================================================================================
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------
FORM 10-Q
[X] QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the quarterly period ended September 30, 2005
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
----- -----
Indicate by check mark whether the registrant is a shell company (as defined by
Rule 12b-2 of the Exchange Act.)
Yes No X
----- -----
Indicate number of shares of each of the issuer's classes of common stock, as of
the latest practicable date. Limited Partner Units outstanding as of November 7,
2005: 9,313,811
================================================================================
This report contains 36 pages
GENESIS ENERGY, L.P.
FORM 10-Q
INDEX
Page
----
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets - September 30, 2005 and December 31,
2004.......................................................... 3
Consolidated Statements of Operations for the Three and Nine
Months Ended September 30, 2005 and 2004...................... 4
Consolidated Statements of Cash Flows for the Nine Months Ended
September 30, 2005 and 2004................................... 5
Consolidated Statement of Partners' Capital for the Nine Months
Ended September 30, 2005...................................... 6
Notes to Consolidated Financial Statements....................... 7
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations......................................... 18
Item 3. Quantitative and Qualitative Disclosures about Market Risk....... 35
Item 4. Controls and Procedures.......................................... 35
PART II. OTHER INFORMATION
Item 1. Legal Proceedings................................................ 36
Item 6. Exhibits and Reports on Form 8-K................................. 36
SIGNATURES .............................................................. 36
-2-
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
(Unaudited)
September 30, December 31,
2005 2004
------------- ------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents ................................ $ 2,149 $ 2,078
Accounts receivable:
Trade ................................................. 94,898 68,737
Related party ......................................... 522 584
Inventories .............................................. 4,825 1,866
Net investment in direct financing leases, net of
unearned income - current portion ..................... 522 318
Insurance receivable ..................................... 2,041 2,125
Other .................................................... 2,499 1,688
-------- --------
Total current assets .................................. 107,456 77,396
FIXED ASSETS, at cost ....................................... 69,192 73,023
Less: Accumulated depreciation ........................... (35,128) (39,237)
-------- --------
Net fixed assets ...................................... 34,064 33,786
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned
income ................................................... 6,077 4,247
CO2 ASSETS, net of amortization ............................. 24,327 26,344
INVESTMENT IN T&P SYNGAS SUPPLY COMPANY ..................... 13,365 --
OTHER ASSETS, net of amortization ........................... 1,330 1,381
-------- --------
TOTAL ASSETS ................................................ $186,619 $143,154
======== ========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable:
Trade ................................................. $ 99,289 $ 74,176
Related party ......................................... 2,253 1,239
Accrued liabilities ...................................... 7,895 6,523
-------- --------
Total current liabilities ............................. 109,437 81,938
LONG-TERM DEBT .............................................. 32,600 15,300
OTHER LONG-TERM LIABILITIES ................................. 186 160
COMMITMENTS AND CONTINGENCIES (Note 12)
MINORITY INTERESTS .......................................... 517 517
PARTNERS' CAPITAL
Common unitholders, 9,314 units issued and outstanding ... 42,994 44,326
General partner .......................................... 885 913
-------- --------
Total partners' capital ............................... 43,879 45,239
-------- --------
TOTAL LIABILITIES AND PARTNERS' CAPITAL ..................... $186,619 $143,154
======== ========
The accompanying notes are an integral part of these consolidated
financial statements.
-3-
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
(Unaudited)
Three Months Ended September 30, Nine Months Ended September 30,
-------------------------------- -------------------------------
2005 2004 2005 2004
-------- -------- -------- --------
REVENUES:
Crude oil gathering and marketing:
Unrelated parties (including revenues from buy/sell
arrangements in the three and nine months of 2005
of $102,893 and $279,285 and $78,876 and $210,311
in the three and nine months of 2004) ................. $290,887 $244,377 $785,161 $663,245
Related parties .......................................... 187 -- 613 --
Pipeline transportation, including natural gas sales:
Unrelated parties ........................................ 5,849 3,787 17,776 11,958
Related parties .......................................... 1,131 277 3,400 277
CO2 revenues ................................................ 2,523 2,295 7,371 6,275
-------- -------- -------- --------
Total revenues ........................................... 300,577 250,736 814,321 681,755
COSTS AND EXPENSES:
Crude oil costs:
Unrelated parties (including crude oil costs from
buy/sell arrangements in the three and nine months
of 2005 of $102,304 and $278,703 and $78,511 and
$209,499 in the three and nine months of 2004) ........ 284,518 214,864 767,864 573,145
Related parties .......................................... 1,421 25,092 3,422 76,491
Field operating .......................................... 4,082 3,473 12,097 9,711
Pipeline transportation costs:
Pipeline operating costs ................................. 2,917 1,463 7,450 6,124
Natural gas purchases .................................... 2,178 -- 6,590 --
CO2 distribution costs:
Transportation costs - related party ..................... 806 726 2,296 1,954
Other costs .............................................. 37 26 113 77
General and administrative .................................. 3,210 2,639 6,536 7,825
Depreciation and amortization ............................... 1,601 2,599 4,695 5,773
Net (gain) loss on disposal of surplus assets ............... (84) 10 (482) (65)
-------- -------- -------- --------
OPERATING (LOSS) INCOME ..................................... (109) (156) 3,740 720
OTHER INCOME (EXPENSE):
Equity in earnings of investment in T&P Syngas .............. 8 -- 260 --
Interest income ............................................. 10 9 38 37
Interest expense ............................................ (550) (212) (1,439) (738)
-------- -------- -------- --------
(LOSS) Income from continuing operations .................... (641) (359) 2,599 19
Income (loss) from operations of discontinued Texas System .. 45 (35) 318 (319)
-------- -------- -------- --------
NET (LOSS) INCOME ........................................... $ (596) $ (394) $ 2,917 $ (300)
NET (LOSS) INCOME PER COMMON UNIT - BASIC AND DILUTED:
(Loss) income from continuing operations ................ $ (0.06) $ (0.04) $ 0.28 $ 0.00
(Loss) income from discontinued operations .............. 0.00 0.00 0.03 (0.03)
-------- -------- -------- --------
NET (LOSS) INCOME ........................................... $ (0.06) $ (0.04) $ 0.31 $ (0.03)
WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING ......... 9,314 9,314 9,314 9,314
======== ======== ======== ========
The accompanying notes are an integral part of these consolidated
financial statements.
-4-
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
Nine Months Ended September 30,
-------------------------------
2005 2004
-------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 2,917 $ (300)
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation ..................................................................... 2,678 3,976
Amortization of CO2 contracts .................................................... 2,017 1,797
Amortization of credit facility issuance costs ................................... 279 289
Amortization of unearned income on direct financing leases ....................... (521) --
Payments received under direct financing leases .................................. 890 --
Equity in earnings of investment in T&P Syngas ................................... (260) --
Distributions from T&P Syngas that are a return on investment .................... 260 --
Change in fair value of derivatives .............................................. (1,101) (16)
Gain on asset disposals .......................................................... (800) (65)
Other non-cash charges ........................................................... 23 564
Changes in components of working capital -
Accounts receivable ........................................................... (26,099) (8,905)
Inventories ................................................................... (3,537) (1,679)
Other current assets .......................................................... (727) 13,756
Accounts payable .............................................................. 25,860 10,338
Accrued liabilities ........................................................... 2,364 (15,476)
-------- --------
Net cash provided by operating activities .............................................. 4,243 4,279
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment ................................................. (5,374) (4,493)
Investment in T&P Syngas Supply Company ............................................. (13,418) --
Distributions from T&P Syngas that are a return of investment ....................... 53 --
CO2 contract acquisitions ........................................................... -- (4,702)
Other, net .......................................................................... (209) (13)
Proceeds from sale of assets ........................................................ 1,581 82
-------- --------
Net cash used in investing activities .................................................. (17,367) (9,126)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net borrowings of debt .............................................................. 17,300 8,000
Credit facility issuance fees ....................................................... -- (839)
Other, net .......................................................................... 172 --
Distributions to common unitholders ................................................. (4,191) (4,192)
Distributions to General Partner .................................................... (86) (86)
-------- --------
Net cash provided by financing activities .............................................. 13,195 2,883
-------- --------
Net decrease in cash and cash equivalents .............................................. 71 (1,964)
Cash and cash equivalents at beginning of year ......................................... 2,078 2,869
-------- --------
Cash and cash equivalents at end of period ............................................. $ 2,149 $ 905
======== ========
The accompanying notes are an integral part of these consolidated
financial statements.
-5-
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, 2005 ..................... 9,314 $44,326 $913 $45,239
Net income for the nine months ended September 30, 2005... -- 2,859 58 2,917
Distributions to partners during the nine months ended
September 30, 2005 .................................... -- (4,191) (86) (4,277)
----- ------- ---- -------
Partners' capital at September 30, 2005 .................. 9,314 $42,994 $885 $43,879
===== ======= ==== =======
The accompanying notes are an integral part of these consolidated
financial statements.
-6-
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 natural gas and wholesale marketing of carbon dioxide (CO2). We
have 9.3 million common units outstanding, representing limited partner
interests in us of 98%, of which 0.7 million units (7.4%) are owned by our
general partner, Genesis Energy, Inc. Our general partner also owns all of our
2% general partner interest. Our general partner is owned by Denbury Gathering &
Marketing, Inc., a subsidiary of Denbury Resources Inc.
Genesis Crude Oil, L.P. is our operating limited partnership and is owned
99.99% by us and 0.01% by our general partner. Genesis Crude Oil, L.P. has five
subsidiary partnerships: Genesis Pipeline Texas, L.P., Genesis Pipeline USA,
L.P., Genesis CO2 Pipeline, L.P., Genesis Natural Gas Pipeline, L.P. and Genesis
Syngas Investments, 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 (i) our
consolidated financial position as of September 30, 2005 and December 31, 2004,
(ii) our consolidated results of operations and changes in comprehensive income
for the three and nine months ended September 30, 2005 and 2004, (iii) our
consolidated cash flows for the nine months ended September 30, 2005 and 2004,
and (iv) our consolidated changes in partners' capital for the nine months ended
September 30, 2005.
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, 2004 filed with the SEC.
All significant intercompany transactions have been eliminated.
