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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, 2005
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-12295
GENESIS ENERGY, L.P.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 76-0513049
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
500 DALLAS, SUITE 2500, HOUSTON, TEXAS 77002
(Address of principal executive offices) (Zip Code)
(713) 860-2500
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined by Rule 12b-2 of the Exchange Act.)
Yes [X] No [ ]
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This report contains 31 pages
GENESIS ENERGY, L.P.
FORM 10-Q
INDEX
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements Page
----
Consolidated Balance Sheets - March 31, 2005 and December 31, 2004........................ 3
Consolidated Statements of Operations for the Three Months Ended March 31, 2005 and 2004.. 4
Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2005 and 2004.. 5
Consolidated Statement of Partners' Capital for the Three Months Ended March 31, 2005..... 6
Notes to Consolidated Financial Statements................................................ 7
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations..... 16
Item 3. Quantitative and Qualitative Disclosures about Market Risk................................ 30
Item 4. Controls and Procedures................................................................... 30
PART II. OTHER INFORMATION
Item 1. Legal Proceedings......................................................................... 31
Item 6. Exhibits.................................................................................. 31
SIGNATURES ....................................................................................... 31
-2-
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
(Unaudited)
March 31, December 31,
2005 2004
---------- ------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents ....................................... $ 3,131 $ 2,078
Accounts receivable:
Trade ........................................................ 89,339 68,737
Related party ................................................ 1,153 584
Inventories ..................................................... 1,797 1,866
Net investment in direct financing leases, net of unearned
income - current portion ...................................... 505 318
Insurance receivable ............................................ 2,097 2,125
Other ........................................................... 1,240 1,688
--------- ---------
Total current assets ......................................... 99,262 77,396
FIXED ASSETS, at cost .............................................. 68,094 73,023
Less: Accumulated depreciation .................................. (34,569) (39,237)
--------- ---------
Net fixed assets ............................................. 33,525 33,786
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income .. 6,343 4,247
CO2 ASSETS, net of amortization .................................... 25,708 26,344
OTHER ASSETS, net of amortization .................................. 1,819 1,381
--------- ---------
TOTAL ASSETS ....................................................... $ 166,657 $ 143,154
========= =========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable -
Trade ........................................................ $ 94,626 $ 74,176
Related party ................................................ 624 1,239
Accrued liabilities ............................................. 6,651 6,523
--------- ---------
Total current liabilities .................................... 101,901 81,938
LONG-TERM DEBT ..................................................... 17,500 15,300
OTHER LONG-TERM LIABILITIES ........................................ 156 160
COMMITMENTS AND CONTINGENCIES (Note 11)
MINORITY INTERESTS ................................................. 517 517
PARTNERS' CAPITAL
Common unitholders, 9,314 units issued and outstanding .......... 45,644 44,326
General partner ................................................. 939 913
--------- ---------
Total partners' capital ...................................... 46,583 45,239
--------- ---------
TOTAL LIABILITIES AND PARTNERS' CAPITAL ............................ $ 166,657 $ 143,154
========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
-3-
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
(Unaudited)
Three Months Ended March 31,
2005 2004
------------ --------------
REVENUES:
Crude oil gathering and marketing:
Unrelated parties (including revenues from buy/sell arrangements of
$85,842 in 2005 and $58,796 in 2004, respectively) ................... $ 246,824 $ 192,996
Related parties ......................................................... 184 -
Pipeline transportation, including natural gas sales:
Unrelated parties ....................................................... 6,201 4,085
Related parties ......................................................... 1,111 -
CO2 revenues ............................................................... 2,280 1,831
--------- ---------
Total revenues ....................................................... 256,600 198,912
COST AND EXPENSES:
Crude oil costs:
Unrelated parties (including crude oil costs from buy/sell arrangements
of $86,145 in 2005 and $58,581 in 2004, respectively) ................ 241,811 165,972
Related parties ......................................................... 477 22,975
Field operating ......................................................... 3,832 3,043
Pipeline transportation costs:
Pipeline operating costs ................................................ 2,233 2,232
Natural gas purchases ................................................... 2,636 -
CO2 marketing costs:
Transportation costs - related party .................................... 717 566
Other costs ............................................................. 38 25
General and administrative ................................................. 858 3,164
Depreciation and amortization .............................................. 1,526 1,547
Net gain on disposal of surplus assets ..................................... (371) -
--------- ---------
OPERATING INCOME (LOSS) ....................................................... 2,843 (612)
OTHER INCOME (EXPENSE):
Interest income ............................................................ 6 24
Interest expense ........................................................... (361) (194)
--------- ---------
INCOME (LOSS) FROM CONTINUING OPERATIONS ...................................... 2,488 (782)
Income (loss) from operations of discontinued Texas System .................... 282 (223)
--------- ---------
NET INCOME (LOSS) ............................................................. $ 2,770 $ (1,005)
========= =========
NET INCOME (LOSS) PER COMMON UNIT - BASIC AND DILUTED:
Income (loss) from continuing operations ................................... $ 0.26 $ (0.09)
Income (loss) from discontinued operations ................................. 0.03 (0.02)
--------- ---------
NET INCOME (LOSS) .......................................................... $ 0.29 $ (0.11)
========= =========
WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING ........................... 9,314 9,314
========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
-4-
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
Three Months Ended March 31,
2005 2004
------------ ---------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) ............................................................ $ 2,770 $ (1,005)
Adjustments to reconcile net income (loss) to net cash provided by operating
activities -
Depreciation .............................................................. 890 1,024
Amortization of CO2 contracts ............................................. 636 523
Amortization of credit facility issuance costs ............................ 93 93
Amortization of unearned income on direct financing leases ................ (177) -
Payments received under direct financing leases ........................... 297 -
Change in fair value of derivatives ....................................... 9 -
Gain on asset disposals ................................................... (653) -
Other non-cash charges .................................................... (1,329) 1,104
Changes in components of working capital -
Accounts receivable .................................................... (21,171) (7,674)
Inventories ............................................................ 159 306
Other current assets ................................................... 476 6,818
Accounts payable ....................................................... 19,171 7,726
Accrued liabilities .................................................... 1,368 (12,518)
-------- --------
Net cash provided by (used in) operating activities ............................ 2,539 (3,603)
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment .......................................... (3,597) (400)
Proceeds from sale of assets ................................................. 1,319 -
Other, net ................................................................... (546) -
-------- --------
Net cash used in investing activities .......................................... (2,824) (400)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Bank borrowings of debt ...................................................... 2,200 2,900
Other, net ................................................................... 564 -
Distributions to common unitholders .......................................... (1,397) (1,397)
Distributions to General Partner ............................................. (29) (29)
-------- --------
Net cash provided by financing activities ...................................... 1,338 1,474
-------- --------
Net increase (decrease) in cash and cash equivalents ........................... 1,053 (2,529)
Cash and cash equivalents at beginning of year ................................. 2,078 2,869
-------- --------
Cash and cash equivalents at end of period ..................................... $ 3,131 $ 340
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
-5-
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
(In thousands)
(Unaudited)
Partners' Capital
--------------------------------------------
Number of
Common Common General
Units Unitholders Partner Total
--------- ----------- --------- ---------
Partners' capital at January 1, 2005 .................. 9,314 $ 44,326 $ 913 $ 45,239
Net income for the three months ended March 31, 2005... - 2,715 55 2,770
Distributions to partners during the three months
ended March 31, 2005 ................................ - (1,397) (29) (1,426)
----- -------- -------- --------
Partners' capital at March 31, 2005 ................... 9,314 $ 45,644 $ 939 $ 46,583
===== ======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
-6-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
Organization
Genesis Energy, L.P. (GELP or the Partnership) is a publicly traded
Delaware limited partnership engaged in gathering, marketing and transportation
of crude oil and natural gas and wholesale marketing of carbon dioxide (CO2). We
have 9.3 million common units outstanding, representing limited partner
interests in us of 98%. Our general partner is Genesis Energy, Inc. which owns a
2% general partner interest in us. The general partner is owned by Denbury
Gathering & Marketing, Inc. a subsidiary of Denbury Resources Inc. Denbury and
its subsidiaries are hereafter referred to as Denbury. Our general partner holds
0.7 million of our common units (7.4%).
