577 $ 4,723 $ 10,431
Maintenance capital expenditures ........ $ 131 $ 496 $ - $ 627
Net fixed and other long-term
assets ............................... $ 6,376 $ 31,465 $ 27,159 $ 65,000
Nine Months Ended September 30, 2003
Revenues:
External Customers ...................... $468,283 $ 8,675 $ - $476,958
Intersegment (a) ........................ - 2,488 - 2,488
-------- -------- -------- --------
Total revenues of reportable segments ... $468,283 $ 11,163 $ - $479,446
======== ======== ======== ========
Segment margin excluding depreciation and
amortization (b) ..................... $ 7,060 2,905 $ - $ 9,965
Capital expenditures .................... $ 528 $ 1,636 $ - $ 2,164
Maintenance capital expenditures ........ $ 528 $ 1,636 $ - $ 2,164
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 Nine Months
Ended September 30, Ended September 30,
2004 2003 2004 2003
-------- -------- -------- --------
(in thousands)
Segment margin excluding depreciation and amortization... $ 5,092 $ 1,403 $ 14,253 $ 9,965
General and administrative expenses ..................... 2,639 1,938 7,825 6,574
Depreciation, amortization and impairment ............... 2,599 943 5,773 3,085
Net loss (gain) on disposal of surplus assets ........... 10 (69) (65) (116)
-------- -------- -------- --------
Operating (loss) income from continuing operations ...... $ (156) $ (1,409) $ 720 $ 422
======== ======== ======== ========
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 three
quarters of 2004 are included in discontinued operations. For the three and nine
months ended September 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 nine
months ended September 30, 2004 and 2003 were as follows:
Three Months Nine Months
Ended September 30, Ended September 30,
2004 2003 2004 2003
--------- --------- --------- ---------
(in thousands)
Revenues:
Crude oil gathering and marketing ...................... $ - $ 80,229 $ - $ 235,883
Crude oil pipeline ..................................... - 1,708 - 5,533
--------- --------- --------- ---------
Total revenues ...................................... - 81,937 - 241,416
Costs and expenses:
Crude oil costs ........................................ - 78,241 - 229,417
Field operating costs .................................. - 1,589 8 4,198
Crude oil pipeline operating costs ..................... 35 1,356 311 4,497
General and administrative ............................. - 56 - 229
Depreciation and amortization .......................... - 417 - 1,159
Gain on disposition of fixed assets .................... - (74) - (74)
--------- --------- --------- ---------
Total costs and expenses ............................ 35 81,585 319 239,426
--------- --------- --------- ---------
(Loss) income from operations from discontinued Texas System
before minority interests ............................. $ (35) $ 352 $ (319) $ 1,990
========= ========= ========= =========
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 nine months ended September
30, 2004 and 2003 were $76.5 million and $41.6 million, respectively.
Transportation of Crude Oil
Beginning September 1, 2004, Denbury began transporting its crude oil on
our pipeline for its own account and marketing it to third parties. Prior to
this date, we purchased Denbury's Mississippi production at the wellhead.
Charges to Denbury for transportation services by truck and pipeline for the
month of September 2004 were $0.3 million.
CO2 Volumetric Production Payment and Transportation
We acquired a volumetric production payment from Denbury in November 2003
for $24.4 million. In September 2004 we acquired a second volumetric production
payment from Denbury for $4.7 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 nine months ended September 30, 2004, we incurred $2.0
million for transportation services related to our sales of CO2.
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 $10.1 million and $11.9 million for
the nine months ended September 30, 2004 and 2003, respectively.
Due to and from Related Parties
At September 30, 2004 and December 31, 2003, we owed Denbury $0.5 million
and $0.1 million, respectively, for CO2 transportation services. Additionally,
we owed Denbury $6.9 million for purchases of crude oil at December 31, 2003.
Denbury owed us $0.4 million at September 30, 2004 for transportation services.
We had advanced $0.7 million to the General Partner at September 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 nine months ended September 30, 2004 and 2003, we paid
$90,000 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.
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.
-14-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 18% and 14% of total revenues for the nine months ended September
30, 2004. Marathon Ashland Petroleum LLC, ExxonMobil Corporation and Shell Oil
Company accounted for 24%, 14% and 11% of total revenues during the first nine
months of 2003. The majority of the revenues from these four customers in both
periods relate to our crude oil gathering and marketing operations.
