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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2006
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 a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition of "accelerated
filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.
Large accelerated filer [ ] Accelerated filer [X] Non-accelerated filer [ ]
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 May 2,
2006: 13,784,441
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This report contains 38 pages
GENESIS ENERGY, L.P.
FORM 10-Q
INDEX
Page
----
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets - March 31, 2006 and
December 31, 2005.......................................... 3
Consolidated Statements of Operations for the Three Months
Ended March 31, 2006 and 2005.............................. 4
Consolidated Statements of Cash Flows for the Three Months
Ended March 31, 2006 and 2005.............................. 5
Consolidated Statement of Partners' Capital for the Three
Months Ended March 31, 2006................................ 6
Notes to Consolidated Financial Statements.................... 7
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations.................................. 20
Item 3. Quantitative and Qualitative Disclosures about Market Risk.... 36
Item 4. Controls and Procedures....................................... 36
PART II. OTHER INFORMATION
Item 1. Legal Proceedings............................................. 37
Item 1A. Risk Factors.................................................. 37
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds... 37
Item 3. Defaults upon Senior Securities............................... 37
Item 4. Submission of Matters to a Vote of Security Holders........... 37
Item 5. Other Information............................................. 37
Item 6. Exhibits...................................................... 37
SIGNATURES............................................................... 38
-2-
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
(Unaudited)
March 31, December 31,
2006 2005
--------- ------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents ............................................. $ 382 $ 3,099
Accounts receivable:
Trade .............................................................. 86,441 82,119
Related party ...................................................... 527 515
Inventories ........................................................... 7,399 498
Net investment in direct financing leases, net of unearned
income - current portion ........................................... 540 531
Insurance receivable .................................................. 1,353 2,042
Other ................................................................. 1,744 1,645
-------- --------
Total current assets ............................................... 98,386 90,449
FIXED ASSETS, at cost .................................................... 69,912 69,708
Less: Accumulated depreciation ........................................ (36,782) (35,939)
-------- --------
Net fixed assets ................................................... 33,130 33,769
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income ........ 5,803 5,941
CO(2) ASSETS, net of amortization ........................................ 36,693 37,648
INVESTMENT IN T&P SYNGAS SUPPLY COMPANY .................................. 13,120 13,042
OTHER ASSETS, net of amortization ........................................ 864 928
-------- --------
TOTAL ASSETS ............................................................. $187,996 $181,777
======== ========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable:
Trade .............................................................. $ 87,478 $ 82,369
Related party ...................................................... 2,097 2,917
Accrued liabilities ................................................... 6,446 7,325
-------- --------
Total current liabilities .......................................... 96,021 92,611
LONG-TERM DEBT ........................................................... 2,600 --
OTHER LONG-TERM LIABILITIES .............................................. 964 955
COMMITMENTS AND CONTINGENCIES (Note 11)
MINORITY INTERESTS ....................................................... 522 522
PARTNERS' CAPITAL
Common unitholders, 13,784 units issued and outstanding ............... 86,066 85,870
General partner ....................................................... 1,823 1,819
-------- --------
Total partners' capital ............................................ 87,889 87,689
-------- --------
TOTAL LIABILITIES AND PARTNERS' CAPITAL .................................. $187,996 $181,777
======== ========
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 March 31,
----------------------------
2006 2005
-------- --------
REVENUES:
Crude oil gathering and marketing:
Unrelated parties (including revenues from buy/sell arrangements
of $69,772 in 2006 and $85,842 in 2005, respectively) ................. $252,261 $246,824
Related parties .......................................................... 184 184
Pipeline transportation, including natural gas sales:
Unrelated parties ........................................................ 6,590 6,201
Related parties .......................................................... 1,180 1,111
CO(2) revenues .............................................................. 3,387 2,280
-------- --------
Total revenues ........................................................ 263,602 256,600
COST AND EXPENSES:
Crude oil costs:
Unrelated parties (including crude oil costs from buy/sell
arrangements of $68,899 in 2006 and $86,145 in 2005, respectively) .... 245,912 241,811
Related parties .......................................................... 1,460 477
Field operating .......................................................... 3,345 3,832
Pipeline transportation costs:
Pipeline operating costs ................................................. 2,269 2,233
Natural gas purchases .................................................... 2,699 2,636
CO(2) marketing costs:
Transportation costs - related party ..................................... 1,021 717
Other costs .............................................................. 52 38
General and administrative .................................................. 2,660 858
Depreciation and amortization ............................................... 1,864 1,526
Net gain on disposal of surplus assets ...................................... (50) (371)
-------- --------
OPERATING INCOME ............................................................... 2,370 2,843
OTHER INCOME (EXPENSE):
Equity in earnings of investment in T&P Syngas .............................. 313 --
Interest income ............................................................. 78 6
Interest expense ............................................................ (200) (361)
-------- --------
INCOME FROM CONTINUING OPERATIONS .............................................. 2,561 2,488
Income from operations of discontinued Texas System ............................ -- 282
Cumulative effect adjustment of adoption of new accounting principle ........... 30 --
-------- --------
NET INCOME ..................................................................... $ 2,591 $ 2,770
======== ========
NET INCOME PER COMMON UNIT - BASIC AND DILUTED:
Income from continuing operations ........................................... $ 0.18 $ 0.26
Income from discontinued operations ......................................... -- 0.03
Cumulative effect adjustment ................................................ -- --
-------- --------
NET INCOME .................................................................. $ 0.18 $ 0.29
======== ========
WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING ............................ 13,784 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)
Three Months Ended March 31,
----------------------------
2006 2005
------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income .......................................................... $ 2,591 $ 2,770
Adjustments to reconcile net income to net cash (used in) provided
by operating activities -
Depreciation ..................................................... 909 890
Amortization of CO(2) contracts .................................. 955 636
Amortization of credit facility issuance costs ................... 92 93
Amortization of unearned income on direct financing leases ....... (168) (177)
Payments received under direct financing leases .................. 297 297
Equity in earnings of T&P Syngas ................................. (313) --
Distributions from T&P Syngas - return on investment ............. 235 --
Gain on asset disposals .......................................... (50) (653)
Cumulative effect adjustment for new accounting principle ........ (30) --
Other non-cash charges (credits) ................................. 401 (1,320)
Changes in components of working capital -
Accounts receivable ........................................... (4,334) (21,171)
Inventories ................................................... (6,901) 159
Other current assets .......................................... 354 476
Accounts payable .............................................. 4,666 19,171
Accrued liabilities ........................................... (1,001) 1,368
------- --------
Net cash (used in) provided by operating activities .................... (2,297) 2,539
------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment ................................. (163) (3,597)
Proceeds from sale of assets ........................................ 67 1,319
Other, net .......................................................... (32) (546)
------- --------
Net cash used in investing activities .................................. (128) (2,824)
------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Bank borrowings of debt, net ........................................ 2,600 2,200
Other, net .......................................................... (501) 564
Distributions to common unitholders ................................. (2,343) (1,397)
Distributions to General Partner .................................... (48) (29)
------- --------
Net cash (used in) provided by financing activities .................... (292) 1,338
------- --------
Net (decrease) increase in cash and cash equivalents ................... (2,717) 1,053
Cash and cash equivalents at beginning of year ......................... 3,099 2,078
------- --------
Cash and cash equivalents at end of period ............................. $ 382 $ 3,131
======= ========
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 ...................................... 13,784 $85,870 $1,819 $87,689
Net income for the three months ended March 31, 2006 ...................... -- 2,539 52 2,591
Distributions to partners during the three months ended March 31, 2006 .... -- (2,343) (48) (2,391)
------ ------- ------ -------
Partners' capital at March 31, 2006 ....................................... 13,784 $86,066 $1,823 $87,889
====== ======= ====== =======
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
We are a publicly traded Delaware limited partnership formed in December
1996. Our operations are conducted through our operating subsidiary, Genesis
Crude Oil, L.P., and its subsidiary partnerships. We are engaged in pipeline
transportation of crude oil, and, to a lesser degree, natural gas and carbon
dioxide (CO(2)), crude oil gathering and marketing, and industrial gas
activities, including wholesale marketing of CO(2) and processing of syngas
through a joint venture. Our assets are located in the United States Gulf Coast
area.
Our 2% general partner interest is held by Genesis Energy, Inc., a Delaware
corporation and indirect wholly-owned subsidiary of Denbury Resources Inc.
Denbury and its subsidiaries are hereafter referred to as Denbury. Our general
partner also owns a 7.25% interest in us through limited partner interests.
Our general partner manages our operations and activities and employs our
officers and personnel, who devote 100% of their efforts to our management.
Basis of Consolidation and Presentation
The accompanying financial statements and related notes present our
consolidated financial position as of March 31, 2006 and December 31, 2005 and
our results of operations, cash flows and changes in partners' capital for the
three months ended March 31, 2006 and 2005. All significant intercompany
transactions have been eliminated. The accompanying consolidated financial
statements include Genesis Energy, L.P., its operating subsidiary and its
subsidiary partnerships. Our general partner owns a 0.01% general partner
interest in Genesis Crude Oil, L.P., which is reflected in our financial
statements as a minority interest.