We have not included a provision for income taxes in our consolidated
financial statements, because we are a "pass-through" entity for federal income
tax purposes, meaning our income will be taxable directly to the partners
holding partnership interests in the Partnership.
2. NEW ACCOUNTING PRONOUNCEMENTS
In September 2005, the Emerging Issues Task Force (EITF) of the Financial
Accounting Standards Board (FASB) reached consensus in the issue of accounting
for buy/sell arrangements as part of its EITF Issue No. 04-13, "Accounting for
Purchases and Sales of Inventory with the Same Counterparty" (Issue 04-13). As
part of Issue 04-13, the EITF is requiring that all buy/sell arrangements be
reflected on a net basis, such that the purchase and sale are netted and shown
as either a net purchase or a net sale in the income statement. This requirement
is effective for new arrangements entered into after March 31, 2006. If this
requirement had been effective for the three and nine months ended September 30,
2005 and 2004, our reported crude oil gathering and marketing revenues from
unrelated parties and our reported crude oil costs from unrelated parties would
be reduced by the amounts shown in parenthetical notations on the consolidated
statements of operations. We do not expect that the adoption of Issue 04-13 will
have a material effect on our financial position, results of operations or cash
flows.
In December 2004, the FASB issued Statement of Financial Accounting
Standards No. 123 (revised December 2004), "Share-Based Payments" (SFAS 123(R)).
This statement replaces SFAS No. 123 and requires that compensation costs
related to share-based payment transactions be recognized in the financial
statements. This
-7-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
statement is effective for us in the first quarter of 2006. The adoption of this
statement will require that the compensation cost associated with our stock
appreciation rights plan be re-measured each reporting period based on the fair
value of the rights. Before the adoption of SFAS 123 (R), we have accounted for
the stock appreciation rights in accordance with FASB Interpretation No. 28,
"Accounting for Stock Appreciation Rights and Other Variable Stock Option or
Award Plans" which required that the liability under the plan be measured at
each balance sheet date based on the market price of our common units at that
date. Under SFAS 123(R), the liability will be calculated using a fair value
method that will take into consideration the expected future value of the rights
at their expected exercise dates. We are currently evaluating what effect SFAS
123(R) will have on our financial statements, but at this time, we do not
believe that the adoption of this statement will have a material effect on our
financial position, results of operations or cash flows.
In March 2005, the FASB issued FASB Interpretation No. 47, "Accounting for
Conditional Asset Retirement Obligations, an interpretation of FASB Statement
No. 143" (FIN 47). FIN 47 clarifies that the term "conditional asset retirement
obligation", as used in SFAS No. 143, "Accounting for Asset Retirement
Obligations", refers to a legal obligation to perform an asset retirement
activity in which the timing and/or method of settlement are conditional upon a
future event that may or may not be within the control of the entity. Although
uncertainty about the timing and/or method of settlement may exist and may be
conditional upon a future event, the obligation to perform the asset retirement
activity is unconditional. Accordingly, an entity is required to recognize a
liability for the fair value of a conditional asset retirement obligation if the
fair value of the liability can be reasonably estimated. FIN 47 clarifies when
an entity would have sufficient information to reasonably estimate the fair
value of an asset retirement obligation and emphasizes that uncertainty about
the timing or method of settlement of the obligation should be factored into the
calculation of the fair value of the obligation. FIN 47 is effective no later
than the end of reporting periods ending after December 15, 2005. We are
currently evaluating what effect FIN 47 will have on our financial statements,
but at this time, we do not believe that the adoption of FIN 47 will have a
material effect on our financial position, results of operations or cash flows.
In May 2005, the FASB issued Statement of Financial Standards No. 154,
"Accounting Changes and Error Corrections" (SFAS 154). This statement
establishes new standards on the accounting for and reporting of changes in
accounting principles and error corrections. SFAS 154 requires retrospective
application to the financial statements of prior periods for all such changes,
unless it is impracticable to do so. SFAS 154 is effective for us in the first
quarter of 2006.
3. NET INVESTMENT IN DIRECT FINANCING LEASES
In 2004, we constructed a segment of crude oil pipeline and a CO2 pipeline
in Mississippi. Denbury pays us a minimum payment each month for the right to
use these pipelines. Both of these arrangements are accounted for as direct
financing leases.
In the first quarter of 2005, we completed another crude oil pipeline
segment to move crude oil from a Denbury field to our Mississippi System.
Denbury pays us a minimum payment each month for the right to use this pipeline.
This arrangement is also being accounted for as a direct financing lease.
At September 30, 2005, the components of the net investment in direct
financing leases were as follows (in thousands):
Total minimum lease payments to be received................... $ 9,707
Estimated residual values of leased property (unguaranteed)... 1,287
Less: Unearned income......................................... (4,395)
-------
Net investment in direct financing leases..................... $ 6,599
=======
At September 30, 2005, minimum lease payments to be received for each of
the five succeeding fiscal years are $1.2 million per year.
-8-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. INVESTMENT IN T&P SYNGAS SUPPLY COMPANY
On April 1, 2005, we acquired a 50% interest in T&P Syngas Supply Company
(T&P Syngas), a Delaware general partnership, for $13.4 million in cash from a
subsidiary of ChevronTexaco Corporation. Praxair Hydrogen Supply Inc. owns the
remaining 50% partnership interest in T&P Syngas. We paid for our interest in
T&P Syngas with proceeds from our credit facilities.
T&P Syngas is a partnership that owns a syngas manufacturing facility
located in Texas City, Texas. That facility processes natural gas to produce
syngas (a combination of carbon monoxide and hydrogen) and high pressure steam.
Praxair provides the raw materials to be processed and receives the syngas and
steam produced by the facility under a long-term processing agreement. T&P
Syngas receives a processing fee for its services. Praxair operates the
facility.
We are accounting for our 50% ownership in T&P Syngas under the equity
method of accounting. T&P Syngas is managed by a management committee comprised
of representatives from each partner, therefore we share equally with Praxair in
the control over the partnership. We reflect in our consolidated statements of
operations our equity in T&P Syngas' net income, net of the amortization of the
excess of our investment over our share of partners' capital of T&P Syngas. We
paid $4.0 million more for our interest in T&P Syngas than our share of
partners' capital on the balance sheet of T&P Syngas at the date of the
acquisition. This excess amount of the purchase price over the equity in T&P
Syngas is being amortized using the straight-line method over the remaining
useful life of the assets of T&P Syngas of eleven years. Our consolidated
statements of operations for the three and nine months ended September 30, 2005
included $97,000 and $436,000, respectively, as our share of the earnings of T&P
Syngas for the period beginning April 1, 2005, reduced by amortization of the
excess purchase price of $89,000 and $176,000, for the three and nine months,
respectively.
The table below reflects summarized financial information for T&P Syngas at
September 30, 2005, for the period since we acquired our interest in T&P Syngas.
Six Months Ended
September 30, 2005
------------------
(in thousands)
Revenues ................................. $ 1,919
Operating expenses and depreciation ...... (1,054)
Other income ............................. 6
-------
Net income ............................... $ 871
=======
September 30, 2005
------------------
(in thousands)
Current assets ........................... $ 1,449
Non-current assets ....................... 16,808
-------
Total assets ............................. $18,257
=======
Current liabilities ...................... $ 490
Partners' capital ........................ 17,767
-------
Total liabilities and partners' capital .. $18,257
=======
The following pro forma information represents the effects on our
consolidated statements of operations assuming the investment in T&P Syngas had
occurred at the beginning of each period presented:
-9-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended September 30, Nine Months Ended September 30,
-------------------------------- -------------------------------
2005 2004 2005 2004
-------- -------- -------- --------
(in thousands, except per unit amounts)
Revenues ........................................ $300,577 $250,736 $814,321 $681,755
Operating (loss) income ......................... $ (109) $ (156) $ 3,740 $ 720
Equity in earnings of T&P Syngas ................ $ 8 $ 162 $ 420 $ 452
Net interest expense ............................ $ (540) $ (382) $ (1,624) $ (1,241)
Income from continuing operations ............... (641) (377) 2,536 (70)
Net (loss) income ............................... $ (596) $ (412) $ 2,944 $ (389)
Basic and diluted net income (loss) per Common
Unit (Loss) income from continuing
operations ................................... $ (0.06) $ (0.04) $ 0.27 $ (0.01)
Income (loss) from discontinued
operations ................................... 0.00 0.00 0.03 (0.03)
-------- -------- -------- --------
Net (loss) income ............................ $ (0.06) $ (0.04) $ 0.30 $ (0.04)
======== ======== ======== ========
The acquisition of T&P Syngas occurred April 1, 2005, so the pro forma
results in the table above are the same as the actual results for the three
months ended September 30, 2005.
5. DEBT
We have a $100 million credit facility comprised of a $50 million revolving
line of credit for acquisitions and a $50 million working capital revolving
facility. The working capital portion of the credit facility has a $15 million
sublimit for loans with the remainder of the $50 million available for letters
of credit. In total we may have up to $65 million in loans under our credit
facility. At September 30, 2005, we had $11.8 million in loans and $5.8 million
in letters of credit (primarily for crude oil purchases in September 2005)
outstanding under the working capital portion and $20.8 million outstanding
under the acquisition portion of our credit facility. At September 30, 2005, the
weighted average interest rate on the debt was 7.36%. Due to the revolving
nature of loans under our credit facility, additional borrowings and periodic
repayments and re-borrowings may be made until the maturity date of June 1,
2008.
The aggregate amount that we may have outstanding at any time under the
working capital portion of our credit facility is subject to a borrowing base
calculation. The borrowing base is limited to $50 million and is calculated
monthly. At September 30, 2005, the borrowing base was $50.0 million. The
remaining amount available for borrowings at September 30, 2005 was $3.2 million
under the working capital portion and $29.2 million under the acquisition
portion of the credit facility.
Certain restrictive covenants of the credit facility limit our ability to
make distributions to our unitholders and our general partner. The credit
facility requires we maintain a cash flow coverage ratio of at least 1.1 to 1.0.
In general, this calculation compares operating cash inflows, as adjusted in
accordance with the credit facility, less maintenance capital expenditures, to
the sum of interest expense and distributions. At September 30, 2005, the
calculation resulted in a ratio of 1.1 to 1.0. Our credit facility also requires
that the level of operating cash inflows, as adjusted in accordance with the
credit facility, be at least $8.5 million. At September 30, 2005, the result of
this calculation was $10.3 million. If we meet these covenants, we are otherwise
not limited by our credit facility in making distributions.