9. SUPPLEMENTAL CASH FLOW INFORMATION
Cash received by the Partnership for interest was $37,000 and $21,000 for
the nine months ended September 30, 2004 and 2003, respectively. Payments of
interest and commitment fees were $196,000 and $238,000 for the nine months
ended September 30, 2004 and 2003, respectively.
For the nine months ended September 30, 2004, the partnership incurred
liabilities for fixed asset additions totaling $1.3 million that had not been
paid at the end of the quarter and, therefore, are not included in the caption
"Additions to property and equipment" on the Consolidated Statements of Cash
Flows.
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 September 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 September 30,
2004, and recorded income of $16,000 which is included in the consolidated
statement of operations under the caption "Change in Fair Value of Derivatives".
The consolidated balance sheet includes $16,000 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 September 30, 2004 and December 31, 2003.
-15-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. CONTINGENCIES
Guarantees
We have guaranteed $3.6 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 $12.5 million at September 30, 2004, 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 September 30, 2004
were $15.0 million and are reflected in the consolidated balance sheet. To the
extent liabilities exist under the letters of credit, such liabilities are
included in the consolidated balance sheet.
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 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
September 30, 2004 and December 31, 2003 is $1.2 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, and was paid in the third quarter of
2004. The fines were not 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.
-16-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, we
currently 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.
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 October 22, 2004, the Board of Directors of the General Partner
declared a cash distribution of $0.15 per Unit for the quarter ended September
30, 2004. The distribution will be paid November 12, 2004, to the General
Partner and all Common Unitholders of record as of the close of business on
November 3, 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 or general and administrative
expenses. 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 nine months of 2004, we have generated $1.1 million
more Available Cash before reserves than the distributions we have paid or are
paying with respect to those nine 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 September 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 nine months of 2004, our unit price increased 15%. As our unit
price rose from $9.80 at December 31, 2003 to $11.25 per unit at September 30,
2004, we increased our liability from $0.2 million to $0.8 million, recording a
charge of $0.6 million.
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.
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
-18-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
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.
In some cases, our sales contracts 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. During 2004, we changed many sales contract arrangements so
that volumes sold are the same as the volumes purchased in an 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 56 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 Nine Months
Ended September 30, Ended September 30,
2004 2003 2004 2003
--------- --------- --------- ---------
(in thousands, except volumes per day)
Revenues .................................. $ 244,377 $ 153,441 $ 663,245 $ 468,283
Crude oil costs ........................... 239,954 149,423 649,652 452,850
Field operating costs ..................... 3,473 2,815 9,711 8,373
Change in fair value of derivatives ....... 2 - (16) -
--------- --------- --------- ---------
Segment margin ........................ $ 948 $ 1,203 $ 3,898 $ 7,060
========= ========= ========= =========
Volumes per day from continuing operations:
Crude oil wellhead - barrels .......... 46,676 43,074 48,078 43,871
Crude oil total - barrels ............. 61,919 55,817 62,556 55,274
Crude oil gathering and marketing segment margins from continuing
operations decreased $0.3 million or 21% for the three months ended September
30, 2004, as compared to the three months ended September 30, 2003. Contributing
to this reduction in segment margin were three primary factors as follows:
- A $0.1 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, from increased
fuel costs to operate our tractor/trailers, additional employee
compensation and benefit costs due to additional volumes, and higher
insurance costs and vehicle repair 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.
Partially offsetting these decreases was a 11% increase in wellhead, bulk
and exchange purchase volumes between the third quarters of 2003 and 2004,
resulting in a $0.5 million increase in segment margin.
For the nine month periods, crude oil gathering and marketing segment
margins from continuing operations decreased $3.2 million in 2004 from the prior
year period. Contributing to this reduction in segment margin were the following
three factors:
- A $2.9 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 $1.3 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 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 7,713 barrels per day, or 14%, adding $2.0 million to segment
margin. Volumes purchased at the wellhead contributed 4,207 barrels per day of
that increase.
Outlook
We expect volatility in our gathering and marketing segment margins to
continue. During the remainder of 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, Denbury began shipping on our Mississippi
pipeline rather than selling the crude oil to us to ship. After this point, our
relationship with Denbury is primarily 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 nine months
ended September 30, 2004 and 2003 are as follows:
Three Months Nine Months
Ended September 30, Ended September 30,
2004 2003 2004 2003
------ ------ ------ ------
(barrels per day)
Texas - continuing operations................... 31,463 42,589 37,757 43,870
Florida ..................................... 12,712 14,711 14,698 14,561
Mississippi..................................... 13,369 7,271 11,947 8,226
Volumes on our Texas System averaged 31,463 barrels per day during the
third 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 had a joint tariff with TEPPCO through
October 2004 under which we earned $0.40 per barrel on the majority of the
barrels we deliver to the shipper's facilities. Most of the volume being shipped
on our Texas System goes to three refineries on the Texas Gulf Coast. The
decrease in volume in the third quarter of 2004 from the nine-month average was
due to a temporary shutdown at one of the refineries for maintenance.