In 2005, we acquired a 50% interest in T&P Syngas Supply Company. This
investment is accounted for by the equity method, as we exercise significant
influence over its operating and financial policies. See Note 3.
No provision for income taxes related to our operations is included in the
accompanying consolidated financial statements; as such income will be taxable
directly to the partners holding partnership interests.
2. NEW ACCOUNTING PRONOUNCEMENTS
Adoption of SFAS 123(R) on January 1, 2006
On January 1, 2006, we adopted the provisions of SFAS No. 123(R). In
December 2004, the FASB issued SFAS No. 123 (revised December 2004),
"Share-Based Payments". The adoption of this statement requires that the
compensation cost associated with our stock appreciation rights plan, which upon
exercise will result in the payment of cash to the employee, be re-measured each
reporting period based on the fair value of the rights. Before the adoption of
SFAS 123(R), we 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 on 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. See Note 12.
EITF 04-13
We enter into buy/sell arrangements that are accounted for on a gross basis
in our statements of operations as revenues and costs of crude. These
transactions are contractual arrangements that establish the terms of the
purchase of a particular grade of crude oil at a specified location and the sale
of a particular grade of crude oil at a different location at the same or at
another specified date. These arrangements are detailed either jointly, in a
single contract, or separately, in individual contracts that are entered into
concurrently or in contemplation of one another with a single counterparty. Both
transactions require physical delivery of the crude oil and the risk and reward
of ownership are evidenced by title transfer, assumption of environmental risk,
transportation scheduling, credit risk and counterparty nonperformance risk. In
accordance with the provision of Emerging Issues Task Force Issue No. 04-13,
"Accounting for Purchases and Sales of Inventory with the Same Counterparty," we
will reflect these amounts
-7-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
of revenues and purchases as a net amount in our consolidated statements of
operations beginning in the second quarter of 2006. Additionally, our reported
crude oil gathering and marketing revenues from unrelated parties for the three
months ended March 31, 2006 would be reduced by $70 million to $182 million. Our
reported crude oil costs from unrelated parties for the three months ended March
31, 2006, would be reduced by $69 million to $177 million. We do not believe
this change will have any affect on operating income, net income or cash flows.
SFAS 154
In May 2005, the FASB issued Statement of Financial Standards No. 154,
"Accounting Changes and Error Corrections" (SFAS 154). This statement
established 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. INVESTMENT IN T&P SYNGAS SUPPLY COMPANY
On April 1, 2005, we acquired a 50% interest in T&P Syngas Supply Company,
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. 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 months ended March 31, 2006 included $401,000 as our share of the
operating earnings of T&P Syngas, reduced by amortization of the excess purchase
price of $88,000.
The table below reflects summarized financial information for T&P Syngas at
March 31, 2006.
-8-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended
March 31, 2006
------------------
(in thousands)
Revenues .................................. $1,246
Operating expenses and depreciation ....... (447)
Other income .............................. 3
------
Net income ................................ $ 802
======
March 31, 2006
--------------
(in thousands)
Current assets ............................ $ 1,365
Non-current assets ........................ 16,575
-------
Total assets .............................. $17,940
=======
Current liabilities ....................... $ 310
Partners' capital ......................... 17,630
-------
Total liabilities and partners' capital ... $17,940
=======
4. 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 March 31, 2006, we had $2.6 million in loans and $10.7 million in
letters of credit (primarily for crude oil purchases in March and April 2006)
outstanding under the working capital portion and no balance outstanding under
the acquisition portion of our credit facility. At March 31, 2006, the weighted
average interest rate on the debt was 8.0%. 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 March 31, 2006, the borrowing base was $49.1 million. The remaining
amount available for borrowings at March 31, 2006 was $12.4 million under the
working capital portion and $50.0 million under the acquisition portion of the
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 March 31, 2006, the
calculation resulted in a ratio of 1.4 to 1.0. The credit facility also requires
that the level of operating cash inflows during the prior twelve months, as
adjusted in accordance with the credit facility, be at least $8.5 million. At
March 31, 2006, the result of this calculation was $15.0 million. Our credit
facility also requires that we meet certain other financial ratios, such as a
current ratio, leverage ratio and funded indebtedness to capitalization ratio.
If we meet these covenants, we are otherwise not limited in making
distributions.
5. PARTNERS' CAPITAL AND DISTRIBUTIONS
Partners' Capital
Partner's capital at December 31, 2005 consists of 13,784,441 common units,
including 1,019,441 units owned by our general partner, representing a 98%
aggregate ownership interest in the Partnership and its subsidiaries (after
giving affect to the general partner interest), and a 2% general partner
interest.
-9-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Our general partner owns all of our general partner interest, all of the
0.01% general partner interest in our operating partnership (which is reflected
as a minority interest in the consolidated balance sheet at March 31, 2006) and
operates our business.
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 by our
partnership agreement) 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. We paid distributions of $0.15 per unit ($1.4 million in
total) for the first two quarters of 2005. For the third quarter of 2005 we paid
a distribution of $0.16 per unit ($1.5 million in total). In February 2006, we
paid a distribution of $0.17 per unit ($2.4 million in total) for the fourth
quarter of 2005. In May 2006, we will pay a distribution of $0.18 per unit ($2.5
million in total) for the first quarter of 2006.
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 through March 31, 2006.
-10-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Net Income Per Common Unit
The following table sets forth the computation of basic net income per
common unit (in thousands, except per unit amounts).
Three Months Ended March 31,
----------------------------
2006 2005
------- ------
Numerators for basic and diluted net income (loss) per common unit:
Income from continuing operations ........................................... $ 2,561 $2,488
Less general partner 2% ownership ........................................... 51 50
------- ------
Income from continuing operations available for common unitholders .......... $ 2,510 $2,438
======= ======
Income from discontinued operations ......................................... $ -- $ 282
Less general partner 2% ownership ........................................... -- 6
------- ------
Income from discontinued operations available for common unitholders ........ $ -- $ 276
======= ======
Income from cumulative effect adjustment .................................... $ 30 $ --
Less general partner 2% ownership ........................................... 1 --
------- ------
Income from cumulative effect adjustment available for common unitholders ... $ 29 $ --
======= ======
Denominator for basic and diluted per common unit - weighted average
number of common units outstanding .......................................... 13,784 9,314
======= ======
Basic and diluted net income per common unit:
Income from continuing operations ........................................... $ 0.18 $ 0.26
Income from discontinued operations ......................................... 0.00 0.03
Income from cumulative effect adjustment .................................... 0.00 0.00
------- ------
Net income .................................................................. $ 0.18 $ 0.29
======= ======
6. BUSINESS SEGMENT INFORMATION
Our operations consist of three operating segments: (1) Pipeline
Transportation - interstate and intrastate crude oil, natural gas and CO(2)
pipeline transportation; (2) Industrial Gases - the sale of CO(2) acquired under
volumetric production payments to industrial customers and our investment in a
syngas processing facility, and (3) Crude Oil Gathering and Marketing - the
purchase and sale of crude oil at various points along the distribution chain.
In prior periods, our Industrial Gases segment was called CO(2) Marketing. The
tables below reflect all periods presented as though the current segment
designations had existed, and include only continuing operations data.
We evaluate segment performance based on segment margin. We calculate
segment margin as revenues less costs of sales and operations expenses, and we
include income from investments in joint ventures. We do not deduct depreciation
and amortization. All of our revenues are derived from, and all of our assets
are located in the United States. The pipeline transportation segment
information includes the revenue, segment margin and assets of the direct
financing leases.
-11-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Crude Oil
Pipeline Industrial Gathering and
Transportation Gases (a) Marketing Total
-------------- ---------- ------------- --------
(in thousands)
Three Months Ended March 31, 2006
Segment margin excluding depreciation and
amortization (b) ......................... $ 2,802 $ 2,627 $ 1,728 $ 7,157
Capital expenditures ........................ $ 166 $ -- $ 121 $ 287
Maintenance capital expenditures ............ $ 98 $ -- $ 121 $ 219
Net fixed and other long-term assets (c) .... $33,957 $49,814 $ 5,839 $ 89,610
Revenues:
External Customers .......................... $ 7,098 $ 3,387 $252,445 $262,930
Intersegment (d) ............................ 672 -- -- 672
------- ------- -------- --------
Total revenues of reportable segments ....... $ 7,770 $ 3,387 $252,445 $263,602
======= ======= ======== ========
Three Months Ended March 31, 2005
Segment margin excluding depreciation and
amortization (b) ......................... $ 2,443 $ 1,525 $ 888 $ 4,856
Capital expenditures ........................ $ 3,676 $ -- $ 22 $ 3,698
Maintenance capital expenditures ............ $ 489 $ -- $ 22 $ 511
Net fixed and other long-term assets (c) .... $35,591 $25,708 $ 6,096 $ 67,395
Revenues:
External Customers .......................... $ 6,633 $ 2,280 $247,008 $255,921
Intersegment (d) ............................ 679 -- -- 679
------- ------- -------- --------
Total revenues of reportable segments ....... $ 7,312 $ 2,280 $247,008 $256,600
======= ======= ======== ========
a) Industrial gases includes our CO(2) marketing operations and the income
from our investment in T&P Syngas Supply Company.
b) Segment margin was calculated as revenues less cost of sales and operations
expense. It includes our share of the operating income of equity joint
ventures. A reconciliation of segment margin to income from continuing
operations for the periods presented is as follows:
Three Months Ended March 31,
----------------------------
2006 2005
------- -------
(in thousands)
Segment margin excluding depreciation and amortization .... $ 7,157 $ 4,856
General and administrative expenses ....................... (2,660) (858)
Depreciation, amortization and impairment ................. (1,864) (1,526)
Net gain on disposal of surplus assets .................... 50 371
Interest expense, net ..................................... (122) (355)
------- -------
Income from continuing operations ......................... $ 2,561 $ 2,488
======= =======
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.