Genesis Crude Oil, L.P. is our operating limited partnership and is owned
99.99% by us and 0.01% by our general partner. Genesis Crude Oil, L.P. has five
subsidiary partnerships: Genesis Pipeline Texas, L.P., Genesis Pipeline USA,
L.P., Genesis CO2 Pipeline, L.P., Genesis Natural Gas Pipeline, L.P. and Genesis
Syngas Investments, L.P. Genesis Crude Oil, L.P. and its subsidiary partnerships
will be referred to as GCOLP.
Basis of Presentation
The accompanying financial statements and related notes present our
consolidated financial position as of March 31, 2005 and December 31, 2004 and
our results of operations, cash flows and changes in partners' capital for the
three months ended March 31, 2005 and 2004.
The financial statements included herein have been prepared by us without
audit pursuant to the rules and regulations of the Securities and Exchange
Commission (SEC). Accordingly, they reflect all adjustments (which consist
solely of normal recurring adjustments) which are, in the opinion of management,
necessary for a fair presentation of the financial results for interim periods.
Certain information and notes normally included in financial statements prepared
in accordance with generally accepted accounting principles have been condensed
or omitted pursuant to such rules and regulations. However, we believe that the
disclosures are adequate to make the information presented not misleading. These
financial statements should be read in conjunction with the financial statements
and notes thereto included in our Annual Report on Form 10-K for the year ended
December 31, 2004 filed with the SEC.
All significant intercompany transactions have been eliminated.
We have not included a provision for income taxes in our consolidated
financial statements; as such income will be taxable directly to the partners
holding partnership interests in the Partnership.
2. NEW ACCOUNTING PRONOUNCEMENTS
The Emerging Issues Task Force (EITF) of the Financial Accounting
Standards Board (FASB) is currently considering the issue of accounting for
buy/sell arrangements as part of its EITF Issue No. 04-13, "Accounting for
Purchases and Sales of Inventory with the Same Counterparty" (Issue 04-13). As
part of Issue 04-13, the EITF is considering a requirement that all buy/sell
arrangements be reflected on a net basis, such that the purchase and sale are
netted and shown as either a net purchase or a net sale in the income statement.
Should this requirement be adopted, our reported crude oil gathering and
marketing revenues from unrelated parties for the three months ended March 31,
2005 would be reduced by $85.8 million to $161.0 million and our reported crude
oil costs from unrelated parties for the three months ended March 31, 2005,
would be reduced by $86.1 million to $155.7 million.
In December 2004, the FASB issued Statement of Financial Accounting
Standards No. 123 (revised December 2004), "Share-Based Payments" (SFAS 123(R)).
This statement replaces SFAS No. 123 and requires that compensation costs
related to share-based payment transactions be recognized in the financial
statements. This statement is effective for public entities as of the first
interim or annual reporting period of the first fiscal year beginning on or
after June 15, 2005. We plan to adopt SFAS 123(R) in the first quarter of 2006.
The adoption of this statement will require that the compensation cost
associated with our stock appreciation rights plan be re-measured each reporting
period based on the fair value of the rights. Before the adoption of SFAS 123
(R), we have accounted for the stock appreciation rights in accordance with FASB
Interpretation No. 28 "Accounting for Stock
-7-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Appreciation Rights and Other Variable Stock Option or Award Plans" which
required that the liability under the plan be measured at each balance sheet
date based on the market price of our Common Units at that date. Under SFAS
123(R), the liability will be calculated using a fair value method that will
take into consideration the expected future value of the rights at their
expected exercise dates. We are currently evaluating what effect SFAS 123(R)
will have on our financial statements, but at this time, we do not believe that
the adoption of this statement will have a material effect on our financial
position, results of operations or cash flows.
In March 2005, the FASB issued FASB Interpretation No. 47, "Accounting for
Conditional Asset Retirement Obligations, an interpretation of FASB Statement
No. 143" (FIN 47). FIN 47 clarifies that the term, conditional asset retirement
obligation as used in SFAS No. 143, "Accounting for Asset Retirement
Obligations", refers to a legal obligation to perform an asset retirement
activity in which the timing and/or method of settlement are conditional upon a
future event that may or may not be within the control of the entity. Although
uncertainty about the timing and/or method of settlement may exist and may be
conditional upon a future event, the obligation to perform the asset retirement
activity is unconditional. Accordingly, an entity is required to recognize a
liability for the fair value of a conditional asset retirement obligation if the
fair value of the liability can be reasonably estimated. FIN 47 clarifies when
an entity would have sufficient information to reasonably estimate the fair
value of an asset retirement obligation and emphasizes that uncertainty about
the timing or method of settlement of the obligation should be factored into the
calculation of the fair value of the obligation. FIN 47 is effective no later
than the end of reporting periods ending after December 15, 2005. We are
currently evaluating what effect FIN 47 will have on our financial statements,
but at this time, we do not believe that the adoption of FIN 47 will have a
material effect on our financial position, results of operations or cash flows.
3. NET INVESTMENT IN DIRECT FINANCING LEASES
In 2004, we constructed a segment of crude oil pipeline and a CO2 pipeline
in Mississippi. Denbury pays us a minimum payment each month for the right to
use these pipelines. Both of these arrangements are accounted for as direct
financing leases.
In the first quarter of 2005, we completed another crude oil pipeline
segment to move crude oil from a Denbury field to our Mississippi System.
Denbury pays us a minimum payment each month for the right to use this pipeline.
This arrangement is also being accounted for as a direct financing lease.
At March 31, 2005, the components of the net investment in direct
financing leases were as follows (in thousands):
Total minimum lease payments to be received .................. $ 10,300
Estimated residual values of leased property (unguaranteed) .. 1,287
Less: Unearned income ........................................ (4,739)
--------
Net investment in direct financing leases .................... $ 6,848
========
At March 31, 2005, minimum lease payments to be received for each of the
five succeeding fiscal years are $1.2 million per year.
4. DEBT
At March 31, 2005, we had $5.0 million outstanding under the working
capital portion and $12.5 million outstanding under the acquisition portion of
our Credit Facility. At March 31, 2005, the weighted average interest rate on
this debt was 7.5%. Due to the revolving nature of loans under both portions of
the Credit Facility, additional borrowings and periodic repayments and
re-borrowings may be made until the maturity date of June 1, 2008. At March 31,
2005, we had letters of credit outstanding under the Credit Facility totaling
$9.5 million, comprised of $4.4 million and $4.3 million for crude oil purchases
related to March 2005 and April 2005, respectively and $0.8 million related to
other business obligations.
The amount that we may have outstanding cumulatively in borrowings and
letters of credit under the working capital portion of the facility is subject
to a borrowing base calculation. The borrowing base is limited to $50 million
-8-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
and is calculated monthly. At March 31, 2005, the borrowing base was $42.8
million. Therefore, the remaining amount available for borrowings at March 31,
2005 was $10 million under the working capital portion and $37.5 million under
the acquisition portion of the Credit Facility.