The Mississippi System 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 system 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.
Beginning in September 2004, Denbury became a shipper on the Mississippi
System, under an incentive tariff, designed to encourage shippers to increase
volumes shipped on the pipeline. Prior to this point, Denbury sold its
production to us before it entered the pipeline.
The Mississippi System also includes another segment of the pipeline from
Liberty to near Baton Rouge, LA that has been out of service since February 1,
2002. A connecting carrier tested its pipeline and decided not to reactivate its
pipeline. During the second quarter of 2004 we displaced the crude oil in this
segment with inhibited water. In 2004 and 2003, this segment made no
contribution to pipeline revenues. In the third quarter of 2004, we wrote this
segment down to its estimated salvage value, recording an impairment charge of
$1.0 million.
-21-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
The Jay pipeline system in Florida/Alabama ships crude oil from fields
with relatively short remaining production lives. Shipments on this system were
impacted in the third quarter of 2004 by Hurricane Ivan that hit the panhandle
of Florida in mid-September. While our facilities experienced minimal damage
from the storm, power outages in the area shut down our crude oil pipeline
transportation operations through the end of September. Except for the effects
of the hurricane, volumes between the first nine months of 2004 and 2003 have
increased approximately 1,000 barrels per day, due to increases in production in
one field that is transported on 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 Nine Months
Ended September 30, Ended September 30,
2004 2003 2004 2003
------- ------ ------- -------
(in thousands, except volumes per day)
Revenues .................................. $ 4,064 $ 3,653 $12,235 $11,163
Pipeline operating costs .................. 1,463 3,453 6,124 8,258
------- ------- ------- -------
Segment margin ........................ $ 2,601 $ 200 $ 6,111 $ 2,905
======= ======= ======= =======
Volumes per day from continuing operations:
Crude oil pipeline - barrels .......... 57,544 64,571 64,402 66,657
Pipeline segment margin increased $2.4 million to $2.6 million for the
three months ended September 30, 2004, as compared to $0.2 million for the three
months ended September 30, 2003. The increase in pipeline segment margin is
attributable to the following factors:
- A $0.4 million increase in pipeline revenues due to higher sales
prices for crude oil, which increased the revenues from volumetric
gain barrels; and
- A $2.0 million decrease in pipeline operating costs. In the third
quarter of 2003, we recorded a charge of $0.7 million for an accrual
for the removal of an abandoned offshore pipeline. In the third
quarter of 2004, we received permission to abandon the pipeline in
place which resulted in the reversal of $0.5 million of the amounts
previously accrued. This charge and reversal resulted in a change of
$1.2 million in pipeline operating costs between the periods.
Additionally, repairs and regulatory testing expenses in the 2004
period were $0.6 million less in the 2004 quarter. Changes in other
operating costs resulted in another $0.2 million of decreased costs.
For the nine months ended September 30, 2004, pipeline segment margin
increased $3.2 million or 110%, as compared to the same period in 2003. The
increase in pipeline segment margin is attributable to the following factors:
- A $0.8 million increase in pipeline revenues due to higher sales
prices for crude oil, which increased the revenues from volumetric
gain barrels;
- A $0.3 million increase in tariff revenues due to higher average
tariff rates; and
- A $2.1 million decrease in pipeline operating costs due to the same
factors discussed above. In the third quarter of 2003, we recorded a
charge of $0.7 million for an accrual for the removal of an
abandoned offshore pipeline. In the second quarter of 2004, we
increased this accrual by $0.4 million. When we received permission
in the third quarter of 2004 to abandon the pipeline in place, we
reversed $0.5 million of the amounts previously accrued. The charges
and reversal resulted in a change of $0.8 million in pipeline
operating costs between the periods. Additionally, repairs and
-22-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
regulatory testing expenses in the 2004 period were $0.9 million
less in the 2004 quarter. Changes in other operating costs resulted
in another $0.4 million of decreased costs.