-12-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
d) Intersegment sales were conducted on an arm's length basis.
7. TRANSACTIONS WITH RELATED PARTIES
Sales, purchases and other transactions with affiliated companies, in the
opinion of management, are conducted under terms no more or less favorable than
then-existing market conditions.
Three Months Ended March 31,
----------------------------
2006 2005
------ ------
(in thousands)
Transactions with Denbury and our General Partner
Crude oil purchases from Denbury ........................................ $1,460 $ 483
Truck transportation services provided to Denbury ....................... $ 184 $ 184
Pipeline transportation services provided to Denbury .................... $ 993 $ 923
Payments received under direct financing leases from Denbury ............ $ 297 $ 297
Pipeline transportation income portion of direct financing lease fees ... $ 167 $ 176
Pipeline monitoring services provided to Denbury ........................ $ 15 $ 7
Directors' fees paid to Denbury ......................................... $ 30 $ 30
CO(2) transportation services provided by Denbury ....................... $1,021 $ 717
Operations, general and administrative services provided by our
general partner ...................................................... $4,893 $4,109
Distributions to our general partner on its limited partner units and
general partner interest ............................................. $ 221 $ 132
Transportation Services
We provide truck transportation services to Denbury to move their crude oil
from the wellhead to our Mississippi pipeline. Denbury pays us a fee for this
trucking 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.
Denbury is 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 CO(2) pipeline and recorded
pipeline transportation income from these arrangements.
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 four Denbury officers who serve as
directors of our general partner at the same rate at which our independent
directors are paid.
CO(2) Operations and Transportation
We acquired contracts, along with volumetric production payments, from
Denbury in 2005 and prior years. Denbury charges us a transportation fee of
$0.16 per Mcf (adjusted for inflation) to deliver the CO(2) 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 March 31, 2006 and December 31, 2005, we owed Denbury $1.5 million and
$1.9 million, respectively, for purchases of crude oil and CO(2) transportation
charges. Denbury owed us $0.5 million and $0.5 million for transportation
services at March 31, 2006 and December 31, 2005, respectively. We owed our
general partner $0.6 million and $1.1 million at March 31, 2006 and December 31,
2005, respectively, for administrative services.
-13-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. Those obligations are
not guaranteed by Denbury or any of its other subsidiaries.
8. 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 23%
and 16% of total revenues in the first quarter of 2006, respectively. Occidental
Energy Marketing, Inc., Plains All American, L.P. and Shell Oil Company
accounted for 28%, 11% and 10% of total revenues for the first quarter of 2005,
respectively. The majority of the revenues from these three customers in both
periods relate to our gathering and marketing operations.
9. SUPPLEMENTAL CASH FLOW INFORMATION
We received interest payments of $101,000 and $6,000 for the three months
ended March 31, 2006 and 2005, respectively. Payments of interest and commitment
fees were $328,000 and $14,000 for the three months ended March 31, 2006 and
2005, respectively.
At March 31, 2006, 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.
10. DERIVATIVES
Our market risk in the purchase and sale of crude oil contracts is the
potential loss that can be caused by a change in the market value of the asset
or commitment. In order to hedge our exposure to such market fluctuations, we
may enter into various financial contracts, including futures, options and
swaps. Historically, any contracts we have used to hedge market risk were less
than one year in duration, 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
-14-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 March 31, 2006, we had forward and
futures contracts 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 March 31, 2006. We marked these
contracts to fair value at March 31, 2006. During the three months ended March
31, 2006, we recorded losses of $87,000 related to derivative transactions,
which is included in the consolidated statements of operations under the caption
"Crude Oil Costs".
At March 31, 2006, we had futures and forward contracts that qualified as
derivatives and were formally documented and designated as fair value hedges of
inventory. During the three months ended March 31, 2006, we recognized losses,
due to hedge ineffectiveness, on the fair value hedge of inventory of less than
$1,000. These losses 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 March 31, 2006 includes a reduction in
other current assets of $498,000 as a result of these derivative transactions.
The consolidated balance sheet at December 31, 2005 included an increase in
other current assets of $6,000 as a result of derivative transactions.
At March 31, 2005, we had futures contracts on the NYMEX qualifying as
derivatives that did not meet the criteria for hedge accounting. The fair value
of these contracts was determined based on the closing price for such contracts
on the NYMEX on March 31, 2005. We marked these contracts to fair value at March
31, 2005, and recorded a loss of $9,000 which is included in the consolidated
statement of operations under the caption "Crude Oil Costs".
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 March 31, 2006 and December 31, 2005.
11. CONTINGENCIES
Guarantees
We guaranteed $1.4 million of residual value related to the leases of
tractors and trailers from Ryder. 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 our
operating partnership to the banks under the terms of our credit facility
related to borrowings and letters of credit. To the extent liabilities exist
under the letters of credit, such liabilities are included in the consolidated
balance sheet. Borrowings at March 31, 2006 were $2.6 million and are reflected
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 $0.2 million in 2006 and
2007 for testing, repairs and improvements under regulations requiring
assessment of the integrity of crude oil pipelines. After 2007 we expect that
our annual expenditures for integrity testing, repairs and improvements to
average from $1.0 million to $1.5 million.
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.
-15-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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
third party claims 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 in 2002. In 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.
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 intend to seek recovery of 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 and affected
groundwater at the Jay Station. We have accrued an estimate of our share of
liability for this matter in the amount of $0.5 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.
-16-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
12. STOCK APPRECIATION RIGHTS PLAN
Under the terms of our stock appreciation rights plan, all regular,
full-time active employees and the members of the Board are eligible to
participate in the plan. The plan is administered by the Compensation Committee
of the Board, who shall determine, in its full discretion, the number of rights
to award, the grant date of the units and the formula for allocating rights to
the participants and the strike price of the rights awarded. Each right is
equivalent to one common unit.
The rights have a term of 10 years from the date of grant. The initial
award to a participant will vest one-fourth each year beginning with the first
anniversary of the grant date of the award. Subsequent awards to participants
will vest on the fourth anniversary of the grant date. If the right has not been
exercised at the end of the ten year term and the participant has not terminated
his employment with us, the right will be deemed exercised as of the date of the
right's expiration and a cash payment will be made as described below.
Upon vesting, the participant may exercise his rights and receive a cash
payment calculated as the difference between the average of the closing market
price of our common units for the ten days preceding the date of exercise over
the strike price of the right being exercised. The cash payment to the
participant will be net of any applicable withholding taxes required by law. If
the Committee determines, in its full discretion, that it would cause
significant financial harm to the Partnership to make cash payments to
participants who have exercised rights under the plan, then the Committee may
authorize deferral of the cash payments until a later date.
Termination for any reason other than death, disability or normal
retirement (as these terms are defined in the plan) will result in the
forfeiture of any non-vested rights. Upon death, disability or normal
retirement, all rights will become fully vested. If a participant is terminated
for any reason within one year after the effective date of a change in control
(as defined in the plan) all rights will become fully vested.
Prior to January 1, 2006, we had accounted for this plan under the
provisions of 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 on that date. On January 1, 2006, we adopted
SFAS No. 123 (revised December 2004), "Share-Based Payments". The adoption of
this statement requires that the compensation cost associated with our stock
appreciation rights plan, which upon exercise will result in the payment of cash
to the employee, be re-measured each reporting period based on the fair value of
the rights. 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 have elected to calculate the fair value of the rights under the plan
using the Black-Scholes valuation model. This model requires that we include the
expected volatility of the market price for our common units, the current price
of our common units, the exercise price of the rights, the expected life of the
rights, the current risk free interest rate, and our expected annual
distribution yield. This valuation is then applied to the vested rights
outstanding and to the non-vested rights based on the percentage of the service
period that has elapsed. The valuation is adjusted for expected forfeitures of
rights (due to terminations before vesting, or expirations after vesting). The
liability amount accrued on the balance sheet is adjusted to this amount at each
balance sheet date with the adjustment reflected in the statement of operations.
The estimates that we made upon the adoption of this standard included the
following:
- In determining the expected life of the rights, we used the simplified
method allowed by the Securities and Exchange Commission. As our stock
appreciation rights plan was not put in place until December 31, 2003,
we have very limited experience with employee exercise patterns. The
simplified method produces an initial expected life of 6.25 years for
those rights we issued that vest 25% per year for four years, and an
initial expected life of 7 years for those rights we issued that fully
vest at the end of a four-year period.