6. PARTNERS' CAPITAL AND DISTRIBUTIONS
Partners' Capital
Partnership equity consists of the general partner interest of 2% and
9,313,811 common units representing limited partner interests of 98%.
Our general partner owns all of our general partner interest, all of the
0.01% general partner interest in GCOLP (which is reflected as a minority
interest in the consolidated balance sheet at September 30, 2005) and operates
our business.
-10-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Our partnership agreement authorizes our general partner to cause us 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 needs.
Distributions
Generally, we will distribute 100% of our Available Cash (as defined in our
partnership agreement) 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. During the first nine months of 2005 and in 2004, we paid a
regular quarterly distribution of $0.15 per unit ($1.4 million in total per
quarter). We have declared a $0.16 per unit distribution for the third quarter
of 2005, payable on November 14, 2005 to unitholders of record on November 4,
2005.
Our general partner is entitled to receive 2% of our distributions plus
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, our 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 September 30, 2005.
Net Income Per Common Unit
The following table sets forth the computation of basic net income per
common unit.
Three Months Ended September 30, Nine Months Ended September 30,
-------------------------------- -------------------------------
2005 2004 2005 2004
------ ------ ------ ------
(in thousands, except per unit amounts)
Numerators for basic and diluted net income per common unit:
(Loss) income from continuing operations ................... $ (641) $ (359) $2,599 $ 19
Less general partner 2% ownership ....................... (13) (8) 52 --
------ ------ ------ ------
(Loss) income from continuing operations available for
common unitholders ...................................... $ (628) $ (351) $2,547 $ 19
====== ====== ====== ======
Income (loss) from discontinued operations ................. $ 45 $ (35) $ 318 $ (319)
Less general partner 2% ownership .......................... 1 -- 6 (6)
------ ------ ------ ------
Income (loss) from discontinued operations available
for common unitholders .................................. $ 44 $ (35) $ 312 $ (313)
====== ====== ====== ======
Denominator for basic and diluted per Common Unit - weighted
average number of Common Units outstanding ................. 9,314 9,314 9,314 9,314
====== ====== ====== ======
Basic and diluted net income (loss) per Common Unit:
(Loss) income from continuing operations ................... $(0.06) $(0.04) $ 0.28 $ 0.00
Income (loss) from discontinued operations ................. 0.00 0.00 0.03 (0.03)
------ ------ ------ ------
Net (loss) income .......................................... $(0.06) $(0.04) $ 0.31 $(0.03)
====== ====== ====== ======
7. 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) Pipeline Transportation - interstate and intrastate
crude oil, natural gas and CO2 pipeline transportation; and (3) CO2 sales - the
sale, under long-term contracts, of CO2 acquired under a volumetric production
payment to industrial customers.
-11-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
Crude Oil
Gathering and Pipeline CO2
Marketing Transportation Sales Total
------------- -------------- ------- --------
(in thousands)
Three Months Ended September 30, 2005
Revenues:
External Customers ......................... $291,074 $ 5,989 $ 2,523 $299,586
Intersegment (a) ........................... -- 991 -- 991
-------- ------- ------- --------
Total revenues of reportable segments ...... $291,074 $ 6,980 $ 2,523 $300,577
======== ======= ======= ========
Segment margin excluding depreciation and
amortization (b) ........................ $ 1,053 1,885 $ 1,680 $ 4,618
Capital expenditures ....................... $ 38 $ 555 $ -- $ 593
Maintenance capital expenditures ........... $ 7 $ 407 $ -- $ 414
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
Nine Months Ended September 30, 2005
Revenues:
External Customers ......................... $785,774 $18,579 $ 7,371 $811,724
Intersegment (a) ........................... -- 2,597 -- 2,597
-------- ------- ------- --------
Total revenues of reportable segments ...... $785,774 $21,176 $ 7,371 $814,321
======== ======= ======= ========
Segment margin excluding depreciation and
amortization (b) ........................ $ 2,391 7,136 $ 4,962 $ 14,489
Capital expenditures ....................... $ 315 $ 5,157 $ -- $ 5,472
Maintenance capital expenditures ........... $ 55 $ 1,070 $ -- $ 1,125
Net fixed and other long-term assets (c) ... $ 6,140 $35,284 $24,374 $ 65,798
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 (c) ... $ 6,376 $31,465 $27,159 $ 65,000
-12-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
a) Intersegment sales were conducted on an arm's length basis.
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 the periods presented is as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
2005 2004 2005 2004
------ ------ ------- -------
(in thousands)
Segment margin excluding depreciation and amortization ... $4,618 $5,092 $14,489 $14,253
General and administrative expenses ...................... 3,210 2,639 6,536 7,825
Depreciation, amortization and impairment ................ 1,601 2,599 4,695 5,773
Net gain on disposal of surplus assets ................... (84) 10 (482) (65)
------ ------ ------- -------
Operating income from continuing operations .............. $ (109) $ (156) $ 3,740 $ 720
====== ====== ======= =======
c) Net fixed and other long-term assets are the measure used by management in
evaluating the results of its operations on a segment basis. Current assets
are not allocated to segments as the amounts are shared by the segments or
are not meaningful in evaluating the success of the segment's operations.
8. 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
then-existing market conditions.
Transactions with Denbury and our General Partner
Nine Months Ended
September 30,
-----------------
2005 2004
------- -------
(in thousands)
Crude oil purchases from Denbury ....................... $ 3,422 $76,491
Crude oil sales to Denbury ............................. $ 22 $ --
Truck transportation services provided to Denbury ...... $ 591 $ 23
Pipeline transportation services provided to Denbury ... $ 2,858 $ 277
Payments received under direct financing leases from
Denbury ............................................. $ 890 $ --
Pipeline transportation income portion of direct
financing lease fees ................................ $ 521 $ --
Pipeline monitoring services provided to Denbury ....... $ 22 $ 15
Directors' fees paid to Denbury ........................ $ 90 $ 90
CO2 transportation services provided by Denbury ........ $ 2,296 $ 1,954
Purchase of CO2 volumetric payment from Denbury ........ $ -- $ 4,663
Operations, general and administrative services
provided by our general partner ..................... $11,487 $10,129
Distributions to our general partner on its limited
partner units and general partner interest .......... $ 396 $ 396
Sales and Purchases of Crude Oil
Denbury began shipping its own crude oil on our Mississippi System in
September 2004, so our purchases of crude oil from Denbury (and our related
crude oil sales) have declined.
Transportation Services
In September 2004, we entered into an agreement with Denbury where we would
provide truck transportation services to Denbury to move its crude oil from the
wellhead to our Mississippi pipeline. Previously we had purchased Denbury's
crude oil and trucked the oil for our own account. Denbury pays us a fee for
this trucking
-13-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
service that varies with the distance the crude oil is trucked. These fees are
reflected in the statement of operations as gathering and marketing revenues.
In September 2004, Denbury also became a shipper on our Mississippi
pipeline. We also earned fees from Denbury under the direct financing lease
arrangements for the Olive and Brookhaven crude oil pipelines and the Brookhaven
CO2 pipeline and recorded pipeline transportation income from these
arrangements. See Note 3.
We also provide pipeline monitoring services to Denbury. This revenue is
included in pipeline revenues in the statement of operations.
Directors' Fees
We pay Denbury for the services of each of four of Denbury's officers who
serve as directors of our general partner, the same rate at which our
independent directors were paid.
CO2 Volumetric Production Payment and Transportation
We acquired volumetric production payments from Denbury in 2004 and 2003.
Denbury charges us a transportation fee of $0.16 per Mcf (adjusted for
inflation) to deliver the CO2 for us to our customers.
Operations, General and Administrative Services
We do not directly employ any persons to manage or operate our business.
Those functions are provided by our general partner. We reimburse the general
partner for all direct and indirect costs of these services.
Amounts due to and from Related Parties
At September 30, 2005 and December 31, 2004, we owed Denbury $1.6 million
and $1.2 million, respectively, for purchases of crude oil and CO2
transportation charges. Denbury owed us $0.5 million and $0.4 million for
transportation services at September 30, 2005 and December 31, 2004,
respectively. We owed our general partner $0.6 million at September 30, 2005,
for administrative services. We had advanced $0.1 million to our general partner
at December 31, 2004 for administrative services.
Financing
Our general partner, a wholly owned subsidiary of Denbury, guarantees our
obligations under our credit facility. Our general partner's principal assets
are its general and limited partnership interests in us. The obligations are not
guaranteed by Denbury or any of its other subsidiaries.
9. MAJOR CUSTOMERS AND CREDIT RISK
Due to the nature of our crude oil operations, a disproportionate
percentage of our trade receivables constitute obligations of oil companies..
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 integrated and large independent energy
companies with stable payment experience. The credit risk related to contracts
which are traded on the NYMEX is limited due to the daily cash settlement
procedures and other NYMEX requirements.
We have established various procedures to manage our credit exposure,
including initial credit approvals, credit limits, collateral requirements and
rights of offset. Letters of credit, prepayments and guarantees are also
utilized to limit credit risk to ensure that our established credit criteria are
met.
Occidental Energy Marketing, Inc. and Shell Oil Company accounted for 27%
and 12% of total revenues for the first nine months of 2005, respectively.
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,
respectively. The majority of the revenues from these customers in both periods
relate to our crude oil gathering and marketing operations.
-14-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. SUPPLEMENTAL CASH FLOW INFORMATION
Cash received by the Partnership for interest was $38,000 and $37,000 for
the nine months ended September 30, 2005 and 2004, respectively. Payments of
interest and commitment fees were $931,000 and $196,000 for the nine months
ended September 30, 2005 and 2004, respectively.
At September 30, 2005, we had incurred liabilities for fixed asset
additions totaling $0.1 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.
11. 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, although we have the flexibility to enter into
arrangements with a longer term.
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 the fair value of derivatives that are 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. The effective portion of
unrealized gains or losses on derivative transactions qualifying as cash flow
hedges are reflected in other comprehensive income. Derivative transactions
qualifying as fair value hedges are evaluated for hedge effectiveness and the
resulting hedge ineffectiveness is recorded as a gain or loss in the
consolidated statements of operations.