Outlook
Through October 2004, we will continue to receive a tariff of $0.40 per
barrel on the volumes shipped from the ExxonMobil connection in Texas. After
October 2004, our share of the joint tariff with TEPPCO and ExxonMobil will be
reduced to $0.20 per barrel. Based on volumes shipped in the third quarter of
2004, this change will reduce tariff revenues by $0.5 million. per quarter. This
arrangement expires December 31, 2004, at which time TEPPCO, ExxonMobil, the
shippers and Genesis will negotiate a revised joint tariff.
After August 2004, the light crude oil volumes that we were receiving from
TEPPCO at West Columbia are received through the ExxonMobil connection at
Webster. We are currently reviewing the costs to test, repair and modify the
West Columbia to Webster segment for transportation of heavy crude oil. We
expect to complete the evaluation during the fourth 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 continue to 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 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,
Denbury began shipping on our Mississippi pipeline rather than selling the crude
oil to us to market and ship on our Mississippi System. We also restructured our
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.
In September 2004, we acquired a second volumetric production payment of
33.0 Bcf of CO2 from Denbury, and Denbury assigned to us another existing
long-term CO2 contract with an industrial customer.
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
-23-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
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 Nine Months
Ended September 30, Ended September 30,
2004 2003 2004 2003
------- ------ ------- -----
(in thousands, except volumes per day)
Revenues .................................. $ 2,295 $ - $ 6,275 $ -
CO2 transportation and other costs ........ 752 - 2,031 -
------- ------ ------- ------
Segment margin ........................ $ 1,543 $ - $ 4,244 $ -
======= ====== ======= =====
Volumes per day from continuing operations:
CO2 marketing - Mcf ................... 48,634 - 44,337 -
Comparable volumes sold by Denbury during the three months and nine months
ended September 30, 2003 under the contracts that we acquired averaged 42,937
and 40,721 Mcf per day. We paid Denbury $0.16 per Mcf, or $0.8 million for the
three months and $2.0 million for the nine months, to transport the CO2 to our
customers on Denbury's pipeline.
Outlook
We expect to generate at least $6.0 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 payments at September
30, 2004, was 183.1 Bcf.
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 nine months ended September 30, 2004, we incurred costs totaling
$0.3 million related to the dismantlement of assets that we abandoned. During
the three and nine months ended September 30, 2003, the assets we sold during
the fourth quarter of 2003 generated $0.4 million and $2.0 million of segment
margin, respectively.
OTHER COSTS AND INTEREST
General and administrative expenses were as follows:
Three Months Nine Months
Ended September 30, Ended September 30,
2004 2003 2004 2003
------- ------- ------- -------
(in thousands)
Expenses excluding effect of stock appreciation rights plan... $ 2,667 $ 1,938 $ 7,261 $ 6,574
Stock appreciation rights plan expense (credit) .............. (28) - 564 -
------- ------- ------- -------
Total general and administrative expenses ................ $ 2,639 $ 1,938 $ 7,825 $ 6,574
======= ======= ======= =======
General and administrative expenses, excluding the effects of our stock
appreciation rights (SAR) plan, increased $0.7 million in the 2004 third quarter
as compared to these costs in the 2003 period. In the third 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, as well as additional audit fees related to this
-24-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
process. An increase in the amount accrued for the quarter under our employee
bonus plan as compared to a decrease in the prior year period resulted in a
change in general and administrative expenses of $0.3 million.
For the nine months ended September 30, 2004 and 2003, general and
administrative expenses excluding the effects of our SAR plan were $7.3 million
and $6.6 million, respectively. While we incurred costs of $0.9 million in the
nine month 2004 period related to the internal control documentation project and
related audit fees, legal fees were $0.4 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. Expense
under our employee bonus plan increased $0.1 million in the 2004 period. Other
administrative costs increased $0.1 million.
The SAR plan for employees and directors 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 15% from $9.80 at
December 31, 2003 to $11.25 at September 30, 2004 resulting in a $0.6 million
increase to the accrual for this liability in the first nine months of 2004.
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.
Interest expense, net was as follows:
Three Months Nine Months
Ended September 30, Ended September 30,
2004 2003 2004 2003
----- ----- ----- -----
(in thousands)
Interest expense, including commitment fees... $ 155 $ 88 $ 533 $ 273
Capitalized interest ......................... (21) - (21) -
Amortization and write-off of facility fees... 78 74 226 604
Interest income .............................. (9) (6) (37) (21)
----- ----- ----- -----
Net interest expense ..................... $ 203 $ 156 $ 701 $ 856
===== ===== ===== =====
Interest expense increased in the three and nine months ended September
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 nine 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 Bank of America 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, subject to a borrowing base
calculation.