We have no limitations on making distributions in our Credit Facility,
except as to the effects of distributions in covenant calculations. 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, 2005, the
calculation resulted in a ratio of 1.3 to 1.0.
5. PARTNERS' CAPITAL AND DISTRIBUTIONS
Partners' Capital
Partnership equity consists of the general partner interest of 2% and
9,313,811 common units representing limited partner interests of 98%.
The general partner interest is held by our General Partner. The
Partnership is managed by our general partner. The general partner also holds a
0.01% general partner interest in GCOLP, which is reflected as a minority
interest in the consolidated balance sheet at March 31, 2005.
Our partnership agreement authorizes our general partner to cause us to
issue additional limited partner interests and other equity securities, the
proceeds from which could be used to provide additional funds for acquisitions
or other needs.
Distributions
Generally, we will distribute 100% of our Available Cash (as defined in
our partnership agreement) within 45 days after the end of each quarter to
unitholders of record and to the general partner. Available Cash consists
generally of all of our cash receipts less cash disbursements adjusted for net
changes to reserves. During 2004, we paid a regular quarterly distribution of
$0.15 per unit ($1.4 million in total per quarter). We have declared a $0.15 per
unit distribution for the first quarter of 2005, payable on May 13, 2005 to
unitholders of record on May 2, 2005.
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 generally is entitled to receive 13.3% of any
distributions in excess of $0.25 per unit, 23.5% of any distributions in excess
of $0.28 per unit and 49% of any distributions in excess of $0.33 per unit
without duplication. We have not paid any incentive distributions through March
31, 2005.
-9-
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,
----------------------------
2005 2004
----------- -----------
Numerators for basic and diluted net income (loss) per common unit:
Income (loss) from continuing operations .................................... $ 2,488 $ (782)
Less general partner 2% ownership ........................................... 50 (16)
------- -------
Income (loss) from continuing operations available for common unitholders ... $ 2,438 $ (766)
======= =======
Income (loss) from discontinued operations .................................. $ 282 $ (223)
Less general partner 2% ownership ........................................... 6 (4)
------- -------
Income (loss) from discontinued operations available for common unitholders . $ 276 $ (219)
======= =======
Denominator for basic and diluted per Common Unit - weighted average
number of Common Units outstanding ............................................. 9,314 9,314
======= =======
Basic and diluted net income (loss) per Common Unit:
Income (loss) from continuing operations .................................... $ 0.26 $ (0.09)
Income (loss) from discontinued operations .................................. 0.03 (0.02)
------- -------
Net income (loss) ........................................................... $ 0.29 $ (0.11)
======= =======
6. BUSINESS SEGMENT INFORMATION
Our operations consist of three operating segments: (1) Crude Oil
Gathering and Marketing - the purchase and sale of crude oil at various points
along the distribution chain; (2) Pipeline Transportation - interstate and
intrastate crude oil, natural gas and CO2 pipeline transportation; and (3) CO2
marketing - the sale of CO2 acquired under a volumetric production payment to
industrial customers.
We evaluate segment performance based on segment margin before
depreciation and amortization. All of our revenues are derived from, and all of
our assets are located in, the United States.
-10-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Crude Oil
Gathering and Pipeline CO2
Marketing Transportation Marketing Total
-------------- -------------- --------- ---------
(in thousands)
Three Months Ended March 31, 2005
Revenues:
External Customers.......................................... $ 247,008 $ 6,633 $ 2,280 $ 255,921
Intersegment (a)............................................ - 679 - 679
-------------- ------------ -------- ---------
Total revenues of reportable segments....................... $ 247,008 $ 7,312 $ 2,280 $ 256,600
============== ============ ======== =========
Segment margin excluding depreciation and amortization (b).. $ 888 2,443 $ 1,525 $ 4,856
Capital expenditures........................................ $ 22 $ 3,676 $ - $ 3,698
Maintenance capital expenditures............................ $ 22 $ 489 $ - $ 511
Net fixed and other long-term assets (c).................... $ 6,096 $ 35,591 $ 25,708 $ 67,395
Three Months Ended March 31, 2004
Revenues:
External Customers.......................................... $ 192,996 $ 3,263 $ 1,831 $ 198,090
Intersegment (a)............................................ - 822 - 822
-------------- ------------ -------- ---------
Total revenues of reportable segments....................... $ 192,996 $ 4,085 $ 1,831 $ 198,912
============== ============ ======== =========
Segment margin excluding depreciation and amortization (b).. $ 1,006 1,853 $ 1,240 $ 4,099
Capital expenditures........................................ $ 51 $ 349 $ - $ 400
Maintenance capital expenditures............................ $ 51 $ 104 $ - $ 155
Net fixed and other long-term assets (c).................... $ 5,211 $ 28,903 $ 23,550 $ 57,664
a) Intersegment sales were conducted on an arm's length basis.
b) Segment margin was calculated as revenues less cost of sales and
operations expense. A reconciliation of segment margin to operating (loss)
income from continuing operations for the periods presented is as follows:
Three Months Ended March 31,
----------------------------
2005 2004
----------- -----------
(in thousands)
Segment margin excluding depreciation and amortization.. $ 4,856 $ 4,099
General and administrative expenses..................... (858) (3,164)
Depreciation, amortization and impairment............... (1,526) (1,547)
Net gain on disposal of surplus assets.................. 371 -
---------- ----------
Operating income (loss) from continuing operations...... $ 2,843 $ (612)
========== ==========
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.
-11-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
Sales and Purchases of Crude Oil
Purchases of crude oil from Denbury for the three months ended March
31, 2005 and 2004 were $0.5 million and $23.0 million, respectively. Denbury
began shipping its own crude oil on our Mississippi System in September 2004, so
our purchases of crude oil from Denbury (and our related crude oil sales) have
declined.
Transportation Services
In September 2004, we entered into an agreement with Denbury where we
would provide truck transportation services to Denbury to move its crude oil
from the wellhead to our Mississippi pipeline. Previously we had purchased
Denbury's crude oil and trucked the oil for our account. Denbury pays us a fee
for this trucking service that varies with the distance the crude oil is
trucked. For the three months ended March 31, 2005, we received fees from
Denbury totaling $0.2 million. These fees are reflected in the statement of
operations as gathering and marketing revenues.
In September 2004, Denbury also became a shipper on our Mississippi
pipeline. Fees for this transportation service totaled $0.9 million for the
three months ended March 31, 2005. We also billed Denbury $0.3 million under the
direct financing lease arrangements for the Olive and Brookhaven crude oil
pipelines and the Brookhaven CO2 pipeline and recorded $0.2 million of pipeline
transportation income from these arrangements. See Note 3.
We also provide pipeline monitoring services to Denbury for which we
charged $7,000 and $4,000 for the three months ended March 31, 2005 and 2004,
respectively. This revenue is included in pipeline revenues in the statement of
operations.
General and Administrative Services
We do not directly employ any persons to manage or operate our
business. Those functions are provided by the General Partner. We reimburse the
General Partner for all direct and indirect costs of these services. Total costs
reimbursed to the General Partner by us were $4.1 million and $3.4 million for
the three months ended March 31, 2005 and 2004, respectively.
Due to and from Related Parties
At March 31, 2005 and December 31, 2004, we owed Denbury $0.1 million
and $0.7 million, respectively, for purchases of crude oil. Additionally, we
owed Denbury $0.5 million and $0.5 million for CO2 transportation services at
March 31, 2005 and December 31, 2004, respectively. Denbury owed us $0.5 million
and $0.4 million for transportation services at March 31, 2005 and December 31,
2004, respectively. We had advanced $0.6 million and $0.1 million to the General
Partner at March 31, 2005 and December 31, 2004, respectively, for
administrative services.