We review our contracts to determine if the contracts meet the definition
of derivatives pursuant to SFAS 133. At September 30, 2005, we had futures
contracts on the NYMEX that were considered free-standing derivatives that are
accounted for at fair value. The fair value of these contracts was determined
based on the closing price for such contracts on the NYMEX on September 30,
2005. We marked these contracts to fair value at September 30, 2005. During the
three months ended September 30, 2005, we recorded a loss of $8,000 related to
derivative transactions, which are included in the consolidated statements of
operations under the caption "Crude Oil Costs". For the nine month period, these
derivative transactions had no effect on earnings.
At September 30, 2005, we had futures contracts on the NYMEX that qualified
as derivatives and were formally documented and designated as fair value hedges
of inventory. During the three and nine months ended September 30, 2005, we
recognized gains, due to hedge ineffectiveness, on the fair value hedge of
60,000 barrels of inventory totaling $155,000 and $147,000, respectively. These
gains are included in the caption "Crude Oil Costs" in the consolidated
statements of operations. The time value component of the derivative gain or
loss excluded from the assessment of hedge effectiveness was not material.
The consolidated balance sheet at September 30, 2005 includes a reduction
in other current assets of $58,000 as a result of these derivative transactions.
At September 30, 2004, we had one swap contract that was considered a
free-standing derivative that was accounted for at fair value. 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 statements of operations under the
caption "Crude Oil Costs".
-15-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We determined that the remainder of our derivative contracts qualified for
the normal purchase and sale exemption and were designated and documented as
such at September 30, 2005 and December 31, 2004.
12. CONTINGENCIES
Guarantees
We have guaranteed $3.5 million of residual value related to the leases of
tractors and trailers from Ryder Transportation, Inc. We believe the likelihood
we would be required to perform or otherwise incur any significant losses
associated with this guaranty is remote.
Along with our general partner, we have guaranteed the payments by GCOLP to
the banks under the terms of our credit facility related to borrowings and
letters of credit. Borrowings at September 30, 2005 were $32.6 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.
In general, we expect to incur expenditures in the future to comply with
increasing levels of regulatory safety standards. While the total amount of
increased expenditures cannot be accurately estimated at this time, we
anticipate that we will expend a total of approximately $0.7 million during the
remainder of 2005 and approximately $0.3 million in 2006 for testing, repairs
and improvements under regulations requiring assessment of the integrity of
crude oil pipelines.
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.
Pennzoil-Quaker State Company (PQS) was seeking from us 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
crude oil we sold to PQS that was contaminated with organic chlorides. In
December 2003, our insurance carriers settled this litigation for $12.8 million.
PQS is also a defendant in five consolidated class action/mass tort actions
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 us and others for indemnity with respect to the
fire and explosion of January 18, 2000. We believe that the demand against us is
without merit and intend to vigorously defend ourselves in this matter. We
currently believe that this matter will not have a material financial effect on
our financial position, results of operations, or cash flows.
Environmental
In 1992, Howell Crude Oil Company entered into a sublease with Koch
Industries, Inc., covering a one acre tract of land located in Santa Rosa
County, Florida to operate a crude oil trucking station, known as Jay Station.
The sublease provided that Howell would indemnify Koch for environmental
contamination on the property under certain circumstances. Howell operated the
Jay Station from 1992 until December of 1996 when this operation was sold to us
by Howell. We operated the Jay Station as a crude oil trucking station until
2003. Koch has indicated that it has incurred certain investigative and/or other
costs, for which Koch alleges some or all should be reimbursed by us, under the
indemnification provisions of the sublease for environmental contamination on
the site and surrounding areas. Koch has also alleged that we are responsible
for future environmental obligations relating to the Jay Station.
Howell was acquired by Anadarko Petroleum Corporation (Anadarko) in 2002.
During the second quarter of 2005, we entered into a joint defense and cost
allocation agreement with Anadarko. Under the terms of the joint allocation
agreement, we agreed to reasonably cooperate with each other to address any
liabilities or defense costs with respect to the Jay Station. Additionally under
the Joint Allocation Agreement, Anadarko will be responsible for sixty percent
of the costs related to any liabilities or defense costs incurred with respect
to contamination at the Jay Station.
-16-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We were formed in 1996 by the sale and contribution of assets from Howell
and Basis Petroleum, Inc.. Anadarko's liability with respect to the Jay Station
is derived largely from contractual obligations entered into upon our formation.
We believe that Basis has contractual obligations under the same formation
agreements. We are preparing a formal demand seeking Basis' share of potential
liabilities and defense costs with respect to Jay Station.
We have contacted the appropriate state regulatory agencies regarding
developing a plan of remediation for certain affected soils at the Jay Station.
It is possible that we will also need to develop a plan for other affected soils
and/or affected groundwater. Through the third quarter of 2005, we have accrued
an estimate of our share of liability for this matter in the amount of $0.5
million. If we are required to remediate the site on a more extensive basis than
contemplated by our estimate, we could incur additional obligations of up to
$0.8 million. The time period over which our liability would be paid is
uncertain and could be several years. This liability may decrease if
indemnification and/or cost reimbursement is obtained by us for Basis' potential
liabilities with respect to this matter. At this time, our estimate of potential
obligations does not assume any specific amount contributed on behalf of the
Basis obligations, although we believe that Basis is responsible for a
significant part of these potential obligations.
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. We do not expect such matters presently
pending to have a material adverse effect on our financial position, results of
operations or cash flows.
13. SUBSEQUENT EVENTS
On October 11, 2005, we acquired a third volumetric production payment and
certain related contracts from Denbury for $14.4 million in cash. Pursuant to
that acquisition, Denbury assigned to us an interest in 80.0 Bcf of CO2 under a
volumetric production payment and Denbury's existing long-term CO2 supply
agreements with two of its industrial customers. The terms of the industrial
sales contracts include minimum take-or-pay volumes and maximum delivery
volumes. Denbury will also provide processing and transportation services for a
fee. We funded the purchase with proceeds from our credit facility.
On October 24, 2005, the Board of Directors of the general partner declared
a cash distribution of $0.16 per unit for the quarter ended September 30, 2005.
The distribution will be paid November 14, 2005, to our general partner and all
common unitholders of record as of the close of business on November 4, 2005.
-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
- Acquisitions in 2005
- Results of Operations and Outlook for 2005 and Beyond
- Liquidity and Capital Resources
- Commitments and Off-Balance Sheet Arrangements
- Other Matters
- New Accounting Pronouncements
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 before Reserves. Our
profitability depends to a significant extent upon our ability to maximize
segment margin. Segment margin is calculated as revenues less cost of sales and
operating expense, and does not include depreciation and amortization. A
reconciliation of segment margin to income from continuing operations is
included in our segment disclosures in Note 7 to the consolidated financial
statements. Available Cash before Reserves is a non-GAAP 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, the
replacement with the amount recognized as our equity in the income of joint
ventures with distributions received from those ventures, 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 before Reserves and a reconciliation of this
measure to cash flows from operations, see "Liquidity and Capital Resources -
Non-GAAP Financial Measure" below.
OVERVIEW
We operate in three business segments - crude oil gathering and marketing,
pipeline transportation and CO2 sales. We generate revenues by selling crude oil
and CO2 and by charging fees for the transportation of crude oil, natural gas
and CO2 on 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, natural gas and CO2 to the customer, and the costs
of operating our assets. We also report our share of the earnings of our equity
investee, T&P Syngas Supply Company in which we acquired a 50% interest on April
1, 2005.
Our primary goal is to generate Available Cash before Reserves for our
unitholders. Our Available Cash after Reserves is distributed quarterly to our
unitholders. During the third quarter of 2005, the Available Cash before
Reserves that we generated was less than our distribution, so we drew upon
reserves that we built in prior periods.
We generated net income for the nine months of 2005 from a combination of
four main sources. These sources included the results of our operating
activities, the sale of idle assets, our equity in the earnings from our
investment in T&P Syngas, and the effects of decreasing the liability under our
incentive compensation plan.
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 our unit price
declined from $12.60 at December 31, 2004 to $8.90 per unit at March 31, 2005,
we decreased our liability during the first quarter from $1.3 million to zero,
recording a credit of $1.3 million. The unit price then increased in the second
quarter of 2005 to $9.39, for which we provided a liability of $43,000. In the
third quarter, the unit price increased to $11.60. Therefore, for the third
quarter of 2005 we increased our liability by $0.7 million. In total, for the
nine months ended September 30, 2005, we have recorded a net credit $0.5
million.
-18-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
ACQUISITIONS IN 2005
GAS PIPELINE TRANSPORTATION ASSETS
In January 2005, we acquired fourteen natural gas pipeline and gathering
systems located in Texas, Louisiana and Oklahoma from Multifuels Energy Asset
Group, L.P. for $3.1 million. These fourteen systems are comprised of 60 miles
of pipeline and related assets. This acquisition was financed with proceeds from
our credit facility. The results of this acquisition are included in our
pipeline transportation segment.
SYNGAS INVESTMENT
On April 1, 2005 we acquired a 50% interest in T&P Syngas Supply Company
(T&P Syngas) for $13.4 million. We acquired our interest from TCHI Inc., a
wholly owned subsidiary of ChevronTexaco Global Energy Inc. Praxair Hydrogen
Supply, Inc. (Praxair) owns the other 50% interest in the partnership.
T&P Syngas is a partnership that owns a syngas manufacturing facility
located in Texas City, Texas. That facility processes natural gas to produce
syngas (a combination of carbon monoxide and hydrogen) and high pressure steam.
Praxair provides the raw materials to be processed and receives the syngas and
steam produced by the facility under a long-term processing agreement. T&P
Syngas receives a processing fee for its services. Praxair operates the
facility.
T&P Syngas is managed by a management committee consisting of two
representatives each from Praxair and us. The T&P Syngas management committee
has an approved resolution that provides that cash distributions will be paid
quarterly to the partners in the amount of cash on hand in excess of $100,000.
In July 2005 and October 2005, we received distributions of $0.3 million and
$0.5 million from T&P Syngas related to the second and third quarters of 2005,
respectively.
We financed our T&P Syngas interest acquisition with proceeds from our
credit facility.