Interest rates and fees under the New Credit Facility are slightly better
than the terms of the prior facility.
At September 30, 2004 we had borrowed $8.9 million under the working
capital portion of the New Credit Facility and $6.1 million under the
acquisition portion. Due to the revolving nature of loans under the New Credit
-25-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Facility, additional borrowings and periodic repayments and re-borrowings may be
made until the maturity date of June 1, 2008. At September 30, 2004, we had
letters of credit outstanding under the New Credit Facility totaling $15.3
million, comprised of $6.5 million and $8.0 million for crude oil purchases
related to September 2004 and October 2004, respectively, and $0.8 million
related to other business obligations. As we no longer purchase crude oil from
Denbury for shipment, we no longer provide Denbury with letters of credit.
At September 30, 2004, the borrowing base calculation limited the $50
million of the working capital portion to $34.2 million. Available amounts under
the working capital and acquisition portions of the New Credit Facility at
September 30, 2004, were $10.0 million and $43.9 million, respectively.
CAPITAL EXPENDITURES
A summary of our capital expenditures in the nine months ended September
30, 2004 and 2003 is as follows:
Nine Months Ended September 30,
----------------------------------
2004 2003
-------------- -------------
(in thousands)
Maintenance capital expenditures:
Texas pipeline system............................................................ $ 109 $ 1,496
Mississippi pipeline system...................................................... 370 1,260
Jay pipeline system.............................................................. 17 195
Crude oil gathering assets....................................................... 41 234
Administrative assets............................................................ 90 294
-------------- -------------
Total maintenance capital expenditures........................................ 627 3,479
Growth capital expenditures:
Mississippi pipeline system...................................................... 5,048 -
CO2 contract..................................................................... 4,723 -
Crude oil gathering assets....................................................... - 659
Miscellaneous.................................................................... 33 -
-------------- -------------
Total growth capital expenditures............................................. 9,804 659
-------------- -------------
Total capital expenditures................................................ $ 10,431 $ 4,138
============== =============
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 in
Mississippi of right-of-way and the initial construction costs for a ten mile
extension of our Mississippi 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.
This extension of our crude oil pipeline will be approximately nine miles. We
acquired a second CO2 volumetric production payment and related industrial sales
contract during the third quarter of 2004. 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 September 30, 2004 and based on the
information available to us at this time, we currently anticipate that our
maintenance capital expenditures during the fourth quarter of 2004 will be
approximately $0.2 million. Although we have not completed our 2005 budget, we
expect that our maintenance
-26-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
capital expenditures for 2005 will be approximately $1.3 million. These
expenditures are expected to relate primarily to our Mississippi System,
including corrosion control expenditures, minor facility improvements and
rehabilitation of the pipeline as a result of integrity management test results.
We made commitments totaling $5.4 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 September 30, 2004, we have expended $4.6 million on
these projects. We expect to fund these capital expenditures from our New Credit
Facility. These projects should be completed by the first quarter of 2005.
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. Other sources of capital would
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:
Nine Months Ended September 30,
----------------------------------
2004 2003
-------------- -------------
(in thousands)
Cash provided by (used in):
Operating activities............................................................. $ 4,279 $ 8,335
Investing activities............................................................. $ (9,126) $ (4,000)
Financing activities............................................................. $ 2,883 $ (1,473)
Operating. Net cash from operating activities for each period have been
comprised of the following:
Nine Months Ended September 30,
----------------------------------
2004 2003
-------------- -------------
(in thousands)
Net income....................................................................... $ (300) $ 1,556
Depreciation and amortization.................................................... 5,773 4,244
Gain on sales of assets.......................................................... (65) (190)
Other non-cash items............................................................. 837 942
Changes in components of working capital, net.................................... (1,966) 1,783
-------------- -------------
Net cash from operating activities............................................ $ 4,279 $ 8,335
============== =============
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. During the third quarter of
-27-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
2004, we paid the $3.0 million in fines assessed in connection with the
Mississippi oil spill in 1999, which utilized operating cash flows. In 2001 and
2002, a total accrual of $3.0 million was recorded for these fines.
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 $75.6 million aggregate receivables on
our consolidated balance sheet at September 30, 2004, approximately $74.0
million, or 97.9%, were less than 30 days past the invoice date.
Investing. Cash flows used in investing activities in the nine month
period of 2004 were $9.1 million as compared to $4.0 million in the 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 for 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 acquired a volumetric production payment
from Denbury. We received $0.1 million from the sale of surplus assets.