- The expected volatility of our units was computed using the historical
period we believe is representative of future expectations. We
determined what period to use in the historical period by
-17-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
considering whether we were paying distributions to our unitholders,
and at what rate. The expected volatility used in the fair value
calculations was approximately 33% at both January 1, 2006 and March
31, 2006.
- The risk-free interest rate was determined from current yields for
U.S. Treasury zero-coupon bonds with a term similar to the remaining
expected life of the rights. At January 1, 2006, the risk-free
interest rate ranged from 4.39% to 4.41%. At March 31, 2006, the
risk-free interest rate ranged from 4.71% to 4.73%.
- In determining our expected future distribution yield, we considered
our history of distribution payments, our expectations for future
payments, and the distribution yields of entities similar to us. At
January 1, 2006 and March 31, 2006, we used an expected future
distribution yield of 6%.
- The final estimate we were required to make is the expected
forfeitures of non-vested rights and expirations of vested rights. We
have very limited experience with employee forfeiture and expiration
patterns, as our plan was not initiated until December 31, 2003. We
reviewed the history available to us as well as employee turnover
patterns in determining the rates to use. We also used different
estimates for different groups of employees.
At December 31, 2005, we had a recorded liability of $0.8 million, computed
under the provisions of FASB Interpretation No. 28. We calculated the effect of
adoption of SFAS 123(R) at January 1, 2006, and determined that our recorded
liability at December 31, 2005 should be reduced by $30,000. This reduction is
reflected as income from the cumulative effect of the adoption of a new
accounting principle on our statement of operations. We do not believe the
effect of adoption of this accounting principle at January 1, 2005 would have
been material. The adjustment of the liability to its fair value at March 31,
2006, resulted in expense of $0.2 million that is included in general and
administrative expenses.
The following table reflects rights activity under our plan as of December
31, 2005, and changes during the first quarter of 2006:
Weighted
Weighted Average Aggregate
Average Remaining Intrinsic
Exercise Contractual Value
Stock Appreciation Rights Rights Price Term (Yrs) (in thousands)
- ------------------------- ------- -------- ----------- --------------
Outstanding at January 1, 2006 596,128 $10.39
Granted 4,012 $12.24
Exercised (6,974) $ 9.26
Forfeited or expired (11,670) $11.49
-------
Outstanding at March 31, 2006 581,496 $10.39 8.4 $1,215
=======
Exercisable at March 31, 2006 153,304 $ 9.47 7.8 $ 461
=======
The weighted-average fair value at March 31, 2006 of rights granted during
the first quarter of 2006 was $2.61 per right. The total intrinsic value of
rights exercised during the first quarter of 2006 was $18,000, which was paid in
cash to the participants.
At March 31, 2006, there was $0.7 million of total unrecognized
compensation cost related to rights that we expect will vest under the plan.
This amount was calculated as the fair value at March 31, 2006 multiplied by
those rights for which compensation cost has not been recognized, adjusted for
estimated forfeitures. This unrecognized cost will be recalculated at each
balance sheet until the rights are exercised, forfeited or expire. For the
awards outstanding at March 31, 2006, the remaining cost will be recognized over
a weighted average period of 1.8 years.
-18-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
13. SUBSEQUENT EVENTS
Sandhill Investment
On April 5, 2006 we acquired a 50% partnership interest in Sandhill Group,
LLC for $5 million from Magna Carta Group, LLC. Magna Carta holds the other 50%
interest in Sandhill. The acquisition was funded with cash on hand. The terms of
the acquisition include earnout provisions such that additional payments of up
to $2.0 million would be paid by us to Magna Carta if Sandhill achieves targeted
performance levels during the seven years between 2006 and 2012 inclusive. We
have also guaranteed to Sandhill's lender 50% of the outstanding debt of $4.7
million, or $2.36 million.
Sandhill is a limited liability company that owns a CO(2) processing
facility located in Brandon, Mississippi. Sandhill is engaged in the production
and distribution of liquid carbon dioxide for use in the food, beverage,
chemical and oil industries. The facility acquires CO(2) from us under a
long-term supply contract that we acquired in 2005 from Denbury.
Sandhill is managed by a management committee consisting of two
representatives each from Magna Carta and us. Our equity in the earnings of
Sandhill will be included in our industrial gases segment.
Distribution
On April 20, 2006, the Board of Directors of the general partner declared a
cash distribution of $0.18 per unit for the quarter ended March 31, 2006. The
distribution will be paid May 15, 2006 to our general partner and all common
unitholders of record as of the close of business on May 2, 2006.
-19-
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 2006
- Results of Operations
- 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. Segment
margin also includes our equity in the operating income of joint ventures. A
reconciliation of segment margin to income from continuing operations is
included in our segment disclosures in Note 6 to the consolidated financial
statements. Available Cash before Reserves is a non-GAAP liquidity measure
calculated as net income with several adjustments, the most significant of which
are the elimination of gains and losses on asset sales, except those from the
sale of surplus assets, the addition of non-cash expenses such as depreciation,
the replacement with the amount recognized as our equity in the income of joint
ventures with the available cash generated 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 conduct our business through three segments - pipeline transportation,
industrial gases and crude oil gathering and marketing. We have a diverse
portfolio of customers and assets, including pipeline transportation of
primarily crude oil and, to a lesser extent, natural gas and carbon dioxide
(CO(2)) in the Gulf Coast region of the United Sates. In conjunction with our
crude oil pipeline transportation operations, we operate a crude oil gathering
and marketing business, which helps ensure a base supply of crude oil for our
pipelines. We also participate in industrial gas activities, including a CO(2)
supply business, which is associated with the CO(2) tertiary oil recovery
process being used in Mississippi by an affiliate of our general partner. We
generate revenues by selling crude oil and industrial gases, by charging fees
for the transportation of crude oil, natural gas and CO(2) on our pipelines,
and, through our joint venture in T&P Syngas Supply Company, by charging fees
for services to produce syngas for our customer from the customer's raw
materials. Our focus is on the margin we earn on these revenues, which is
calculated by subtracting the costs of the crude oil and natural gas; the costs
of transporting the crude oil, natural gas and CO(2) to the customer; and the
costs of operating our assets. We also report our share of the earnings of our
joint venture, T&P Syngas, in which we acquired a 50% interest on April 1, 2005.
Our objective is to operate as a growth-oriented midstream MLP with a focus
on increasing cash flow, earnings and return to our unitholders by becoming one
of the leading providers of pipeline transportation, crude oil gathering and
marketing and industrial gas services in the regions in which we operate.
Increases in cash flow generally result in increases in Available Cash, which we
distribute quarterly to our unitholders and general partner. During the first
quarter of 2006, we generated $5.0 million of Available Cash before Reserves,
and distributed $2.4 million to our unitholders and general partner. During the
first quarter of 2006, cash utilized in operations was $2.3 million.
In the first quarter of 2006, we generated net income of $2.6 million, or
$0.18 per common unit. The results for the first quarter of 2006 include
increased segment margin from our pipeline transportation and crude oil
gathering and marketing segments and significant contributions from asset
acquisitions in the industrial gases
-20-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
segment. We also adopted a new accounting pronouncement affecting the manner in
which we value and account for our stock appreciation rights plan.
We increased our cash distribution by $0.01 to $0.17 per unit for the
fourth quarter of 2005 (which was paid in February 2006) and increased our cash
distribution again to $0.18 per unit for the first quarter of 2006. This
distribution will be paid in May 2006. This distribution represented a 20%
increase from our distribution of $0.15 per unit for the first quarter of 2005.
ACQUISITIONS IN 2006
SANDHILL INVESTMENT
On April 5, 2006 we acquired a 50% partnership interest in Sandhill Group,
LLC for $5 million from Magna Carta Group, LLC. Magna Carta holds the other 50%
interest in Sandhill. The acquisition was financed with cash on hand. The terms
of the acquisition include earnout provisions such that additional payments of
up to $2.0 million would be paid by us to Magna Carta if Sandhill achieves
targeted performance levels during the seven years between 2006 and 2012
inclusive. We have also guaranteed to Sandhill's lender 50% of the outstanding
debt of $4.7 million, or $2.36 million.
Sandhill is a limited liability company that owns a CO(2) processing
facility located in Brandon, Mississippi. Sandhill is engaged in the production
and distribution of liquid carbon dioxide for use in the food, beverage,
chemical and oil industries. The facility acquires CO(2) from us under a
long-term supply contract that we acquired in 2005 from Denbury.
Sandhill is managed by a management committee consisting of two
representatives each from Magna Carta and us. Our equity in the earnings of
Sandhill will be included in our industrial gases segment.