THIRD VOLUMETRIC PRODUCTION PAYMENT
On October 11, 2005, we acquired a third volumetric production payment and
certain related contracts from Denbury for $14.4 million in cash. Pursuant to
that acquisition, Denbury assigned to us an interest in 80.0 Bcf of CO2 under a
volumetric production payment and Denbury's existing long-term CO2 supply
agreements with two of its industrial customers. The terms of the industrial
sales contracts include minimum take-or-pay volumes and maximum delivery
volumes. Denbury will also provide processing and transportation services for a
fee. We funded the purchase with proceeds from our credit facility.
In accordance with our procedures for evaluating and valuing material
acquisitions with Denbury, our Special Conflicts Committee of our Board of
Directors engaged legal counsel and obtained a fairness opinion from an
independent financial advisor regarding the acquisition of the third volumetric
production payment. The opinion we received stated the transaction was fair to
our unitholders.
RESULTS OF OPERATIONS AND OUTLOOK FOR THE REMAINDER OF 2005 AND BEYOND
CRUDE OIL GATHERING AND MARKETING OPERATIONS
The key factors 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.
These factors are discussed in detail in our Annual Report on Form 10-K for the
year ended December 31, 2004.
Segment margins from gathering and marketing operations are a function of
volumes purchased and the difference between the price of crude oil at the point
of purchase and the price of crude oil at the point of sale, minus the
associated costs of aggregation and transportation. The commodity price (for
purchases and sales) of crude oil do not necessarily bear a relationship to
segment margin as those prices normally impact revenues and costs of sales by
approximately equivalent amounts. Because period-to-period variations in
revenues and costs of sales are not
-19-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
generally meaningful in analyzing the variation in segment margin for our
gathering and marketing operations, these changes are not addressed in the
following discussion.
Field operating costs primarily consist of the costs to operate our fleet
of 53 trucks (51 leased and 2 owned) used to transport crude oil, and the costs
to maintain the trucks and assets used in the crude oil gathering operation.
Approximately 54% of these costs are variable and increase or decrease with
volumetric changes. Those 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.
Operating results from continuing operations for our crude oil gathering
and marketing segment were as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- -------------------
2005 2004 2005 2004
-------- -------- -------- --------
(in thousands, except volumes per day)
Revenues ................................................... $291,074 $244,377 $785,774 $663,245
Crude oil costs ............................................ 286,608 239,954 772,387 649,652
Field operating costs ...................................... 4,082 3,473 12,097 9,711
Change in fair value of derivatives ........................ (669) 2 (1,101) (16)
-------- -------- -------- --------
Segment margin .......................................... $ 1,053 $ 948 $ 2,391 $ 3,898
======== ======== ======== ========
Volumes per day from continuing operations:
Crude oil wellhead - barrels ............................ 37,213 46,676 39,818 48,078
Crude oil total - barrels (includes wellhead barrels) ... 51,639 61,919 55,211 62,556
Crude oil truck transported only - barrels .............. 2,212 1,307 3,335 760
Three Months Ended September 30, 2005 Compared with Three Months Ended
September 30, 2004
Crude oil gathering and marketing segment margins from continuing
operations increased $0.1 million for the three months ended September 30, 2005,
as compared to the three months ended September 30, 2004. Segment margin
increased primarily due to two factors with two other factors partially
offsetting the increase. These four factors were as follows:
- A $0.7 million unrealized gain from a fair value hedge of inventory.
This gain resulted from an 18% increase in crude oil market prices
during the 2005 third quarter.
- A $0.1 million increase in revenues from volumes that we transported
for a fee but did not purchase. Approximately one-half of this revenue
related to volumes transported for Denbury. In July and August of the
2004 period, we purchased Denbury's crude oil at the wellhead,
incurring all risk of loss and price variations. Beginning in
September 2004, Denbury started selling its production to the
end-market directly, and we only provide transportation services for
fees in our trucks and in our pipeline.
- A $0.6 million increase in field operating costs, related to higher
fuel costs and higher personnel costs. Fuel costs have increased
approximately $0.67 per gallon, or 38%, since the 2004 quarter. Due to
competition for wellhead barrels in the areas in which we operate, we
were not able to adjust the purchase price of the crude oil for these
cost increases.
- A 17% decrease in wellhead, bulk and exchange purchase volumes
combined with an 18% increase in the difference between the average
sales and purchase prices for the crude oil, resulting in a $0.1
million reduction in segment margin.
-20-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Nine Months Ended September 30, 2005 Compared with Nine Months Ended
September 30, 2004
For the nine month period, crude oil gathering and marketing segment
margins from continuing operations decreased $1.5 million in 2005 from the prior
year period. Contributing to this reduction in segment margin were the following
two factors that reduced segment margin:
- A $2.4 million increase in field operating costs. $0.4 million of this
increase is attributable to a reserve we recorded for 40% of the
expected costs to remediate Jay Station. (See additional discussion at
Note 12 to the Consolidated Financial Statements.) The majority of the
remaining increase of $2.0 million over the 2004 third quarter related
again to higher fuel costs, higher employee costs and the costs
related to additional tractor/trailers we leased in the third quarter
of 2004.
- A 7,345 barrel per day decrease in purchased volumes. This 12%
decrease, offset by a slight increase in the average difference
between the sales price and purchase price of crude oil reduced
segment margin by $1.1 million.
Partially offsetting the decrease from higher field costs and lower volumes
were increases in three factors. These factors were:
- A $0.7 million increase in revenues from volumes that we transported
for a fee but did not purchase. Approximately one-half of this revenue
related to volumes transported for Denbury. In the 2004 period, we
purchased Denbury's crude oil at the wellhead, incurring all risk of
loss and price variations. Beginning in September 2004, Denbury
started selling its production to the end-market directly, and we only
provide transportation services for fees in our trucks and in our
pipeline.
- A $1.1 million unrealized gain from a fair value hedge of inventory.
This gain resulted from an approximate 35% increase in crude oil
market prices since we acquired the inventory in the second quarter of
2005.
- A $0.2 million decrease in credit costs related to crude oil
transactions.
Outlook
Based on past experience and knowledge of assets in the crude oil gathering
and marketing segment, we continue to expect volatility from this segment, which
we attempt to mitigate in various ways. Effectively managing relationships with
suppliers; managing inventory; controlling field costs; and improving
operational efficiency in the field are some steps we take to mitigate
volatility.
PIPELINE TRANSPORTATION OPERATIONS
We operate three crude oil 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, 2005 and 2004 are as follows:
Three Months Ended September 30, Nine Months Ended September 30,
-------------------------------- --------------------------------
2005 2004 2005 2004
------ ------ ------ ------
(barrels per day)
Texas......... 33,536 31,463 32,213 37,757
Jay........... 11,704 12,712 13,909 14,698
Mississippi... 14,924 13,369 15,568 11,947
Volumes on our Texas System averaged 33,536 barrels per day during the
third quarter of 2005. 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 Texas System 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.
-21-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
This tariff declined to $0.20 per barrel in November 2004. Substantially all of
the volume being shipped on our Texas System goes to two refineries on the Texas
Gulf Coast.
The Mississippi System begins in Soso, Mississippi and extends to Liberty,
Mississippi. 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
expected future increases in production volumes in the area due to Denbury's CO2
tertiary recovery activities, 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 was injected into the pipeline.
In the fourth quarter of 2004, we constructed two segments of crude oil
pipeline to connect producing fields operated by Denbury to our Mississippi
System. One of these segments was placed in service in 2004 and the other began
operation in the first quarter of 2005. Denbury pays us a minimum payment each
month for the right to use these pipeline segments. We account for these
arrangements as direct financing leases.
The Jay pipeline system in Florida/Alabama ships crude oil from fields with
relatively short remaining production lives. Although volumes on this pipeline
had been declining steadily in recent years due to declining production in the
surrounding area, new production in the area has reduced the impact of those
declines.
Historically, the largest operating costs in our crude oil pipeline segment
have consisted of personnel costs, power costs, maintenance costs and costs of
compliance with regulations. Some of these costs are not predictable, such as
failures 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 and to minimize cost increases.
In the fourth quarter of 2004, we constructed a CO2 pipeline in Mississippi
to transport CO2 from Denbury's main CO2 pipeline to an oil field from which we
also constructed an oil pipeline to bring the oil from the field to our existing
Mississippi pipeline. Denbury has the exclusive right to use this CO2 pipeline.
This arrangement has been accounted for as a direct financing lease.
-22-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Operating results from continuing operations for our pipeline
transportation segment were as follows:
Three Months Ended September 30, Nine Months Ended September 30,
-------------------------------- -------------------------------
2005 2004 2005 2004
------- ------- ------- -------
(in thousands, except volumes per day)
Crude oil tariffs and revenues from direct financing leases
of crude oil pipelines ................................... $ 3,314 $ 3,102 $10,096 $ 9,666
Sales of crude oil pipeline loss allowance volumes .......... 1,158 854 3,456 2,449
Revenues from direct financing leases of CO2 pipelines ...... 88 -- 271 --
Tank rental reimbursements and other miscellaneous revenues.. 134 108 432 120
------- ------- ------- -------
Total revenues from crude oil and CO2 tariffs, including
revenues from direct financing leases .................... 4,694 4,064 14,255 12,235
Revenues from natural gas tariffs and sales ................. 2,286 -- 6,921 --
Natural gas purchases ....................................... (2,178) -- (6,590) --
Pipeline operating costs .................................... (2,917) (1,463) (7,450) (6,124)
------- ------- ------- -------
Segment margin ........................................... $ 1,885 $ 2,601 $ 7,136 $ 6,111
======= ======= ======= =======
Volumes per day from continuing operations:
Crude oil pipeline - barrels ............................. 60,164 57,544 61,690 64,402
Three Months Ended September 30, 2005 Compared with Three Months Ended
September 30, 2004
Pipeline segment margin decreased $0.7 million to $1.8 million for the
three months ended September 30, 2005, as compared to the three months ended
September 30, 2004. The decrease in pipeline segment margin is primarily
attributable to an increase in pipeline operating costs of $1.5 million, offset
partially by an increase of $0.6 million in crude oil and CO2 tariff revenues.
Also offsetting the higher costs were $0.2 million of net profit from the sales
of natural gas.