Directors' Fees
In both the first quarter of 2005 and 2004, we paid $30,000 to Denbury
for the services of each of four of Denbury's officers who serve as directors of
our general partner, the same rate at which our independent directors were paid.
CO2 Volumetric Production Payment and Transportation
We acquired volumetric production payments from Denbury in 2005 and
2004. Denbury charges us a transportation fee of $0.16 per Mcf (adjusted for
inflation) to deliver the CO2 for us to our customers. For the three months
ended March 31, 2005 and 2004, we paid Denbury $0.7 million and $0.6 million for
these transportation services related to our sales of CO2.
-12-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Financing
Our general partner, a wholly owned subsidiary of Denbury, guarantees
our obligations under the Credit Facility. Our general partner's principal
assets are its general and limited partnership interests in us. The obligations
are not guaranteed by Denbury or any of its other subsidiaries.
8. MAJOR CUSTOMERS AND CREDIT RISK
We derive our revenues from customers primarily in the crude oil industry.
This industry concentration has the potential to impact our overall exposure to
credit risk, either positively or negatively, in that our customers could be
affected by similar changes in economic, industry or other conditions. However,
we believe that the credit risk posed by this industry concentration is offset
by the creditworthiness of our customer base. Our portfolio of accounts
receivable is comprised in large part of major international corporate entities
with stable payment experience. The credit risk related to contracts which are
traded on the NYMEX is limited due to the daily cash settlement procedures and
other NYMEX requirements.
We have established various procedures to manage our credit exposure,
including initial credit approvals, credit limits, collateral requirements and
rights of offset. Letters of credit, prepayments and guarantees are also
utilized to limit credit risk to ensure that our established credit criteria are
met.
Occidental Energy Marketing, Inc., 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. ExxonMobil Corporation, Marathon Ashland Petroleum LLC
and Plains All American, L.P. accounted for 15%, 14% and 10% of total revenues
during the first quarter of 2004, respectively. The majority of the revenues
from these customers in both periods relate to our gathering and marketing
operations.
9. SUPPLEMENTAL CASH FLOW INFORMATION
We received interest payments of $6,000 and $24,000 for the three months
ended March 31, 2005 and 2004, respectively. Payments of interest and commitment
fees were $14,000 and $52,000 for the three months ended March 31, 2005 and
2004, respectively.
At March 31, 2005, we had incurred liabilities for fixed asset additions
totaling $0.1 million that had not been paid at the end of the quarter, and,
therefore, are not included in the caption "Additions to property and equipment"
on the Consolidated Statements of Cash Flows.
10. DERIVATIVES
Our market risk in the purchase and sale of crude oil contracts is the
potential loss that can be caused by a change in the market value of the asset
or commitment. In order to hedge our exposure to such market fluctuations, we
may enter into various financial contracts, including futures, options and
swaps. Historically, any contracts we have used to hedge market risk were less
than one year in duration.
We may utilize crude oil futures contracts and other financial derivatives
to reduce our exposure to unfavorable changes in crude oil prices. Every
derivative instrument (including certain derivative instruments embedded in
other contracts) must be recorded in the balance sheet as either an asset or
liability measured at its fair value. Changes in the derivative's fair value
must be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a derivative's
gains and losses to offset related results on the hedged item in the income
statement. Companies must formally document, designate and assess the
effectiveness of transactions that receive hedge accounting.
We mark to fair value our derivative instruments at each period end with
changes in fair value of derivatives not designated as hedges being recorded as
unrealized gains or losses. Such unrealized gains or losses will change, based
on prevailing market prices, at each balance sheet date prior to the period in
which the transaction actually occurs. Unrealized gains or losses on derivative
transactions qualifying as cash flow hedges are reflected in other comprehensive
income.
-13-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We regularly review our contracts to determine if the contracts qualify
for treatment as derivatives. 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 as such
at March 31, 2005 and December 31, 2004.
11. CONTINGENCIES
Guarantees
We have guaranteed $3.6 million of residual value related to the leases
of tractors and trailers from Ryder Transportation, Inc. We believe the
likelihood we would be required to perform or otherwise incur any significant
losses associated with this guaranty is remote.
Along with our general partner, we have guaranteed the payments by
GCOLP to the banks under the terms of the Credit Facility related to borrowings
and letters of credit. Borrowings at March 31, 2005 were $17.5 million and are
reflected in the consolidated balance sheet. To the extent liabilities exist
under the letters of credit, such liabilities are included in the consolidated
balance sheet.
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 $2.0 million during 2005
and 2006 for testing and improvements under regulations requiring assessment of
the integrity of crude oil pipelines.
Pennzoil Litigation
We were named a defendant in a complaint filed on January 11, 2001, in
the 125th District Court of Harris County, Texas, Cause No. 2001-01176. From
Genesis, Pennzoil-Quaker State Company (PQS) was seeking property damages, loss
of use and business interruption suffered as a result of a fire and explosion
that occurred at the Pennzoil Quaker State refinery in Shreveport, Louisiana, on
January 18, 2000. PQS claimed the fire and explosion were caused, in part, by
Genesis selling to PQS crude oil that was contaminated with organic chlorides.
In December 2003, our insurance carriers settled this litigation for $12.8
million.
PQS is also a defendant in five consolidated class action/mass tort
actions brought by neighbors living in the vicinity of the PQS Shreveport,
Louisiana refinery in the First Judicial District Court, Caddo Parish,
Louisiana, Cause Nos. 455,647-A, 455,658-B, 455,655-A, 456,574-A, and 458,379-C.
PQS has brought a third party demand against Genesis and others for indemnity
with respect to the fire and explosion of January 18, 2000. We believe that the
demand against Genesis is without merit and intend to vigorously defend
ourselves in this matter. We currently have no reason to believe that this
matter would have a material financial effect on our financial position, results
of operations, or cash flows.
Environmental
In 1992, Howell Crude Oil Company (Howell) entered into a sublease with
Koch Industries, Inc., 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 Jay
Station as a crude oil trucking station until 2003. Koch has indicated that they
may make a claim against us under the indemnification provisions of the sublease
for environmental contamination on the site and surrounding areas.
Genesis and Howell, now a subsidiary of Anadarko Petroleum Corporation,
are investigating whether Genesis and/or Howell may have liability for this
contamination, and if so, to what extent. Based upon the early stage of this
investigation, and subject to resolution of the allocation of responsibility
between us and Howell and the
-14-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
method and timing of any required remediation, we currently have no reason to
believe that this matter would have a material financial effect on our financial
position, results of operations, or cash flows.
We are subject to various environmental laws and regulations. Policies
and procedures are in place to monitor compliance and to detect and address any
releases of crude oil from our pipelines or other facilities, however no
assurance can be made that such environmental releases may not substantially
affect our business.
Other Matters
We have taken additional security measures since the terrorist attacks
of September 11, 2001 in accordance with guidance provided by the Department of
Transportation and other government agencies. We cannot assure you that these
security measures would prevent our facilities from a concentrated attack. Any
future attacks on us or our customers or competitors could have a material
effect on our business, whether insured or not. We believe we are adequately
insured for public liability and property damage to others and that our coverage
is similar to other companies with operations similar to ours. No assurance can
be made that we will be able to maintain adequate insurance in the future at
premium rates that we consider reasonable.
We are subject to lawsuits in the normal course of business and
examination by tax and other regulatory authorities. Such matters presently
pending are not expected to have a material adverse effect on our financial
position, results of operations or cash flows.