RESULTS OF OPERATIONS
PIPELINE TRANSPORTATION OPERATIONS
We operate three crude oil common carrier pipeline systems in a four state
area. We refer to these pipelines as our Texas System, Mississippi System and
Jay System. Volumes shipped on these systems for the first quarters of 2006 and
2005 are as follows:
Three Months Ended
March 31,
------------------
Pipeline System - barrels per day 2006 2005
- --------------------------------- ------ ------
Mississippi 16,409 16,139
Jay 11,414 14,853
Texas 34,235 29,828
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
future increases in production volumes in the area that are expected, we have
made capital expenditures for tank, station and pipeline improvements and we
intend to make further improvements. See Capital Expenditures under "Liquidity
and Capital Resources" below.
Denbury is the largest producer (based on average barrels produced per day)
of crude oil in the State of Mississippi. Our Mississippi System is adjacent to
several of Denbury's existing and prospective oil fields. As Denbury continues
to acquire and develop old oil fields using CO(2) based tertiary recovery
operations, additional crude oil gathering and CO(2) supply infrastructure will
be needed, although we can provide no assurance that we will be involved in any
such projects.
-21-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
The Jay pipeline system in Florida/Alabama ships crude oil from fields with
relatively short remaining production lives. Throughput declined from an annual
average of 14,440 barrels per day in 2004 to 13,725 barrels per day in 2005,
although part of the decline in these years can be attributed to hurricanes that
passed near the panhandle of Florida. In the first quarter of 2006, throughput
declined further to a daily average of 11,414 barrels.
While new production in the area surrounding the Jay System has offset some
of the declining production curves of the older producing fields in the area, we
do not know if this new production will be sufficient to continue to offset
declining production from existing wells in the area. One of the larger older
fields has been unable to return to its production levels before the hurricanes
of 2005. Another producing field reduced production during part of the first
quarter for maintenance. In the last month of the first quarter, volumes started
to improve from these fields, resulting in total average throughput for March at
12,575 barrels per day. We do not know if these producers will be successful in
returning to production levels before the hurricanes.
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 2006 or 2007.
Volumes on our Texas System averaged 34,235 barrels per day during the
first quarter of 2006. 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. We have a joint tariff with
TEPPCO under which we earned $0.20 per barrel on the majority of the barrels we
deliver to the shipper's facilities. Substantially all of the volume being
shipped on our Texas System goes to two refineries on the Texas Gulf Coast.
Our Texas System is dependent on the connecting carriers for supply, and on
the two refineries for demand for our services. Volumes on the Texas System
fluctuate as a result of changes in the supply available for the two refineries
to acquire and ship on our pipeline. We lease tankage in Webster on the Texas
System of approximately 165,000 barrels. We have a tank rental reimbursement
agreement with the primary shipper on our Texas System to reimburse us for the
expense of leasing of that storage capacity. 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 operate a CO(2) pipeline in Mississippi to transport CO(2) from
Denbury's main CO(2) pipeline to Brookhaven oil field. Denbury has the exclusive
right to use this CO(2) pipeline. This arrangement has been accounted for as a
direct financing lease.
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 power cost increases. We perform regular maintenance on
our assets to keep them in good operational condition and to minimize cost
increases.
Operating results from continuing operations for our pipeline
transportation segment were as follows:
-22-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Three Months Ended March 31,
----------------------------
2006 2005
------- -------
(in thousands)
Crude oil tariffs and revenues from direct financing
leases of crude oil pipelines ............................. $ 3,333 $ 3,264
Sales of crude oil pipeline loss allowance volumes ........... 1,318 1,079
Revenues from direct financing leases of CO(2) pipelines ..... 87 92
Tank rental reimbursements and other miscellaneous revenues .. 144 133
------- -------
Total revenues from crude oil and CO(2) tariffs, including
revenues from direct financing leases ..................... 4,882 4,568
Revenues from natural gas tariffs and sales .................. 2,888 2,744
Natural gas purchases ........................................ (2,699) (2,636)
Pipeline operating costs ..................................... (2,269) (2,233)
------- -------
Segment margin ............................................ $ 2,802 $ 2,443
======= =======
Crude oil pipeline volumes per day - barrels ................. 62,058 60,821
Three Months Ended March 31, 2006 Compared with Three Months Ended March
31, 2005
Pipeline segment margin increased $0.4 million or 15% to $2.8 million for
the three months ended March 31, 2006, as compared to $2.4 million for the three
months ended March 31, 2005. Revenues from crude oil and CO(2) tariffs and
related sources added the majority of the increase for the period. Higher market
prices for crude oil added $0.2 million to pipeline loss allowance revenues,
with the remainder of the increase from variations in volumes and higher tariffs
on the Jay System than in the prior period.
Costs of operating the pipelines remained the same as in the 2005 period.
INDUSTRIAL GASES SEGMENT
Our industrial gases segment includes the results of our CO(2) sales to
industrial customers and our share of the operating income of our 50%
partnership interest in T&P Syngas.
CO(2)
We supply CO(2) to industrial customers under seven long-term CO(2) sales
contracts. We acquired those contracts, as well as the CO(2) necessary to
satisfy substantially all of our expected obligations under those contracts, in
three separate transactions with Denbury. We sell our CO(2) to customers who
treat the CO(2) and sell it to end users for use for beverage carbonation and
food chilling and freezing. Our compensation for supplying CO(2) to our
industrial customers is the effective difference between the price at which we
sell our CO(2) under each contract and the price at which we acquired our CO(2)
pursuant to our volumetric production payments (VPPs), minus transportation
costs. We expect our CO(2) contracts to provide stable cash flows until they
expire, at which time we will attempt to extend or replace those contracts,
including acquiring the necessary CO(2) supply from wholesalers. At March 31,
2006, we have 231.1 Bcf of CO(2) remaining under the VPPs.
The terms of our contracts with the industrial CO(2) customers include
minimum take-or-pay and maximum delivery volumes. The maximum daily contract
quantity per year in the contracts totals 98,000 Mcf. Under the minimum
take-or-pay volumes, the customers must purchase a total of 51,000 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 three years ended December 31, 2005, all
of our customers purchased more than their minimum take-or-pay quantities.
Our seven industrial contracts expire at various dates beginning in 2010
and extending through 2023. The sales contracts contain provisions for
adjustments for inflation to sales prices based on the Producer Price Index,
with a minimum price.
-23-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Our industrial customers treat the CO(2) and transport it to their own
customers. The primary industrial applications of CO(2) by these customers
include beverage carbonation and food chilling and freezing. Based on historical
data for 2004 through 2006, we can expect some seasonality in our sales of
CO(2). 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 table below depicts
these seasonal fluctuations. The average daily sales (in Mcfs) of CO(2) for each
quarter in 2006, 2005 and 2004 under these contracts (including volumes sold by
Denbury on the contracts we acquired in the third quarter of 2004 and fourth
quarter of 2005) were as follows:
Quarter 2006 2005 2004
- ------- ------ ------ ------
First 66,565 67,434 63,953
Second 73,307 73,734
Third 77,264 78,097
Fourth 77,089 70,696
Syngas
On April 1, 2005, we acquired from TCHI Inc., a wholly owned subsidiary of
ChevronTexaco Global Energy Inc., a 50% partnership interest in T&P Syngas for
$13.4 million in cash, which we funded with proceeds from our credit facility.
T&P Syngas is a partnership which owns a facility located in Texas City, Texas
that manufactures syngas (a combination of carbon monoxide and hydrogen) and
high-pressure steam. Under that processing agreement, Praxair provides the raw
materials to be processed and receives the syngas and steam produced by the
facility. T&P Syngas receives a processing fee for its services. Praxair has the
exclusive right to use the facility through at least 2016 (term extendable at
Praxair's option for two additional five year terms). Praxair also is our
partner in the joint venture and owns the remaining 50% interest. We recognize
our share of the earnings of T&P Syngas in each period. 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. We receive
cash distributions from T&P Syngas quarterly.
Operating results from continuing operations for our industrial gases
segment were as follows:
Three Months Ended March 31,
----------------------------
2006 2005
------- -------
(in thousands)
Revenues from CO(2) sales ............. $ 3,387 $ 2,280
CO(2) transportation and other costs .. (1,073) (755)
Equity in earnings of T&P Syngas ...... 313 --
------- -------
Segment margin ..................... $ 2,627 $ 1,525
======= =======
CO(2) sales - Mcf per day ............. 66,565 47,808
Three Months Ended March 31, 2006 Compared with Three Months Ended March
31, 2005
The increasing margins from the industrial gases segment between the first
quarter of 2005 and 2006 are primarily attributable to the acquisition we made
in the fourth quarter of 2005 in this segment. The average revenue per Mcf sold
increased almost 7% between the periods, due to inflation adjustments in the
contracts and variations in the volumes sold under each contract.
Transportation costs for the CO(2) on Denbury's pipeline have increased due
to the increased volume and the effect of the annual inflation factor in the
rate paid to Denbury. The rate per Mcf in 2006 increased 2% over the 2005 first
quarter rate.
-24-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Our share of the operating income of T&P Syngas for the three months of
2006 was $401,000. We reduced the amount we recorded as our equity in T&P Syngas
by $88,000 as amortization of the excess purchase price of T&P Syngas. During
the first quarter of 2006, T&P Syngas paid us a distribution totaling $0.2
million attributable to the fourth quarter of 2005.