The fluctuation in operating costs is the result of increased costs related
to pipeline integrity management repairs in 2005 and the effects on the 2004
period of a reversal of an accrual related to a pipeline we were allowed to
abandon rather than remove. Our pipeline integrity costs in the third quarter of
2005 totaled $0.7 million. Those costs related to the last major section of
pipeline that needed to be tested for the first time. The accrual that was
reversed in the third quarter of 2004 reduced that period's pipeline operating
costs by $0.5 million. The remaining $0.2 million increase in pipeline operating
costs in the 2005 quarter resulted from increased costs for numerous items
including liability insurance, maintenance projects and various operational
costs.
Crude oil and CO2 tariff revenues increased $0.2 million in the 2005 third
quarter compared to the prior year period due to the combination of higher
tariffs and higher volumes. Volumes on our pipelines were affected briefly by
hurricanes in both periods, but overall volumes increased when comparing the
quarters. The effects of lower tariffs on the Texas System were offset by
increased volumes and higher tariffs on the Mississippi System.
Revenues from sales of crude oil volumes deducted from shippers as pipeline
loss allowances that exceeded actual losses increased $0.3 million in the 2005
third quarter as a result of higher crude oil market prices. The CO2 pipeline
did not exist in the third quarter of 2004, and the natural gas gathering
pipelines were acquired in the first quarter of 2005.
Nine Months Ended September 30, 2005 Compared with Nine Months Ended
September 30, 2004
For the nine months ended September 30, 2005, pipeline segment margin
increased $1.0 million or 17%, as compared to the same period in 2004. Revenues
from crude oil and CO2 tariffs and related sources added $2.0 million of the
increase for the period and $0.3 million of the increase resulted from net
profit from natural gas transportation and sales. Pipeline operating cost
increases offset $1.3 million of the revenue increases.
-23-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Crude oil pipeline volumes increased slightly between the two periods. The
hurricanes in the third quarter of 2005 reduced volumes on the Jay System, but
the decline was offset by increases on the other two crude oil pipelines.
Overall, crude oil pipeline tariffs, including income from direct financing
leases of crude oil pipelines increased $0.4 million between the nine month
periods due primarily to higher tariffs on the Mississippi System. Higher market
prices for crude oil added $1.0 million to pipeline loss allowance revenues
between the periods, and tariffs from the CO2 pipeline added another $0.3
million. The tank rental agreement on the Texas System combined with other
miscellaneous revenues added $0.3 million to tariff revenues between the
periods.
Operating costs increased $1.3 million. In 2004, as well as in 2005, we
incurred costs for regulatory testing and repairs resulting from that testing.
Those costs were approximately $0.3 million greater in the 2005 period.
Operational costs for personnel, contract services, liability insurance and
equipment maintenance accounted for most of the remaining increase.
Outlook
Volumes on the Texas System may continue to fluctuate as refiners on the
Texas Gulf Coast compete for crude oil with other markets connected to TEPPCO's
pipeline systems. We have completed our integrity testing on that system.
Denbury is the largest oil and gas producer in Mississippi. Our Mississippi
System 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 expects to add crude oil
gathering and CO2 supply infrastructure to these fields. Further, that
re-development of older fields and any related increase in production, could
create increased demand for our crude oil transportation services. Beginning in
September 2004, Denbury began shipping on our Mississippi System 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.
We built a CO2 pipeline to connect Denbury's existing CO2 pipeline to the
Brookhaven oil field in Mississippi. Our agreement with Denbury provides for a
minimum capacity charge that will provide $0.6 million of annual payments to us
with a commodity charge for volumes in excess of a threshold volume through
December 2012. The segments of crude oil pipeline we constructed to Denbury's
Olive and Brookhaven fields also have agreements providing for minimum capacity
charges with commodity charges for volumes in excess of threshold volumes
through 2013. The payments under these crude oil transportation agreements
should provide a combined total of $0.6 million of annual payments to us, in
addition to the amount received for the CO2 pipeline. The Brookhaven CO2 and
Olive pipelines went into service in 2004 and the Brookhaven oil pipeline began
service in the first quarter of 2005. We account for these arrangements as
direct financing leases.
As a result of new production in the area surrounding the Jay System,
volumes have stabilized on that system. Historically, producing wells in the
area have had rapidly declining future production curves, therefore we do not
know if this new production will be sufficient to continue to offset declining
production from existing wells in the area.
Should the production surrounding the Jay System decline such that it
becomes uneconomical to continue to operate the pipeline in crude oil service,
we believe that the best use of the Jay System may be to convert it to natural
gas service. We continue to review opportunities to effect such a conversion.
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 2005 or 2006.
We will continue to evaluate opportunities to dispose of or to make further
investments in components of this segment in order to improve its performance.
-24-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
CARBON DIOXIDE (CO2) OPERATIONS
In November 2003, we acquired a volumetric production payment, or VPP, of
167.5 Bcf of CO2 from Denbury and, in September 2004, we acquired an additional
33.0 Bcf VPP. Denbury owns 2.7 trillion cubic feet of estimated proved reserves
of CO2 in the Jackson Dome area near Jackson, Mississippi. In addition to the
production payments, Denbury also assigned to us five of their existing
long-term CO2 contracts with industrial customers. Denbury owns the pipeline
that is used to transport the CO2 to our customers as well as to its own
tertiary recovery operations.
The volumetric production payments entitle us to a maximum daily quantity
of CO2 of 65,250 thousand cubic feet (Mcf) per day through December 31, 2009,
55,750 Mcf per day for the calendar years 2010 through 2012, and 37,750 Mcf per
day beginning in 2013 until we have received all volumes under the production
payments. Under the terms of transportation agreements with Denbury, Denbury
will process and deliver this CO2 to our industrial customers and receive a fee
from us of $0.16 per Mcf, subject to adjustments for inflation, for those
transportation services.
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 and our
experience in 2003 and 2004, we can expect some seasonality in our sales of CO2.
The dominant months for beverage carbonation and freezing food are from April to
October, when warm weather increases demand for beverages and the approaching
holidays increase demand for frozen foods.
The average daily sales (in Mcfs) of CO2 for each quarter in 2005 and 2004
under these contracts (including volumes sold by Denbury on the contracts we
acquired in the third quarter of 2004) were as follows:
Quarter 2005 2004
- ------- ------ ------
First 47,808 45,671
Second 51,049 51,164
Third 51,386 53,095
Fourth 48,217
The terms of our contracts with the industrial customers include minimum
take-or-pay and maximum delivery volumes. The maximum daily contract quantity
per year in the contracts totals 61,500 Mcf. Under the minimum take-or-pay
volumes, the customers must purchase a total of 31,292 Mcf per day whether
received or not. Any volume purchased under the take-or-pay provision in any
year can then be recovered in a future year as long as the minimum requirement
is met in that year. In the two years ended December 31, 2004, all three
customers purchased more than their minimum take-or-pay quantities.
Our five industrial contracts expire at various dates beginning in 2010 and
extending through 2016. The sales contracts contain provisions for adjustments
for inflation to sales prices based on the Producer Price Index, with a minimum
price.
Operating results from continuing operations for our CO2 Sales segment were
as follows:
Three Months Ended September 30, Nine Months Ended September 30,
-------------------------------- -------------------------------
2005 2004 2005 2004
------- ------- ------- -------
(in thousands, except volumes per day)
Revenues ................................... $2,523 $2,295 $7,371 $6,275
CO2 transportation and other costs ......... 843 752 2,409 2,031
------ ------ ------ ------
Segment margin .......................... $1,680 $1,543 $4,962 $4,244
====== ====== ====== ======
Volumes per day from continuing operations:
CO2 Sales - Mcf ......................... 51,386 48,634 50,094 44,337
-25-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Three Months Ended September 30, 2005 Compared with Three Months Ended
September 30, 2004
The increase in volume in the third quarter of 2005 was due to the effects
of the additional contracts acquired in September 2004. The average revenue per
Mcf sold increased by $0.02, due to inflation adjustments in the contracts and
variations in the volumes sold under each contract.
Transportation costs for the CO2 on Denbury's pipeline increased by $0.1
million when comparing the third quarters. This increase is attributable to the
increased volume and the effect of the annual inflation adjustment factor in the
rate paid to Denbury. The rate in the third quarter of 2005 averaged $0.1705 per
Mcf as compared to $0.1623 per Mcf in the 2004 period
Nine Months Ended September 30, 2005 Compared with Nine Months Ended
September 30, 2004
For the nine month period, the increased revenues are attributable to the
same effects as in the 2004 period. Volumes increased due to the additional
contracts, and the average sales price increased by $0.02 per Mcf.
The rate for transportation costs increased from an average of $0.1608 per
Mcf to $0.1679 per Mcf, due to the inflation provision in the transportation
contract.
Outlook
We acquired an 80 Bcf volumetric payment from Denbury in October 2005 at a
cost of $14.4 million in cash. We also acquired two additional long-term sales
contracts with industrial customers.
DISCONTINUED OPERATIONS
In the first nine months of 2005, we sold assets that were no longer in
service related to the Texas operations that we sold in 2003, receiving $0.3
million and recognizing a gain of $0.3 million. During the first nine months of
2004, we incurred costs totaling $0.3 million related to the dismantlement of
assets that we abandoned in 2003.
OTHER COSTS AND INTEREST
General and administrative expenses. General and administrative expenses
were as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
2005 2004 2005 2004
------ ------ ------ ------
(in thousands)
Expenses excluding effect of stock appreciation rights plan .. $2,465 $2,667 $7,077 $7,261
Stock appreciation rights plan expense (credit) .............. 745 (28) (541) 564
------ ------ ------ ------
Total general and administrative expenses ................. $3,210 $2,639 $6,536 $7,825
====== ====== ====== ======
Three Months Ended September 30, 2005 Compared with Three Months Ended
September 30, 2004
General and administrative expenses increased by $0.6 million, however, the
increase is attributable to our employee stock appreciation rights (SAR) plan.
This plan is a long-term incentive plan whereby rights are granted for the
grantee to receive cash equal to the difference between the grant price and
common unit price at date of exercise. The rights vest over several years.
Between the end of the second quarter of 2005 and the end of the third quarter
of 2005, the market price for our units rose $2.21, resulting in an increase in
the liability under the SAR plan of $0.7 million. In the 2004 three month
period, the market price did not change, resulting in a small credit to general
and administrative expense.
The remainder of our general and administrative expenses declined slightly
between the two quarterly periods.