12. SUBSEQUENT EVENT
Syngas Investment
On April 1, 2005 we acquired a 50% partnership interest in T & P Syngas
Supply Company (T&P Syngas) for $13.5 million from TCHI Inc., a wholly owned
subsidiary of ChevronTexaco Global Energy Inc. Hydrogen Supply, Inc. ("Praxair")
holds the other 50% interest in T&P Syngas. The acquisition was financed through
our Credit Facility.
T&P Syngas is a partnership that owns a syngas manufacturing facility
located in Texas City, Texas. The 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 T&P Syngas receives a fee
from Praxair for the processing.
T&P Syngas is managed by a management committee consisting of two
representatives each from Praxair and us. The T&P Syngas management committee
has an approved resolution that provides that cash distributions will be paid
quarterly to the partners of the amount of cash on hand in excess of $100,000.
Distribution
On April 21, 2005, the Board of Directors of the General Partner
declared a cash distribution of $0.15 per Unit for the quarter ended March 31,
2005. This distribution will be paid on May 13, 2005 to our general partner and
all common unitholders of record as of the close of business on May 2, 2005.
-15-
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Included in Management's Discussion and Analysis are the following
sections:
- Overview
- Acquisitions in 2005
- Results of Operations and Outlook for 2005 and Beyond
- Liquidity and Capital Resources
- Commitments and Off-Balance Sheet Arrangements
- Other Matters
- New Accounting Pronouncements
In the discussions that follow, we will focus on two measures that we use
to manage the business and to review the results of our operations. Those two
measures are segment margin and Available Cash before Reserves. Our
profitability depends to a significant extent upon our ability to maximize
segment margin. Segment margin is calculated as revenues less cost of sales and
operating expense, and does not include depreciation and amortization. A
reconciliation of Segment Margin to income from continuing operations is
included in our segment disclosures in Note 6 to the consolidated financial
statements. Available Cash before Reserves is a non-GAAP measure calculated as
net income with several adjustments, the most significant of which are the
elimination of gains and losses on asset sales, except those from the sale of
surplus assets, the addition of non-cash expenses such as depreciation, and the
subtraction of maintenance capital expenditures, which are expenditures to
sustain existing cash flows but not to provide new sources of revenues. For
additional information on Available Cash before Reserves and a reconciliation of
this measure to cash flows from operations, see "Liquidity and Capital Resources
- - Non-GAAP Financial Measure" below.
OVERVIEW
We operate in three business segments - crude oil gathering and marketing,
pipeline transportation and CO2 marketing. We generate revenues by selling crude
oil and CO2 and by charging fees for the transportation of crude oil, natural
gas and CO2 on our pipelines. Our focus is on the margin we earn on these
revenues, which is calculated by subtracting the costs of the crude oil, the
costs of transporting the crude oil, natural gas and CO2 to the customer, and
the costs of operating our assets.
Our primary goal is to generate Available Cash before Reserves for our
unitholders. This Available Cash before Reserves is then distributed quarterly
to our unitholders. During the first quarter of 2005, we generated Available
Cash before Reserves that enabled us to pay our regularly quarterly distribution
and build reserves toward any future distribution shortfalls.
We generated net income for the first quarter of 2005 from a combination
of three main sources. These sources included the results of our operating
activities, the sale of idle assets, and the effects of decreasing the liability
under our incentive compensation plan.
Our gathering and marketing segment performed better than it did in the
fourth quarter of 2004, but not as well as it did in the first quarter of 2004.
Higher field costs due to increased fuel prices and increases in payroll and
fleet repair costs were the primary factors for the reduction in our segment
margin.
Our pipeline transportation segment showed improvement in the first
quarter of 2005 as compared to the prior year first quarter. The sale of crude
oil volumes deducted from shippers as pipeline loss allowances that exceeded
actual losses at high crude oil prices in 2005 contributed to this increase in
segment margin.
We sold idle assets during the first quarter of 2005, realizing a gain of
$0.7 on the sales. These idle assets included a segment of our Mississippi
pipeline that had been out of service since 2002, and two segments of our Texas
pipeline that we no longer used due to the sale of part of that system to TEPPCO
in 2003.
We have a stock appreciation rights plan under which employees and
directors are granted rights to receive cash upon exercise for the difference
between the strike price of the rights and the market price for our units at the
time of
-16-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
exercise. These rights vest over several years. As of March 31, 2005, the
outstanding rights had no value as our unit price was below the strike price of
the rights. As our unit price declined from $12.60 at December 31, 2004 to $8.90
per unit at March 31, 2005, we decreased our liability during the first quarter
from $1.3 million to zero, recording a credit of $1.3 million.
ACQUISITIONS IN 2005
GAS GATHERING AND MARKETING ASSETS
In January 2005, we acquired fourteen natural gas pipeline and gathering
systems located in Texas, Louisiana and Oklahoma from Multifuels Energy Asset
Group, L.P. for $3.1 million. These fourteen systems are comprised of 60 miles
of pipeline and related assets. This acquisition was financed through our credit
agreement. The results of this acquisition are included in our pipeline
transportation segment.
SYNGAS INVESTMENT
On April 1, 2005 we acquired a 50% interest in T&P Syngas Supply Company
(T&P Syngas) for $13.5 million. We made this acquisition from TCHI Inc., a
wholly owned subsidiary of ChevronTexaco Global Energy Inc. Praxair Hydrogen
Supply, Inc. ("Praxair") holds the other 50% interest in the partnership.
T&P Syngas is a partnership that owns a syngas manufacturing facility
located in Texas City, Texas. This 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.
T&P Syngas is managed by a management committee consisting of two
representatives each from Praxair and us. The T&P Syngas management committee
has an approved resolution that provides that cash distributions will be paid
quarterly to the partners of the amount of cash on hand in excess of $100,000.
The acquisition was financed through our credit agreement.
RESULTS OF OPERATIONS AND OUTLOOK FOR THE REMAINDER OF 2005 AND BEYOND
CRUDE OIL GATHERING AND MARKETING OPERATIONS
The key factors affecting our crude oil gathering and marketing segment
margin include production volumes, volatility of P-Plus, volatility of grade
differentials, inventory management, field operating costs and credit costs.
These factors are discussed in detail in our Annual Report on Form 10-K for the
year ended December 31, 2004.
Segment margins from gathering and marketing operations are a function of
volumes purchased and the difference between the price of crude oil at the point
of purchase and the price of crude oil at the point of sale, minus the
associated costs of aggregation and transportation. The absolute price levels
for crude oil do not necessarily bear a relationship to segment margin as
absolute price levels normally impact revenues and costs of sales by 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
gathering and marketing operations, these changes are not addressed in the
following discussion.
Field operating costs primarily consist of the costs to operate our fleet
of 53 trucks (51 leased and 2 owned) used to transport crude oil, and the costs
to maintain the trucks and assets used in the crude oil gathering operation.
Approximately 54% of these costs are variable and increase or decrease with
volumetric changes. 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.
- 17-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Operating results from continuing operations for our crude oil gathering
and marketing segment were as follows:
Three Months Ended March 31,
2005 2004
----------- ------------
(in thousands)
Revenues.................................. $ 247,008 $ 192,996
Crude oil costs........................... (242,279) (188,947)
Field operating costs..................... (3,832) (3,043)
Change in fair value of derivatives....... (9) -
----------- ------------
Segment margin......................... $ 888 $ 1,006
=========== ============
Volumes per day:
Crude oil wellhead - barrels........... 41,969 48,445
Crude oil total - barrels.............. 58,346 60,591
Crude oil transported only - barrels... 5,122 262
Three Months Ended March 31, 2005 as Compared to Three Months Ended March
31, 2004
Gathering and marketing segment margins decreased $0.1 million or 12% to
$0.9 million for the three months ended March 31, 2005, as compared to $1.0
million for the three months ended March 31, 2004.