CRUDE OIL GATHERING AND MARKETING OPERATIONS
We conduct certain crude oil aggregating operations, which involve
purchasing, gathering, transporting by trucks and pipelines owned by us and
trucks, pipelines and barges operated by others, and reselling, that (among
other things) help ensure a base supply source for our crude oil pipeline
systems. Our profit for those services is derived from the difference between
the price at which we re-sell crude oil less the price at which we purchase that
crude oil, minus the associated costs of aggregation and any cost of supplying
credit. The most substantial component of our aggregating costs relates to
operating our fleet of leased trucks. Our crude oil gathering and marketing
activities provide us with an extensive expertise, knowledge base and skill set
that facilitates our ability to capitalize on regional opportunities which arise
from time to time in our market areas. Usually this segment experiences limited
commodity price risk because we generally make back-to-back purchases and sales,
matching our sale and purchase volumes on a monthly basis.
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 generally
meaningful in analyzing the variation in segment margin for our gathering and
marketing operations, these changes are not addressed in the following
discussion.
Generally, as we purchase crude oil, we simultaneously establish a margin
by selling crude oil for physical delivery to third party users, such as
independent refiners or major oil companies. Through these transactions, we seek
to maintain a position that is substantially balanced between crude oil
purchases, on the one hand, and sales or future delivery obligations, on the
other hand. We do not hold crude oil, futures contracts or other derivative
products for the purpose of speculating on crude oil price changes.
Most of our contracts for the purchase and sale of crude oil have
components in the pricing provisions such that the price paid or received is
adjusted for changes in the market price for crude oil. The pricing in the
majority of our purchase contracts contain the market price component, a bonus
that is not fixed, but instead is based on another market factor and a deduction
to cover the cost of transporting the crude oil and to provide us with a margin.
Contracts will sometimes also contain a grade differential which considers the
chemical composition of the crude oil and its appeal to different customers.
Typically the pricing in a contract to sell crude oil will consist of the market
price components and the grade differentials. The margin on individual
transactions is then dependent on our ability to manage our transportation costs
and to capitalize on grade differentials.
Field operating costs consist of the costs to operate our fleet of leased
trucks used to transport crude oil, and the costs to maintain the trucks and
assets used in the crude oil gathering operation. More than 60% of these costs
are variable and increase or decrease with volumetric changes. These 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:
-25-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Three Months Ended March 31,
----------------------------
2006 2005
--------- ---------
(in thousands)
Revenues ................................................... $ 252,445 $ 247,008
Crude oil costs ............................................ (247,372) (242,288)
Field operating costs ...................................... (3,345) (3,832)
--------- ---------
Segment margin .......................................... $ 1,728 $ 888
========= =========
Volumes per day:
Crude oil wellhead - barrels ............................ 36,624 41,969
Crude oil total - barrels (includes wellhead barrels) ... 45,288 58,346
Crude oil truck transported only - barrels .............. 2,767 5,122
Three Months Ended March 31, 2006 as Compared to Three Months Ended March
31, 2005
Gathering and marketing segment margins increased $0.8 million or 95% to
$1.7 million for the three months ended March 31, 2006, as compared to $0.9
million for the three months ended March 31, 2005.
The primary reasons for this increase in segment margin were an improvement
in marketing margins and a decrease in field costs. An increase in the average
difference between the sales price and the purchase price of crude oil increased
segment margin by $0.5 million, despite a 13,058 barrel per day decrease in
purchased volumes. The majority of the decrease in field operating costs of $0.5
million is attributable to a reduction in the size of our fleet. When we leased
new trucks late in 2005, we reduced the size of the fleet to better match the
volumes being purchased. This reduction in fleet size reduced personnel and
truck lease costs. Higher fuel costs offset part of the reduction. Fuel costs
increased almost $0.50 per gallon over the 2005 quarter.
Partially offsetting the effects of the decreased field costs was a $0.2
million decrease in revenues from volumes that we transported for a fee but did
not purchase.
OTHER COSTS AND INTEREST
Three Months Ended March 31, 2006 Compared with Three Months Ended March
31, 2005
General and administrative expenses. General and administrative expenses
consisted of the following:
Three Months Ended March 31,
----------------------------
2006 2005
------ -------
(in thousands)
Expenses excluding the effects of the
stock appreciation rights plan ................. $2,508 $ 2,187
Stock appreciation rights plan expense (credit) ... 152 (1,329)
------ -------
Total general and administrative expense ....... $2,660 $ 858
====== =======
General and administrative expenses increased by $1.8 million, however, the
increase is primarily attributable to our employee stock appreciation rights
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. In
2005 we accounted for these rights under the provisions of FASB Interpretation
No. 28, which provided that we calculate the difference between the current
market price for our common units and the strike price of the rights. At March
31, 2005, our unit price was $8.90 per unit, a decline from $12.60 per unit at
December 31, 2004. As a result, all rights were "out of the money", and the
liability at December 31, 2004 was reversed, resulting in a credit of $1.3
million. On January 1, 2006, we adopted the provisions of a new accounting
pronouncement for accounting for stock-based compensation. Under this
pronouncement, we determine the fair value of the rights at each balance sheet
date, and record the change in fair value over the service period required from
our employees before the rights
-26-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
vest. See additional discussion below under "Cumulative Effect Adjustment of
Adoption of New Accounting Principle" and in Note 12 to the financial
statements.
Also increasing general and administrative expenses were increases in
employee costs, including benefits and bonus accruals, offset slightly by a
reduction in office rent from a lease renegotiation.
Depreciation, amortization and impairment expense increased $0.3 million
between 2005 and 2006 first quarters. The majority of this increase related to
amortization of our CO(2) assets. Amortization of the CO(2) assets increased due
to the additional CO(2) contracts acquired in the fourth quarter of 2005.
Interest expense, net.
Interest expense, net was as follows:
Three Months Ended March 31,
----------------------------
2006 2005
---- ----
(in thousands)
Interest expense, including commitment fees ... $115 $273
Amortization of facility fees ................. 85 88
Interest income ............................... (78) (6)
---- ----
Net interest expense ....................... $122 $355
==== ====
In the 2006 first quarter, our net interest expense decreased by $0.2
million compared to the 2005 period. In the 2006 period, our average outstanding
balance of bank debt was $10.3 million lower than in the 2005 first quarter and
our average interest rate was 0.7% greater than in the 2005 period. Our equity
offering in December 2005 was used to repay outstanding debt from acquisitions
in 2005 and prior years, resulting in the lower average debt balance.
Gain on disposal of surplus assets. In the 2006 first quarter, we disposed
of a minimal amount of surplus assets. In the 2005 first quarter, we sold the
Liberty to Maryland segment of our Mississippi pipeline and two idle segments of
pipeline in Texas. The Mississippi segment had been out-of-service since
February 2002. The Texas segments were idle as a result of our sale of part of
our Texas System to TEPPCO in 2003. Additionally we sold an idle site in Houma,
Louisiana. We received $1.3 million from the sales of these assets and realized
gains totaling $0.7 million, of which $0.3 million was recorded as discontinued
operations.
CUMULATIVE EFFECT ADJUSTMENT - ADOPTION OF NEW ACCOUNTING PRINCIPLE
On January 1, 2006, we adopted the provisions of SFAS No. 123(R). In
December 2004, the FASB issued SFAS No. 123 (revised December 2004),
"Share-Based Payments". The adoption of this statement requires that the
compensation cost associated with our stock appreciation rights plan, which upon
exercise will result in the payment of cash to the employee, be re-measured each
reporting period based on the fair value of the rights. Before the adoption of
SFAS 123(R), we 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 on 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 have elected to calculate the fair value of the rights under the plan
using the Black-Scholes valuation model. This model requires that we include the
expected volatility of the market price for our common units, the current price
of our common units, the exercise price of the rights, the expected life of the
rights, the current risk free interest rate, and our expected annual
distribution yield. This valuation is then applied to the vested rights
outstanding and to the non-vested rights based on the percentage of the service
period that has elapsed. The valuation is adjusted for expected forfeitures of
rights (due to terminations before vesting, or expirations after vesting). The
liability amount accrued on the balance sheet is adjusted to this amount with
the adjustment reflected in the statement of operations.
-27-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
The estimates that we made upon the adoption of this standard at January 1,
2006 included the following:
- In determining the expected life of the rights, we used the simplified
method allowed by the Securities and Exchange Commission. We have very
limited experience with employee exercise patterns, as our plan was
initiated on December 31, 2003. The simplified method produces an
initial expected life of 6.25 years for those rights we issued that
vest 25% per year for four years, and an initial expected life of 7
years for those rights we issued that fully vest at the end of a
four-year period.
- The expected volatility of our units was computed using the historical
period we believe is representative of future expectations. We
determined what period to use in the historical period by considering
whether we were paying distributions to our unitholders, and at what
rate. The expected volatility used in the fair value calculations was
approximately 33%.
- The risk-free interest rate was determined from current yields for
U.S. Treasury zero-coupon bonds with a term similar to the remaining
expected life of the rights.