-26-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Nine Months Ended September 30, 2005 Compared with Nine Months Ended
September 30, 2004
For the nine month periods, general and administrative expenses decreased
by $1.3 million, with $1.1 million of the decrease attributable to our employee
stock appreciation rights plan. In the 2004 period, the market price for our
common units rose so that we recorded a liability of $0.6 million. In the 2005
period, our unit price declined from $12.60 per unit at December 31, 2004 to
$11.60 per unit at September 30, 2005. As a result, a reduction in the accrual
was recorded, resulting in a total difference of $1.1 million.
General and administrative expenses, excluding the effects of our stock
appreciation rights (SAR) plan, decreased by $0.2 million between the nine month
periods. We did not incur costs in the 2005 period for assistance in the initial
documentation of our internal controls, although this reduction was partially
offset by higher employee costs.
Equity in T&P Syngas. On April 1, 2005, we acquired a 50% interest in T&P
Syngas. Our share of the earnings of T&P Syngas for the second and third
quarters of 2005 was $436,000. We are amortizing the excess of the price we paid
for our interest in T&P Syngas over our share of the equity of T&P Syngas over
the remaining useful life of the assets of T&P Syngas. This excess of $4.0
million is being amortized over eleven years. The effect of this amortization
was to reduce the amount we recorded as our equity in T&P Syngas by $176,000. In
July 2005, we received a distribution from T&P Syngas of $313,000 related to the
second quarter. In October 2005, we received a distribution of $510,000 related
to the third quarter of 2005.
Interest expense, net. Interest expense, net was as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
2005 2004 2005 2004
---- ---- ------ ----
(in thousands)
Interest expense, including commitment fees ... $461 $134 $1,174 $512
Amortization of facility fees ................. 89 78 265 226
Interest income ............................... (10) (9) (38) (37)
---- ---- ------ ----
Net interest expense ....................... $540 $203 $1,401 $701
==== ==== ====== ====
In the third quarter and first nine months of 2005, we had more debt
outstanding and market interest rates rose. Additionally in June 2004, we
increased the size of our credit facility resulting in increased commitment
fees. These factors contributed to an increase in interest expense in these
periods as compared to the same periods in 2004.
In the 2005 third quarter, our average outstanding balance of bank debt was
$18.6 million higher than in the 2004 third quarter and our average interest
rate was 1.9% greater than in the 2004 period. The debt increase is attributable
primarily to acquisitions in the 2005 period.
In the 2005 nine month period, our average outstanding balance of debt was
$14.5 million higher than in the 2004 period and our average interest rate was
1.8% greater than the 2004 period.
Gain on disposal of surplus assets. In the first nine months of 2005, we
sold the Liberty to Maryland segment of our Mississippi pipeline. This segment
had been out-of-service since February 2002. Additionally, we sold an idle site
in Houma, Louisiana and other surplus assets. We received $1.3 million from the
sales of these assets and realized gains totaling $0.5 million.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL RESOURCES
We have a $100 million credit facility comprised of a $50 million revolving
line of credit for acquisitions and a $50 million working capital revolving
facility. The working capital portion of the credit facility has a $15 million
sublimit for loans with the remainder of the $50 million available for letters
of credit. In total we may have up to $65 million in loans outstanding under our
credit facility. At September 30, 2005, we had $11.8 million in loans and $5.8
million in letters of credit outstanding under the working capital portion and
$20.8 million
-27-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
outstanding under the acquisition portion of our credit. Due to the revolving
nature of loans under our credit facility, additional borrowings and periodic
repayments and re-borrowings may be made until the maturity date of June 1,
2008.
The aggregate amount that we may have outstanding at any time in loans and
letters of credit under the working capital portion of our credit facility is
subject to a borrowing base calculation. The borrowing base is limited to $50
million and is calculated monthly. At September 30, 2005, the borrowing base was
$50.0 million. The total amount available for borrowings at September 30, 2005
was $3.2 million under the working capital portion and $29.2 million under the
acquisition portion of our credit facility.
Certain restrictive covenants in the credit facility limit our ability to
make distributions to our unitholders and the general partner. The credit
facility 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 credit facility, less maintenance capital expenditures, to
the sum of interest expense and distributions. At September 30, 2005, the
calculation resulted in a ratio of 1.1 to 1.0. The credit facility also requires
that the level of operating cash inflows, as adjusted in accordance with the
credit facility, be at least $8.5 million. At September 30, 2005, the result of
this calculation was $10.3 million. If we meet these covenants, we are otherwise
not limited in making distributions.
Our average daily outstanding balance under our credit facility during the
first nine months of 2005 was $17.2 million. The average interest rate we paid
during this same period was 7.13%. The average interest rate on our outstanding
borrowings at September 30, 2005 was 7.36%.
CAPITAL EXPENDITURES
A summary of our capital expenditures in the nine months ended September
30, 2005 and 2004 is as follows:
Nine Months Ended
September 30,
-----------------
2005 2004
------- -------
(in thousands)
Maintenance capital expenditures:
Texas pipeline system ....................... $ 101 $ 109
Mississippi pipeline system ................. 961 370
Jay pipeline system ......................... 7 17
Crude oil gathering assets .................. 10 41
Administrative assets ....................... 46 90
------- -------
Total maintenance capital expenditures ... 1,125 627
Growth capital expenditures:
Mississippi pipeline system ................. 976 5,048
Natural gas gathering assets ................ 3,110 --
T&P Syngas Company investment ............... 13,418 --
CO2 contracts ............................... -- 4,723
Crude oil gathering assets .................. 260 33
------- -------
Total growth capital expenditures ........ 17,764 9,804
------- -------
Total capital expenditures ............ $18,889 $10,431
======= =======
Maintenance capital expenditures in 2005 and 2004 included pipeline and
station improvements in Mississippi to handle increased volumes. Texas pipeline
maintenance capital expenditures related to corrosion control improvements.
Administrative assets included computer software and hardware.
The growth capital expenditures on the Mississippi system in 2005 included
additional tankage. Growth capital expenditures in the first nine months of 2004
related to the acquisition of right-of-way and the initial construction costs
for the extensions of our crude oil pipeline and a CO2 pipeline to Denbury's
Brookhaven field.
-28-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
The natural gas gathering assets were acquired from Multifuels in January
2005. The investment in T&P Syngas was made in April 2005. Crude oil gathering
assets included a crude oil gathering pipeline to move oil from a producer's
wellhead to a connection with a third party pipeline.
Although we have no commitments to make capital expenditures, based on the
information available to us at this time, we currently anticipate that our
maintenance capital expenditures for the remainder of 2005 will total to
approximately $0.4 million. These expenditures are expected to relate primarily
to our Mississippi System, including minor facility improvements and
improvements to the pipeline as a result of integrity management test results
and software and equipment updates in our corporate office.
Complying with Department of Transportation Pipeline Integrity Management
Program (IMP) regulations has been and will be a significant factor in
determining the amount and timing of our capital expenditure requirements. The
IMP regulations required that a baseline assessment be completed within seven
years of March 31, 2002, with 50% of the mileage assessed in the first three and
one-half years. Reassessment is then required every five years. We will complete
the repairs for the first 50% during the fourth quarter of 2005. In addition to
our estimated capital expenditures, we expect to spend $0.5 million in the
remainder of 2005 and $0.3 million in 2006 for pipeline integrity testing and
repairs that will be charged to pipeline operating expense as incurred. As
testing is completed, we are required to take prompt remedial action to address
integrity issues raised by the assessment.
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." We will look for opportunities to acquire assets from other parties
that meet our criteria for stable cash flows such as the two acquisitions
discussed in "Acquisitions in 2005" above. In addition, we acquired a third
volumetric production payment in October 2005 for $14.4 million in cash.
SOURCES OF FUTURE CAPITAL
Our credit facility provides us with $50 million of capacity for
acquisitions and $15 million for borrowings under the working capital portion.
Both portions of the facility are revolving facilities. At September 30, 2005,
we had $32.6 million outstanding under our credit facility, and $32.4 million
available for borrowings. On October 11, 2005, we used $14.4 million of this
availability to purchase a third volumetric production payment.
We expect to use cash flows from operating activities to fund cash
distributions and maintenance capital expenditures needed to sustain existing
operations. Future acquisitions or capital projects for our expansion will
require funding through borrowings under our credit facility or from proceeds
from equity offerings, or a combination of the two sources of funds.
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,
------------------
2005 2004
-------- -------
(in thousands)
Cash provided by (used in):
Operating activities ........ $ 4,243 $ 4,279
Investing activities ........ $(17,367) $(9,126)
Financing activities ........ $ 13,195 $ 2,883
-29-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Operating. Net cash from operating activities for each period have been
comprised of the following:
Nine Months Ended
September 30,
-----------------
2005 2004
------- -------
(in thousands)
Net income (loss) ............................... $ 2,917 $ (300)
Depreciation and amortization ................... 4,695 5,773
Gain on sales of assets ......................... (800) (65)
Direct financing leases ......................... 369 --
Other non-cash items ............................ (799) 837
Changes in components of working capital, net ... (2,139) (1,966)
------- -------
Net cash from operating activities ........... $ 4,243 $ 4,279
======= =======
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.
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 $95.4 million aggregate receivables on
our consolidated balance sheet at September 30, 2005, approximately $94.0
million, or 98.5%, were less than 30 days past the invoice date.
Investing. Cash flows used in investing activities in the first half of
2005 were $17.4 million as compared to $9.1 million in 2004 period. In 2005, we
expended $5.4 million for property additions, including $3.1 million for the
natural gas gathering assets acquired from Multifuels. We made an investment in
T&P Syngas Supply Company utilizing $13.4 million. Offsetting these expenditures
was the receipt of $1.6 million for the sale of idle assets.
In 2004 we expended $4.5 million for property and equipment additions, and
received $0.1 million from the sale of surplus assets. In 2004 we expended cash
for the first phase of an addition to our Mississippi System and to begin
construction on a new tank on the Mississippi System. We used $4.7 million to
acquire a CO2 volumetric payment in 2004.
Financing. In the first nine months of 2005, financing activities provided
net cash of $13.2 million. We increased our borrowings by $17.3 million,
primarily to fund the investment in T&P Syngas and the acquisition of the
natural gas assets. We utilized $4.3 million of cash to make distributions to
our partners.