The primary reason for this decrease in segment margin was an increase in
field costs of $0.8 million. The majority of the increase over the 2004 first
quarter related to higher fuel costs and higher personnel costs. Fuel costs have
increased over $0.60 per gallon since the 2004 quarter. We also had five
additional tractor/trailers in the 2005 quarter than in 2004, increasing our
fixed lease payments. Due to competition for wellhead barrels in the areas in
which we operate, we were not able to adjust the purchase price of the crude oil
for these cost increases.
Partially offsetting the effects of the increased field costs were three
primary factors as follows:
- A $0.4 million increase in revenues from volumes that we transported
for a fee but did not purchase. Approximately one-half of this
revenue related to volumes transported for Denbury. In the 2004
period, we purchased Denbury's crude oil at the wellhead, incurring
all risk of loss and price variations. Beginning in September 2004,
Denbury started selling its production to the end-market directly,
and we only provide transportation services for fees in our trucks
and in our pipeline.
- A $0.2 million increase in the difference between the price of crude
oil at the point of purchase and the price of crude oil at the point
of sale; and
- A $0.1 million decrease in credit costs related to crude oil
transactions.
Outlook for 2005 and Beyond
Based on past experience and knowledge of the crude oil gathering and
marketing segment, we continue to expect volatility from this segment. We
continue to take steps to improve the performance of this segment. These steps
include effectively managing relationships with suppliers; inventory management;
controlling field costs; and improving operational efficiency in the field.
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 2005 and
2004 are as follows:
- 18-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Three Months Ended
March 31,
------------------
Pipeline System - barrels per day 2005 2004
- --------------------------------- ------ ------
Texas 29,828 42,206
Mississippi 16,139 10,495
Jay 14,853 15,882
Volumes on our Texas System averaged 29,828 barrels per day during the
first quarter of 2005. The crude oil that enters our system comes to us at West
Columbia where we have a connection to TEPPCO's South Texas System and at
Webster where we have connections to two other pipelines. One of these
connections at Webster is with ExxonMobil Pipeline and is used to receive
volumes that originate from TEPPCO's pipelines. Under the terms of our 2003 sale
of portions of the Texas System to TEPPCO, we had a joint tariff with TEPPCO
through October 2004 under which we earned $0.40 per barrel on the majority of
the barrels we deliver to the shipper's facilities. This tariff declined to
$0.20 per barrel in November 2004. Most of the volume being shipped on our Texas
System goes to two refineries on the Texas Gulf Coast.
The Mississippi System begins in Soso, Mississippi and extends to Liberty,
Mississippi. At Liberty, shippers can transfer the crude oil to a connection to
Capline, a pipeline system that moves crude oil from the Gulf Coast to
refineries in the Midwest. The system has been improved to handle the increased
volumes produced by Denbury and transported on the pipeline. In order to handle
expected future increases in production volumes in the area, we have made
capital expenditures for tank, station and pipeline improvements, and we intend
to make further improvements. See Capital Expenditures under "Liquidity and
Capital Resources" below.
Beginning in September 2004, Denbury became a shipper on the Mississippi
System under an incentive tariff designed to encourage shippers to increase
volumes shipped on the pipeline. Prior to this point, Denbury sold its
production to us before it entered the pipeline.
In the fourth quarter of 2004, we constructed two segments of crude oil
pipeline to connect producing fields operated by Denbury to our Mississippi
System. One of these segments was placed in service in 2004 and the other began
operation in the first quarter of 2005. Denbury pays us a minimum payment each
month for the right to use these pipeline segments. We account for these
arrangements as direct financing leases.
The Jay pipeline system in Florida/Alabama ships crude oil from fields
with relatively short remaining production lives. Although volumes on this
pipeline had been declining steadily in recent years due to declining production
in the surrounding area, new production in the area has reduced the impact of
those declines.
Historically, the largest operating costs in our crude oil pipeline
segment have consisted of personnel costs, power costs, maintenance costs and
costs of compliance with regulations. Some of these costs are not predictable,
such as failures of equipment, or are not within our control, like power cost
increases. We perform regular maintenance on our assets to keep them in good
operational condition and to minimize cost increases.
In the fourth quarter of 2004, we constructed a CO2 pipeline in
Mississippi to transport CO2 from Denbury's main CO2 pipeline to an oil field
from which we also constructed an oil pipeline to bring the oil from the field
to our existing Mississippi pipeline. Denbury has the exclusive right to use
this CO2 pipeline. This arrangement has been accounted for as a direct financing
lease.
Operating results from continuing operations for our pipeline
transportation segment were as follows:
- 19-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Three Months Ended March 31,
2005 2004
----------- ------------
(in thousands)
Revenues from tariffs, including revenues from
direct financing leases........................ $ 4,623 $ 4,085
Revenues from natural gas sales................... 2,689 -
Natural gas purchases............................. (2,636) -
Pipeline operating costs.......................... (2,233) (2,232)
----------- ------------
Segment margin................................. $ 2,443 $ 1,853
=========== ============
Volumes per day from continuing operations:
Crude oil pipeline - barrels................... 60,821 68,583
Three Months Ended March 31, 2005 Compared with Three Months Ended March
31, 2004
Pipeline segment margin increased $0.6 million or 32% to $2.4 million for
the three months ended March 31, 2005, as compared to $1.9 million for the three
months ended March 31, 2004. The increase in pipeline segment margin is
primarily attributable to an increase in pipeline revenues from tariffs and
related services. A breakdown of these revenues in each period is as follows:
Three Months Ended March 31,
2005 2004
----------- ------------
(in thousands)
Crude oil tariffs and revenues from direct
financing lease of crude oil pipelines...................... $ 3,263 $ 3,297
Sales of crude oil pipeline loss allowance volumes............. 1,079 787
Revenues from direct financing leases of CO2 pipelines......... 92 -
Natural gas tariffs............................................ 56 -
Tank rental reimbursements and other miscellaneous revenues.... 133 1
----------- ------------
Revenues from tariffs....................................... $ 4,623 $ 4,085
=========== ============
The effects of declines in volumes shipped on the Texas System and the
lower tariff on that system were offset by increased volumes and higher tariffs
on the Mississippi System.
Revenues from sales of crude oil volumes deducted from shippers as
pipeline loss allowances that exceeded actual losses increased in the 2005 first
quarter as a result of higher crude oil market prices. The CO2 pipeline did not
exist in the first quarter of 2004, and the natural gas gathering pipelines were
acquired in the first quarter of 2005. Under a tank rental reimbursement
arrangement with the largest shipper on the Texas System that began in January
2005, we receive reimbursement for the costs of renting tankage at Webster.
In some cases we only transport natural gas for producers on our natural
gas gathering pipelines. We recorded natural gas tariffs for these services
totaling $56,000 in the first quarter of 2005.
In other cases, we acquire the natural gas that we gather utilizing our
natural gas gathering pipelines, recording gas sales and purchases. The net
profit from the sale of this gas added an additional $53,000 to the pipeline
transportation segment.
Costs of operating the pipelines remained the same as in the 2004 period.
Outlook for 2005 and Beyond
We anticipate that volumes on the Texas System may continue to decline as
refiners on the Texas Gulf Coast compete for crude oil with other markets
connected to TEPPCO's pipeline systems.