In the first nine months of 2003 we expended $4.1 million for property and
equipment additions, and received $0.2 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 nine months of 2004, financing activities provided
net cash of $2.9 million. Our outstanding debt increased $8.0 million, to
provide funds for our capital additions and to fund the fines related to the
Mississippi spill. Distributions to our partners utilized $4.3 million. We also
incurred $0.8 million of costs related to our new credit facility.
Net cash expended for financing activities was $1.5 million in the first
nine months of 2003. In 2003 we increased 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 $0.9 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 September 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.
-28-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
We believe we will be able to sustain a regular quarterly distribution of
$0.15 per unit during 2004. We expect to increase our distribution during 2005.
However, our ability to restore the distribution to the targeted minimum
quarterly distribution amount of $0.20 per unit may depend in part on our
success at developing and executing capital projects and making accretive
acquisitions.
Available Cash before reserves for the three and nine months ended
September 30, 2004, is as follows:
Three Nine
Months Months
Ended Ended
September 30, September 30,
2004 2004
------------- -------------
(in thousands)
AVAILABLE CASH BEFORE RESERVES:
Net loss......................................................................... $ (394) $ (300)
Depreciation and amortization.................................................... 2,599 5,773
Net non-cash (credits) charges................................................... (13) 565
Maintenance capital expenditures................................................. (217) (627)
-------- -------
Available Cash before reserves................................................... $ 1,975 $ 5,411
======== =======
Distributions for the three and nine month periods total $1.4 million and
$4.3 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 nine months
ended September 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. Further, 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 that have been incurred.
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
The reconciliation of Available Cash (a non-GAAP liquidity measure) to
cash flow from operating activities (the GAAP measure) for the three and nine
months ended September 30, 2004, is as follows:
-29-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Three Nine
Months Months
Ended Ended
September 30, September 30,
2004 2004
------------- -------------
(in thousands)
Cash flows from operating activities............................................. $ (1,185) $ 4,279
Adjustments to reconcile operating cash flows to Available Cash:
Maintenance capital expenditures............................................ (217) (627)
Proceeds from asset sales................................................... 3 82
Amortization of credit facility issuance fees............................... (95) (289)
Net effect of changes in working capital accounts not
included in calculation of Available Cash................................ 3,469 1,966
-------- -------
Available Cash before reserves................................................... $ 1,975 $ 5,411
======== =======
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 September 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.............. $ - $ - $ 15,000 $ - $ 15,000
Operating Leases............ 2,864 1,818 1,493 819 6,994
Capital expenditure
commitments............ 2,100 - - - 2,100
Unconditional Purchase
Obligations (1)........ 150,119 104,618 - - 254,737
--------- --------- -------- ------- ---------
Total Contractual Cash
Obligations............ $ 155,083 $ 106,436 $ 16,493 $ 819 $ 278,831
========= ========= ======== ======= =========
(1) The unconditional purchase obligations included above are contracts to
purchase crude oil, at market-based prices. For purposes of this table,
market prices at September 30, 2004, were used to value the obligations,
such that actual obligations may differ from the amounts included above.
OFF-BALANCE SHEET ARRANGEMENTS
We have no off-balance sheet arrangements, special purpose entities, or
financing partnerships, other than the contractual obligations disclosed above,
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.
-30-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
CRITICAL ACCOUNTING POLICIES
For a discussion of our critical accounting policies, which are related to
revenue and expense accruals, pipeline loss allowance recognition, depreciation,
amortization and impairment of long-lived assets, and liability and contingency
accruals, and which remain unchanged, see "Management's Discussion and Analysis
of Financial Condition and Results of Operations" in our annual report on Form
10-K for the year ended December 31, 2003.
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, 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 our 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 September 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)............................................ 54
Carrying value (in thousands).................................. $ 2,305
Fair value (in thousands)...................................... $ 2,574
Commodity Swap Agreement:
Contract volumes (1,000 bbls).................................. 62
Weighted average price per bbl................................. $ 50.00
Contract value (in thousands).................................. $ 3,100
Mark-to-market change (in thousands)........................... (16)
------------
Market settlement value (in thousands)......................... $ 3,084
============
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 September 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 September 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.
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ITEM 6. EXHIBITS.
(a) Exhibits.
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.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
GENESIS ENERGY, L.P.
(A Delaware Limited Partnership)
By: GENESIS ENERGY, INC., as
General Partner
Date: November 9, 2004 By: /s/ ROSS A. BENAVIDES
--------------------------------
Ross A. Benavides
Chief Financial Officer
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EXHIBIT INDEX
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.
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