In the nine months of 2004, financing activities provided net cash of $2.9
million. Our outstanding debt increased $8.0 million. Distributions to our
partners utilized $4.3 million. We also incurred $0.8 million of costs related
to our new credit facility.
DISTRIBUTIONS
As a master limited partnership, the key consideration of our unitholders
is the amount and reliability of our distribution, and our prospects for
distribution increases. We are required by our Partnership Agreement to
distribute 100% of our Available Cash within 45 days after the end of each
quarter to unitholders of record and to our general partner. Available Cash
consists generally of all of our cash receipts less cash disbursements adjusted
for net changes to reserves. Beginning with the distribution for the fourth
quarter of 2003, which was paid in February 2004, we have paid a quarterly
distribution to $0.15 per unit ($1.4 million in total). Beginning with the
distribution for the third quarter of 2005 (payable on November 14, 2005), we
have increased our distribution rate and will pay $0.16 per unit ($1.5 million
in total).
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 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. The likelihood and timing of the
payment of any
-30-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
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 2005.
We believe we will be able to sustain a regular quarterly distribution at
$0.16 per unit for the fourth quarter of 2005. Our ability to increase
distributions during 2006 will depend in part on our success in developing and
executing capital projects and making accretive acquisitions, the results of our
integrity management program testing, and our ability to generate sustained
improvements in the gathering and marketing segment.
Available Cash before reserves for the three and nine months ended
September 30, 2005, is as follows:
Three Nine
Months Months
Ended Ended
September 30, September 30,
2005 2005
------------- -------------
(in thousands)
AVAILABLE CASH BEFORE RESERVES:
Net (loss) income ...................................................... $ (596) $ 2,917
Depreciation and amortization .......................................... 1,601 4,695
Cash received from direct financing leases not included in income ...... 125 369
Cash proceeds in excess of gains on certain asset sales ................ 92 781
Distributions received or to be received from T&P Syngas
in excess of equity recorded ........................................ 502 563
Net non-cash (credits) charges ......................................... (145) (1,137)
Maintenance capital expenditures ....................................... (414) (1,125)
------ -------
Available Cash before reserves ......................................... $1,165 $ 7,063
====== =======
Distributions for the three and nine month period 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, 2005 below.
NON-GAAP FINANCIAL MEASURE
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 us 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 we are generating cash flows at
a level that can support a quarterly cash distribution to our partners. Lastly,
Available Cash (also referred to as distributable cash flow) is a quantitative
standard used throughout the investment community with respect to
publicly-traded partnerships.
Several adjustments to net income are required to calculate Available Cash.
These adjustments include: (1) the addition of non-cash expenses such as
depreciation and amortization expense; (2) miscellaneous non-cash adjustments
such as the addition of decreases or the subtraction of increases in the accrual
for our stock appreciation rights plan expense and the value of financial
instruments; and (3) the subtraction of maintenance capital expenditures.
Maintenance capital expenditures are capital expenditures (as defined by GAAP)
to replace or enhance partially or fully depreciated assets in order to sustain
the existing operating capacity or efficiency of our assets and extend their
useful lives. See "Distributions" above.
The reconciliation of Available Cash (a non-GAAP liquidity measure) to cash
flow from operating activities (the GAAP measure) for the three and nine months
ended September 30, 2005, is as follows:
-31-
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,
2005 2005
------------- -------------
(in thousands)
Cash flows from operating activities ............................... $ 5,098 $ 4,243
Adjustments to reconcile operating cash flows to Available Cash:
Maintenance capital expenditures ................................ (414) (1,125)
Proceeds from sales of certain assets ........................... 221 1,581
Amortization of credit facility issuance fees ................... (92) (279)
Cash effects of stock appreciation rights plan .................. (9) (59)
Effect of distributions from T&P Syngas ......................... 250 563
Net effect of changes in working capital accounts not
included in calculation of Available Cash .................... (3,889) 2,139
------- -------
Available Cash before reserves ..................................... $ 1,165 $ 7,063
======= =======
COMMITMENTS AND OFF-BALANCE SHEET ARRANGEMENTS
CONTRACTUAL OBLIGATION AND COMMERCIAL COMMITMENTS
In addition to our 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,
2005.
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 ............. $ -- $ 32,600 $ -- $ -- $ 32,600
Operating Leases ........... 1,816 3,014 1,434 372 6,636
Interest Payments (1) ...... 2,567 4,241 -- -- 6,808
Unconditional Purchase
Obligations (2) ......... 148,907 85,292 -- -- 234,199
-------- -------- ------ ---- --------
Total Contractual Cash
Obligations ............. $153,290 $125,147 $1,434 $372 $280,243
======== ======== ====== ==== ========
(1) Interest on our long-term debt is at market-based rates. Amount shown for
interest payments represents interest that would be paid if the debt
outstanding at September 30, 2005 remained outstanding through the maturity
date of June 1, 2008 and interest rates remained at the September 30, 2005
market levels through June 1, 2008. Actual obligations may differ from the
amounts included above.
(2) The unconditional purchase obligations included above are contracts to
purchase crude oil, generally at market-based prices. For purposes of this
table, market prices at September 30, 2005, were used to value the
obligations. 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 as disclosed under Contractual Obligation and
Commercial Commitments 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.
-32-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
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," "continue," "believe,"
"estimate," "expect," "plan," "may," "will," or "intend" or the negative of
those terms and similar expressions and statements regarding our business
strategy, plans and objectives of our management for future operations. We make
these statements based on our 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.
Forward-looking statements are not guarantees of performance. They involve
risks, uncertainties and assumptions. Future actions, conditions or events and
future results of operations may differ materially from those expressed in these
forward-looking statements. Many of the factors that will determine these
results are beyond our ability to control or predict. Specific factors that
could cause actual results to differ from those in the forward-looking
statements include:
- demand for the supply of, changes in forecast data for, and price
trends related to crude oil, liquid petroleum, natural gas and natural
gas liquids in the United States, all of which may be affected by
economic activity, capital expenditures by energy producers, weather,
alternative energy sources, international events, conservation and
technological advances;
- throughput levels and rates;
- changes in, or challenges to, our tariff rates;
- our ability to successfully identify and consummate strategic
acquisitions, make cost saving changes in operations and integrate
acquired assets or businesses into our existing operations;
- service interruptions in our pipeline transportation systems;
- shut-downs or cutbacks at refineries, petrochemical plants, utilities
or other businesses for which we transport crude oil or to whom we
sell crude oil;
- changes in laws or regulations to which we are subject;
- our inability to borrow or otherwise access funds needed for
operations, expansions or capital expenditures as a result of existing
debt agreements that contain restrictive covenants;
- loss of key personnel;
- the effects of competition;
- our lack of control over the activities and timing and amount of
distributions of partnerships in which we have invested that we do not
control;
- hazards and operating risks that may not be covered fully by
insurance;
- the condition of the capital markets in the United States;
- the political and economic stability of the oil producing nations of
the world; and
- general economic conditions, including rates of inflation and interest
rates.
You should not put undue reliance on any forward-looking statements. When
considering forward-looking statements, please review the risk factors described
under "Risk Factors" discussed in Item 7, "Management's Discussion and Analysis
of Financial Condition and Results of Operations" in our Annual Report on Form
10-K for
-33-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
the year ended December 31, 2004. Except as required by applicable securities
laws, we do not intend to update these forward-looking statements and
information.
-34-
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Price Risk Management and Financial Instruments
We may be exposed to market risks primarily related to volatility in crude
oil commodity prices and interest rates.
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 effect on future contractual commitments. We
seek to maintain a position that is substantially balanced between crude oil
purchases and sales and future delivery obligations. We utilize NYMEX commodity
based futures contracts and forward contracts to hedge our exposure to these
market price fluctuations as needed. At September 30, 2005, we had entered into
NYMEX future contracts that will settle during October 2005. These contracts
either do not qualify for hedge accounting or are fair value hedges, therefore
the fair value of these derivatives have received mark-to-market treatment in
current earnings. This accounting treatment is discussed further under Note 2
"Summary of Significant Accounting Policies" of our Consolidated Financial
Statements in our Annual Report on Form 10-K.
Sell (Short)
Contracts
------------
Futures Contracts
Contract volumes (1,000 bbls) ........... 63
Weighted average price per bbl .......... $65.321
Contract value (in thousands) ........... $ 4,115
Mark-to-market change (in thousands) .... 58
-------
Market settlement value (in thousands) .. $ 4,173
=======
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, 2005 quoted market prices on the NYMEX.
We are also exposed to market risks due to the floating interest rates on
our credit facility. Our debt bears interest at the LIBOR or prime rate plus the
applicable margin. We do not hedge our interest rates. The average interest rate
presented below is based upon rates in effect at September 30, 2005. The
carrying value of our debt in our credit facility approximates fair value
primarily because interest rates fluctuate with prevailing market rates, and the
credit spread on outstanding borrowings reflects market.
Expected Year
Of Maturity
2008
--------------
(in thousands)
Long-term debt - variable rate 32,600
Average interest rate 7.36%
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. As of the end of the period covered by this
report, we carried out an evaluation, under the supervision of our Chief
Executive Officer and Chief Financial Officer, of the effectiveness of the
design and operation of our disclosure controls and procedures pursuant to Rule
13a-14 of the Exchange Act. Based upon that evaluation, our Chief Executive
Officer and Chief Financial Officer concluded that our disclosure controls and
procedures are adequate
-35-
and effective in all material respects in providing to them in a timely manner
material information relating to us (including our consolidated subsidiaries)
required to be disclosed in this quarterly report.
In addition, there have been no changes in our internal controls over
financial reporting during the three months ended September 30, 2005, 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 12 to the Consolidated Financial Statements
entitled "Contingencies", which is incorporated herein by reference.
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, 2005 By: /s/ ROSS A. BENAVIDES
------------------------------------
Ross A. Benavides
Chief Financial Officer
-36-
Index to Exhibits
31.1 Certification by Chief Executive Officer Pursuant to Rule 13a-14(a)
under the Securities Exchange Act of 1934.
31.2 Certification by Chief Financial Officer Pursuant to Rule 13a-14(a) under
the Securities Exchange Act of 1934.
32.1 Certification by Chief Executive Officer Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
32.2 Certification by Chief Financial Officer Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.