- 20-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
The tank rental reimbursement arrangement with the largest shipper on the
Texas System is expected to increase revenues from the Texas System by $0.5
million annually, offsetting a portion of the expected decrease in tariff
revenues.
We completed a hydrotest in the first quarter of 2005 that we believe will
allow us to continue to operate the West Columbia to Webster segment of pipeline
for service in heavy oil. This oil will be shipped under a joint tariff with
TEPPCO. The shippers agreed to an increase in this tariff during the fourth
quarter of 2004 if we would continue to provide this service which will provide
us with additional return on our investment in this segment. We expect an annual
increase in tariff revenues of $0.6 million, based on volumes shipped in the
fourth quarter of 2004.
Denbury is the largest oil and gas producer in Mississippi. Our
Mississippi System is adjacent to several of Denbury's existing and prospective
oil fields. There are mutual benefits to Denbury and us due to this common
production and transportation area. As Denbury continues to acquire and develop
old oil fields using CO2 based tertiary recovery operations, Denbury expects to
add crude oil gathering and CO2 supply infrastructure to these fields. Further,
as the fields are developed over time, it may create increased demand for our
crude oil transportation services. Beginning in September 2004, Denbury began
shipping on our Mississippi System rather than selling the crude oil to us to
market and ship on our Mississippi System. We also restructured our tariffs to
provide additional return on the investments we have made and will continue to
make in the Mississippi System.
We built a CO2 pipeline to connect Denbury's existing CO2 pipeline to the
Brookhaven oil field in Mississippi. The agreement with Denbury provides for a
minimum capacity charge that will provide $0.6 million of annual payments to us
for eight years with a commodity charge for volumes in excess of a threshold
volume. The segments of crude oil pipeline we constructed to Denbury's Olive and
Brookhaven fields also have agreements providing for minimum capacity charges
for ten years with commodity charges for volumes in excess of threshold volumes.
The payments under these crude oil transportation agreements will provide a
combined total of $0.6 million of annual payments to us, in addition to the
amount received for the CO2 pipeline. The Brookhaven CO2 and Olive pipelines
went into service in 2004 and the Brookhaven oil pipeline began service in the
first quarter of 2005. We account for these arrangements as direct financing
leases.
We believe that the best use of the Jay System may be to convert it to
natural gas service. We continue to review opportunities to effect such a
conversion. Part of the process will involve finding alternative methods for us
to continue to provide crude oil transportation services in the area. While we
believe this initiative has long-term potential, it is not expected to have a
substantial impact on us during 2005 or 2006.
We will continue to evaluate opportunities to dispose of or to make
further investments in components of this segment in order to improve its
performance.
CARBON DIOXIDE (CO2) OPERATIONS
In November 2003, we acquired a volumetric production payment ("VPP") of
167.5 Bcf of CO2 from Denbury and in September 2004 we acquired an additional
33.0 Bcf VPP. Denbury owns 2.7 trillion cubic feet of estimated proved reserves
of CO2 in the Jackson Dome area near Jackson, Mississippi. In addition to the
production payments, Denbury also assigned to us five of their existing
long-term CO2 contracts with industrial customers. Denbury owns the pipeline
that is used to transport the CO2 to our customers as well as to its own
tertiary recovery operations.
The volumetric production payments entitle us to a maximum daily quantity
of CO2 of 65,250 thousand cubic feet (Mcf) per day through December 31, 2009,
55,750 Mcf per day for the calendar years 2010 through 2012, and 37,750 Mcf per
day beginning in 2013 until we have received all volumes under the production
payments. Under the terms of transportation agreements with Denbury, Denbury
will process and deliver this CO2 to our industrial customers and receive a fee
from us of $0.16 per Mcf, subject to adjustments for inflation, for those
transportation services.
The industrial customers treat the CO2 and transport it to their own
customers. The primary industrial applications of CO2 by these customers include
beverage carbonation and food chilling and freezing. Based on
- 21-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Denbury's and our experience in 2003 and 2004, we can expect some seasonality in
our sales of CO2. The dominant months for beverage carbonation and freezing food
are from April to October, when warm weather increases demand for beverages and
the approaching holidays increase demand for frozen foods.
The average daily sales (in mcfs) of CO2 for each quarter in 2005, 2004
and 2003 under these contracts were as follows:
Quarter 2005 2004 2003
- ------- ------ ------ ------
First 47,808 45,671 45,038
Second 51,164 49,982
Third 53,095 50,679
Fourth 48,217 42,468
The terms of our contracts with the industrial customers include minimum
take-or-pay and maximum delivery volumes. The maximum daily contract quantity
per year in the contracts totals 61,500 Mcf. Under the minimum take-or-pay
volumes, the customers must purchase a total of 31,292 Mcf per day whether
received or not. Any volume purchased under the take-or-pay provision in any
year can then be recovered in a future year as long as the minimum requirement
is met in that year. In the two years ended December 31, 2004, all three
customers purchased more than their minimum take-or-pay quantities, as shown in
the table above.
Our five industrial contracts expire at various dates beginning in 2010
and extending through 2016. The sales contracts contain provisions for
adjustments for inflation to sales prices based on the Producer Price Index,
with a minimum price.
Operating results from continuing operations for our CO2 marketing segment
were as follows:
Three Months Ended March 31,
2005 2004
----------- ------------
(in thousands)
Revenues................. $ 2,280 $ 1,831
Marketing costs.......... (755) (591)
----------- ------------
Segment margin........ $ 1,525 $ 1,240
=========== ============
Volumes per day:
CO2 marketing - Mcf... 47,808 45,671
Three Months Ended March 31, 2005 Compared with Three Months Ended March
31, 2004
Revenues, costs and segment margin have increased due to the higher
volumes sold during the 2005 first quarter. The average segment margin per Mcf
of CO2 sold was $0.35 in the first quarter of 2005 as compared to $0.30 for the
first quarter of 2004. Because of differing contractual arrangements with the
customers, revenues and segment margin are also affected by the specific volumes
sold to each customer.
DISCONTINUED OPERATIONS
In the first quarter of 2005, we sold assets that were no longer in
service related to the operations that we sold in 2003, recognizing a gain of
$0.3 million. During the first quarter of 2004, we incurred costs totaling $0.2
million related to the dismantlement of assets that we abandoned in 2003.
OTHER COSTS AND INTEREST
Three Months Ended March 31, 2005 Compared with Three Months Ended March
31, 2004
General and administrative expenses. General and administrative expenses
consisted of the following:
-22-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Three Months Ended March 31,
2005 2004
----------- -------------
(in thousands)
Expenses excluding the effects of the stock
appreciation rights plan....................... $ 2,187 $ 2,060
Stock appreciation rights plan expense (credit)... (1,329) 1,104
----------- -------------
Total general and administrative expense....... $ 858 $ 3,164
=========== =============
General and administrative expenses decreased by $2.3 million, however,
the decrease is attributable entirely 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. Our
unit price rose 27% from $9.80 at December 31, 2003 to $12.45 at March 31, 2004
resulting in a $1.1 million increase to the accrual for this liability in the
first quarter of 2004. In the first quarter of 2005, our unit price declined
from $12.60 per unit at December 31, 2004 to $8.90 per unit at March 31, 2005.
As a result, all rights are "out of the money", and the liability at December
31, 2004 was reversed.
Interest expense, net. In the 2005 first quarter, our net interest expense
increased by $0.2 million compared to the 2004 period. In the 2005 period, our
average outstanding balance of bank debt was $6.6 million higher than in the
2004 first quarter and our average interest rate was 1.7% greater than in the
2004 period.