- In determining our expected future distribution yield, we considered
our history of distribution payments, our expectations for future
payments, and the distribution yields of entities similar to us.
- The final estimate we were required to make is the expected
forfeitures of non-vested rights and expirations of vested rights. As
our stock appreciation rights plan was not put in place until December
31, 2003, we have very limited experience with employee forfeiture and
expiration patterns. We reviewed the history available to us as well
as employee turnover patterns in determining the rates to use. We also
decided to use different estimates for different groups of employees.
At December 31, 2005, we had a recorded liability of $0.8 million, computed
under the provisions of FASB Interpretation No. 28. We calculated the effect of
adoption of SFAS 123(R) at January 1, 2006, and determined that our recorded
liability at December 31, 2005 should be reduced by $30,000. This reduction is
reflected as income from the cumulative effect of the adoption of a new
accounting principle on our statement of operations. We do not believe the
effect of adoption of this accounting principle at January 1, 2005 would have
been material. The adjustment of the liability to its fair value at March 31,
2006, resulted in the expense of $0.2 million that is included in general and
administrative expenses.
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 is composed of two
components - up to $15 million for loans and up to $35 million for letters of
credit. In total we may borrow up to $65 million in loans under our credit
facility. At March 31, 2006, we had $10.7 million in letters of credit and $2.6
million of debt outstanding under the working capital portion. 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.
Interest on amounts borrowed under the credit facility is equal to (x)
either the applicable Eurodollar settlement rate or the higher of the Federal
funds rate plus 1/2 of 1% or Bank of America's prime rate for the relevant
period, at our option, plus (y) the applicable margin rate. We are required to
pay our credit facility lenders a fee based upon amounts available but not
borrowed under each of the acquisition and working capital facilities, as well
as certain other fees.
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 March 31, 2006, the borrowing base was
$49.1 million. The total amount available for borrowings at March 31, 2006 was
$12.4 million under the working capital portion and $50.0 million under the
acquisition portion of our credit facility.
-28-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
We must comply with various affirmative and negative covenants contained in
our credit facility. Among other things, those covenants limit our ability to:
- incur additional indebtedness or liens;
- make payments in respect of or redeem or acquire any debt or equity
issued by us;
- sell assets;
- make loans or investments;
- extend credit;
- acquire or be acquired by other companies;
- enter into or amend certain existing agreements to the detriment of
the lenders under the credit facility; and
- to maintain physical petroleum inventory for which there is not an
off-setting sale or hedging agreement, subject to specified
exceptions.
Our credit facility covenants also require us to achieve specified minimum
financial metrics. For example, before we may make distributions to our
partners, we must 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 March 31, 2006, the
calculation resulted in a ratio of 1.4 to 1.0. The credit facility also requires
that the level of operating cash inflows during the prior twelve months, as
adjusted in accordance with the credit facility, be at least $8.5 million. At
March 31, 2006, the result of this calculation was $15.0 million. Our credit
facility also requires that we meet or exceed certain other financial ratios,
such as a current ratio, leverage ratio and funded indebtedness to
capitalization ratio. If we meet these covenants and are not otherwise in
default under our credit facility, we are otherwise not limited by our credit
facility in making distributions to our partners.
The covenants described above could prevent us from engaging in certain
transactions which might otherwise be considered beneficial to us. For example,
they could:
- increase our vulnerability to generally adverse economic and industry
conditions;
- limit our ability to make distributions to unitholders; to fund future
working capital, capital expenditures and other general partnership
requirements; to engage in future acquisitions, construction or
development activities; or to otherwise fully realize the value of our
assets and opportunities because of the need to dedicate a substantial
portion of our cash flow from operations to payments on our
indebtedness or to comply with any restrictive terms of our
indebtedness; and
- limit our flexibility in planning for, or reacting to, changes in our
businesses and the industries in which we operate.
Our credit facility contains customary events of default, including for
non-payment of principal and interest, and failure to comply with any covenant.
Our average daily outstanding balance under our credit facility during the
first quarter of 2006 was less than $0.1 million. The interest rate we paid
during this same period was 8.0%.
Our credit facility is secured by liens on substantially all of our assets.
-29-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
CAPITAL EXPENDITURES
A summary of our capital expenditures in the three months ended March 31,
2006 and 2005 is as follows:
Three Months Ended March 31,
----------------------------
2006 2005
---- ------
(in thousands)
Maintenance capital expenditures:
Texas pipeline system ........................ $ 15 $ 14
Mississippi pipeline system .................. 44 471
Jay pipeline system .......................... 39 5
Crude oil gathering assets ................... 72 9
Administrative assets ........................ 49 12
---- ------
Total maintenance capital expenditures .... 219 511
Growth capital expenditures:
Mississippi pipeline system .................. 68 79
Natural gas gathering assets ................. -- 3,108
---- ------
Total growth capital expenditures ......... 68 3,187
---- ------
Total capital expenditures ............. $287 $3,698
==== ======
We have no commitments to make capital expenditures; however, we anticipate
that our maintenance capital expenditures for 2006 will be approximately $1.5
million. These expenditures are expected to relate primarily to the replacement
of a tank on the Texas System and improvements on our Mississippi System. Based
on the information available to us at this time, we do not anticipate that
future capital expenditures for compliance with regulatory requirements will be
material.
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 three acquisitions made
in 2005 and the investment in April 2006 in Sandhill Group, LLC discussed in
"Acquisitions in 2006" above.
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 March 31, 2006, we
had $2.6 million outstanding under the working capital facility and no debt
outstanding under the acquisition facility.
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, credit facilities, and in
2005, proceeds from the sale of idle assets. Our primary uses of cash flows are
capital expenditures and distributions. A summary of our cash flows is as
follows:
-30-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Three Months Ended March 31,
----------------------------
2006 2005
------- -------
(in thousands)
Cash provided by (used in):
Operating activities...... $(2,297) $ 2,539
Investing activities...... $ (128) $(2,824)
Financing activities...... $ (292) $ 1,338
Operating. Net cash from operating activities for each period have been
comprised of the following:
Three Months Ended March 31,
----------------------------
2006 2005
------- -------
(in thousands)
Net (loss) income............................... $ 2,591 $ 2,770
Depreciation, amortization and impairment....... 1,864 1,526
Gain on sales of assets......................... (50) (653)
Direct financing leases......................... 129 120
Other non-cash items............................ 385 (1,227)
Changes in components of working capital, net... (7,216) 3
------- -------
Net cash from operating activities........... $(2,297) $ 2,539
======= =======
Our operating cash flows are affected significantly by changes in items of
working capital. We have had situations where other parties have prepaid for
purchases or paid more than was due, resulting in fluctuations in one period as
compared to the next until the party recovers the excess payment. In the 2006
first quarter, we acquired inventory. The timing of capital expenditures and the
related effect on our recorded liabilities also affects operating cash flows.
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 $87.0 million aggregate receivables on
our consolidated balance sheet at March 31, 2006, approximately $86.3 million,
or 99.3%, were less than 30 days past the invoice date.
Investing. We utilized cash flows to make limited capital expenditures,
primarily related to equipment we installed on our newly leased trucks used in
our gathering operations, and for pipeline improvements.
Financing. In the first quarter of 2006, we borrowed $2.6 million under our
credit facility. We also paid distributions to our unitholders and our general
partner totaling $2.4 million. In the prior year period, we increased our
borrowings by $2.2 million and paid distributions totaling $1.4 million.
DISTRIBUTIONS
We are required by our partnership agreement to distribute 100% of our
available cash (as defined therein) 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. We have increased our distribution for each of the last
three quarters, including the distribution to be paid for the first quarter of
2006, as shown in the table below.
Date Per Unit Total
Distribution For Paid or to be Paid Amount Amount (000's)
- ---------------- ------------------ -------- --------------
Fourth quarter 2004 February 2005 $0.15 $1,426
First quarter 2005 May 2005 $0.15 $1,426
Second quarter 2005 August 2005 $0.15 $1,426
Third quarter 2005 November 2005 $0.16 $1,521
Fourth quarter 2005 February 2006 $0.17 $2,391
First quarter 2006 May 2006 $0.18 $2,532
-31-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
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,
our 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. The
likelihood and timing of the payment of any incentive distributions will depend
on our ability to increase the cash flow from our existing operations and to
make cash flow accretive acquisitions. In addition, our partnership agreement
authorizes us to issue additional equity interests in our partnership with such
rights, powers and preferences (which may be senior to our common units) as our
general partner may determine in its sole discretion, including with respect to
the right to share in distributions and profits and losses of the partnership.
We have not paid any incentive distributions and do not expect to make incentive
distributions during 2006.
Available Cash before Reserves for the year ended March 31, 2006 is as
follows (in thousands):
Net income............................................................. $2,591
Depreciation and amortization.......................................... 1,864
Cash received from direct financing leases not included in income...... 129
Cash effects from sales of certain asset sales......................... 17
Effects of available cash generated by investment in T&P Syngas
not included in net income.......................................... 280
Non-cash charges....................................................... 353
Maintenance capital expenditures....................................... (219)
------
Available Cash before Reserves......................................... $5,015
======
We have reconciled Available Cash (a non-GAAP liquidity measure) to cash
flow from operating activities (the GAAP measure) for the three months ended
March 31, 2006 below. For the three months ended March 31, 2006, cash flows
utilized in operating activities were $2.3 million.
NON-GAAP FINANCIAL MEASURE
This quarterly report includes the financial measure of Available Cash,
which measure often is referred to as a "non-GAAP" measure because it is not
contemplated by or referenced in accounting principles generally accepted in the
U.S., also referred to as GAAP. The accompanying schedule provides a
reconciliation of this non-GAAP financial measure to its most directly
comparable GAAP financial. Our non-GAAP financial measure should not be
considered as an alternative to GAAP measures such as net income, operating
income, cash flow from operating activities or any other GAAP measure of
liquidity or financial performance. We believe that investors benefit from
having access to the same financial measures being utilized by management,
lenders, analysts and other market participants.
Available Cash, also referred to as discretionary cash flow, is commonly
used as a supplemental financial measure by management and by external users of
financial statements, such as investors, commercial banks, research analysts and
rating agencies, to assess: (1) the financial performance of our assets without
regard to financing methods, capital structures or historical cost basis; (2)
the ability of our assets to generate cash sufficient to pay interest cost and
support our indebtedness; (3) our operating performance and return on capital as
compared to those of other companies in the midstream energy industry, without
regard to financing and capital structure; and (4) the viability of projects and
the overall rates of return on alternative investment opportunities. Because
Available Cash excludes some, but not all, items that affect net income or loss
and because these measures may vary among other companies, the Available Cash
data presented in this Quarterly Report on Form 10-Q may not be comparable to
similarly titled measures of other companies. The GAAP measure most directly
comparable to Available Cash is net cash provided by operating activities.
Available Cash is a liquidity measure used by our management to compare
cash flows generated by us to the cash distribution paid to our limited partners
and 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
-32-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
financial measure aids investors in determining whether or not we are generating
cash flows at a level that can support a quarterly cash distribution to the
partners. Lastly, Available Cash before Reserves (also referred to as
distributable cash flow) is the quantitative standard used throughout the
investment community with respect to publicly-traded partnerships.
The reconciliation of Available Cash (a non-GAAP liquidity measure) to cash
flow from operating activities (the GAAP measure) for the three months ended
March 31, 2006, is as follows (in thousands):
Three
Months
Ended
March 31,
2006
---------
Cash flows utilized in operating activities .......................... $(2,297)
Adjustments to reconcile operating cash flows to Available Cash:
Maintenance capital expenditures .................................. (219)
Proceeds from sales of certain assets ............................. 67
Amortization of credit facility issuance fees ..................... (92)
Cash effects of stock appreciation rights plan .................... (18)
Effects of available cash generated by investment in T&P Syngas
not included in cash flows from operating activities ........... 358
Net effect of changes in operating accounts not included in
calculation of Available Cash before Reserves .................. 7,216
-------
Available Cash before Reserves ....................................... $ 5,015
=======
COMMITMENTS AND OFF-BALANCE-SHEET ARRANGEMENTS
CONTRACTUAL OBLIGATION AND COMMERCIAL COMMITMENTS
In addition to the 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 March 31, 2006.
-33-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Payments Due by Period
------------------------------------------------------
Less than After
Contractual Cash Obligations 1 Year 1-3 Years 4-5 Years 5 Years Total
- ---------------------------- --------- --------- --------- ------- --------
(in thousands)
Long-term Debt ........................ $ -- $ 2,600 $ -- $ -- $ 2,600
Interest Payments (1) ................. 208 243 -- -- 451
Operating Leases ...................... 2,803 4,621 2,323 298 10,045
Unconditional Purchase
Obligations (2) .................... 144,302 57,057 -- -- 201,359
-------- ------- ------ ---- --------
Total Contractual Cash Obligations .... $147,313 $64,521 $2,323 $298 $214,455
======== ======= ====== ==== ========
(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 March 31, 2006 remained outstanding through the maturity
date of June 1, 2008 and interest rates remained at the March 31, 2006
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 March 31, 2006, 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 AND PROPOSED ACCOUNTING PRONOUNCEMENTS
See discussion of new accounting pronouncements in Note 2, "New Accounting
Pronouncements" in the accompanying consolidated financial statements.
FORWARD LOOKING STATEMENTS
The statements in this Quarterly Report on Form 10-Q that are not
historical information may be "forward looking statements" within the meaning of
the various provisions of the Securities Act of 1933 and the Securities Exchange
Act of 1934. All statements, other than historical facts, included in this
document that address activities, 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 forward-looking statements are identified as
any statement that does not relate strictly to historical or current facts. They
use words such as "anticipate," "believe," "continue," "estimate," "expect,"
"forecast," "intend," "may," "plan," "position," "projection," "strategy" or
"will" or the negative of those terms or other variations of them or by
comparable terminology. In particular, statements, expressed or implied,
concerning future actions, conditions or events or future operating results or
the ability to generate sales, income or cash flow are forward-looking
statements. 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 or the ability of our affiliates
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
or "NGLs" 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;
-34-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
- - 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 liquids transportation systems, natural gas
transportation systems or natural gas gathering and processing operations;
- - shut-downs or cutbacks at refineries, petrochemical plants, utilities or
other businesses for which we transport crude oil, natural gas or other
products or to whom we sell such products;
- - 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 financial covenants;
- - loss of key personnel;
- - the effects of competition, in particular, by other pipeline systems;
- - hazards and operating risks that may not be covered fully by insurance;
- - the condition of the capital markets in the United States;
- - loss of key customers;
- - 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 1A of our Annual Report on Form 10-K for
the year ended December 31, 2005. Except as required by applicable securities
laws, we do not intend to update these forward-looking statements and
information.
-35-
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risks primarily related to volatility in crude oil
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
utilize NYMEX commodity based futures contracts and forward contracts to hedge
our exposure to these market price fluctuations as needed. At March 31, 2006, we
had entered into forward contracts and NYMEX future contracts that will settle
through May 2006. 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) Buy (Long)
Contracts Contracts
------------ ----------
Futures Contracts
Contract volumes (1,000 bbls)............ 184 53
Weighted average price per bbl........... $ 64.11 66.38
Contract value (in thousands)............ $11,796 $3,518
Mark-to-market change (in thousands)..... 560 13
------- ------
Market settlement value (in thousands)... $12,356 $3,531
======= ======
Forward Contracts
Contract volumes (1,000 bbls)............ 73 73
Weighted average price per bbl........... $ 62.68 $61.28
Contract value (in thousands)............ $ 4,576 $4,473
Mark-to-market change (in thousands)..... 134 229
------- ------
Market settlement value (in thousands)... $ 4,710 $4,702
======= ======
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 March 31, 2006 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 March 31, 2006. 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 2,600
Average interest rate 8.0%
ITEM 4. CONTROLS AND PROCEDURES
We maintain disclosure controls and procedures and internal controls
designed to ensure that information required to be disclosed in our filings
under the Securities Exchange Act of 1934 is recorded, processed, summarized and
reported within the time periods specified in the Securities and Exchange
Commission's rules and forms. Our
-36-
chief executive officer and chief financial officer, with the participation of
our management, have evaluated our disclosure controls and procedures as of the
end of the period covered by this Quarterly Report on Form 10-Q and have
determined that such disclosure controls and procedures are adequate and
effective in all material respects in providing to them on a timely basis
material information relating to us (including our consolidated subsidiaries)
required to be disclosed in this quarterly report.
There were no changes during our last fiscal quarter that materially
affected, or are reasonably likely to materially affect, our internal control
over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
See Part I. Item 1. Note 11 to the Consolidated Financial Statements
entitled "Contingencies", which is incorporated herein by reference.
ITEM 1A. RISK FACTORS.
There have been no material changes to the risk factors previously
disclosed in our Annual Report on Form 10-K for the year ended December 31,
2005.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES.
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
ITEM 5. OTHER INFORMATION.
None.
ITEM 6. EXHIBITS.
(a) Exhibits.
Exhibit 10.1 Earnout Agreement by and Between the Magna Carta Group,
L.L.C. and Genesis Crude Oil, L.P.
Exhibit 10.2 Limited Commercial Guarantee with Sandhill Group,
L.L.C. as Borrower, Region's Bank as Bank and Genesis
Crude Oil, L.P. as Guarantor
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.
-37-
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
GENESIS ENERGY, L.P.
(A Delaware Limited Partnership)
By: GENESIS ENERGY, INC., as
General Partner
Date: May 9, 2006 By: /s/ ROSS A. BENAVIDES
------------------------------------
Ross A. Benavides
Chief Financial Officer
-38-
Index to Exhibits
Exhibits
Exhibit 10.1 Earnout Agreement by and Between the Magna Carta Group, L.L.C.
and Genesis Crude Oil, L.P.
Exhibit 10.2 Limited Commercial Guarantee with Sandhill Group, L.L.C. as
Borrower, Region's Bank as Bank and Genesis Crude Oil, L.P. as
Guarantor
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.