Gain on disposal 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.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL RESOURCES
At March 31, 2005, we had borrowed $5.0 million under the working capital
portion of the Credit Facility and $12.5 million under the acquisition portion.
Due to the revolving nature of loans under the Credit Facility, additional
borrowings and periodic repayments and re-borrowings may be made until the
maturity date of June 1, 2008. At March 31, 2005, we had letters of credit
outstanding under the Credit Facility totaling $9.5 million, comprised of $4.4
million and $4.3 million for crude oil purchases related to March 2005 and April
2005, respectively, and $0.8 million related to other business obligations.
The amount that we may have outstanding cumulatively in borrowings and
letters of credit under the working capital portion of the facility is subject
to a borrowing base calculation. The borrowing base is limited to $50 million
and is calculated monthly. At March 31, 2005, the borrowing base was $42.8
million. Therefore, the total amount available for borrowings at March 31, 2005
was $10 million under the working capital portion and $37.5 million under the
acquisition portion of the Credit Facility.
We were in compliance with the Credit Facility covenants at March 31,
2005.
We have no limitations on making distributions in our Credit Facility,
except as to the effects of distributions in covenant calculations. 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, 2005, the
calculation resulted in a ratio of 1.3 to 1.0. The Credit Facility also requires
that the level of operating cash inflows, as adjusted in accordance with the
Credit Facility, be at least $8.5 million. At March 31, 2005, the result of this
calculation was $10.7 million.
We will distribute our Available Cash to our Unitholders each quarter if
we are not in default of these covenants.
-23-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Our average daily outstanding balance under the Credit Facility during the
first quarter of 2005 was $10.3 million. The average interest rate we paid
during this same period was 7.26%. On April 1, 2005, we borrowed additional
funds under the Credit Facility of $13 million to fund the acquisition of T&P
Syngas. Market interest rates increased during the first quarter of 2005 by
0.50%, increasing the rate on our borrowings by that same amount during the
first quarter. The average interest rate on our outstanding borrowings at March
31, 2005 was 7.5%.
CAPITAL EXPENDITURES
A summary of our capital expenditures in the three months ended March 31,
2005 and 2004 is as follows:
THREE MONTHS ENDED MARCH 31,
----------------------------
2005 2004
----------- ------------
(in thousands)
Maintenance capital expenditures:
Texas pipeline system....................... $ 14 $ 8
Mississippi pipeline system................. 471 91
Jay pipeline system......................... 5 5
Crude oil gathering assets.................. 9 -
Administrative assets....................... 12 51
----------- ------------
Total maintenance capital expenditures... 511 155
Growth capital expenditures:
Mississippi pipeline system................. 79 245
Natural gas gathering assets................ 3,108 -
----------- ------------
Total growth capital expenditures........ 3,187 245
----------- ------------
Total capital expenditures............ $ 3,698 $ 400
=========== ============
Maintenance capital expenditures in 2005 and 2004 included pipeline and
station improvements in Mississippi to handle increased volumes. Administrative
assets included computer software and hardware.
The growth capital expenditures on the Mississippi system in 2005 included
additional tankage. Growth capital expenditures in the first quarter of 2004
related to the acquisition of right-of-way for the extensions of our crude oil
pipeline and a CO2 pipeline to Denbury's Brookhaven field. The natural gas
gathering assets were acquired from Multifuels in January 2005.
Although we have no commitments to make capital expenditures, based on the
information available to us at this time, we currently anticipate that our
maintenance capital expenditures for 2005 will total to approximately $2.4
million. These expenditures are expected to relate primarily to our Mississippi
System, including corrosion control expenditures, minor facility improvements
and improvements of the pipeline as a result of integrity management test
results.
Complying with Department of Transportation Pipeline Integrity Management
Program ("IMP") regulations has been and will be a significant factor in
determining the amount and timing of our capital expenditure requirements. The
IMP regulations required that a baseline assessment be completed within seven
years of March 31, 2002, with 50% of the mileage assessed in the first three and
one-half years. Reassessment is then required every five years. We expect to
spend $0.1 million in 2005 and $0.2 million in 2006 for pipeline integrity
testing that will be charged to pipeline operating expense as incurred. As
testing is completed, we are required to take prompt remedial action to address
integrity issues raised by the assessment.
The rehabilitation action required as a result of the assessment and
testing is expected to impact our capital expenditure program by requiring us to
make improvements to our pipeline. This creates a difficult budgeting and
planning challenge as we cannot predict the results of pipeline testing until
they are completed. Based on estimated improvements required from assessments
made during 2002 through 2004, we have estimated capital expenditures to be made
during the IMP assessment period from 2005 through 2009. These capital
expenditure projections are
-24-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
based on very preliminary data regarding the cost of rehabilitation. We will
update these projections as we obtain additional information. As we rehabilitate
the Mississippi System as a result of IMP testing, we will also make
improvements to handle increased volumes more efficiently. Overall we expect to
spend approximately $2.0 million in 2005 through 2007 for these improvements. We
do not expect to incur any rehabilitation expenditures on the other systems
during this period.
Expenditures for capital assets to grow the partnership distribution will
depend on our access to debt and capital discussed below in "Sources of Future
Capital." We will look for opportunities to acquire assets from other parties
that meet our criteria for stable cash flows such as the two acquisitions
discussed in "Acquisitions in 2005" above.
SOURCES OF FUTURE CAPITAL
The 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, 2005, we
had $17.5 million outstanding under the Credit Facility, and $47.5 million
available for borrowings. On April 1, 2005, we borrowed an additional $13.0
million to acquire 50% of T&P Syngas.
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 to expand the Partnership
will require funding through borrowings under the 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:
Three Months Ended March 31,
------------------------------
2005 2004
----------- -------------
(in thousands)
Cash provided by (used in):
Operating activities......... $ 2,539 $ (3,603)
Investing activities......... $ (2,824) $ (400)
Financing activities......... $ 1,338 $ 1,474
Operating. Net cash from operating activities for each period have been
comprised of the following:
Three Months Ended March 31,
-----------------------------
2005 2004
----------- ------------
(in thousands)
Net (loss) income............................... $ 2,770 $ (1,005)
Depreciation, amortization and impairment....... 1,526 1,640
Gain on sales of assets......................... (653) -
Direct financing leases......................... 120 -
Other non-cash items............................ (1,227) 1,104
Changes in components of working capital, net... 3 (5,342)
----------- ------------
Net cash from operating activities........... $ 2,539 $ (3,603)
=========== ============
Our operating cash flows are affected significantly by changes in items of
working capital. In the 2004 period we temporarily funded $6.9 million of a
litigation settlement with funds we borrowed and funds on hand. We were
reimbursed for this payment by insurers in May 2004, however, at March 31, 2004,
we had a net cash outflow related to this payment. Affecting all periods is the
timing of capital expenditures and their effects on our recorded liabilities.
-25-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Our accounts receivable settle monthly and collection delays generally
relate only to discrepancies or disputes as to the appropriate price, volume or
quality of crude oil delivered. Of the $90.5 million aggregate receivables on
our consolidated balance sheet at March 31, 2005, approximately $88.7 million,
or 98%, were less than 30 days past the invoice date.
Investing. Cash flows used in investing activities in the first quarter of
2005 were $2.8 million as compared to $0.4 million in 2004 period. In 2005, we
expended $3.6 million for property additions, including $3.1 million for the
natural gas gathering assets acquired from Multifuels. We also made a $0.5
million deposit toward the T&P Syngas acquisition. Offsetting these expenditures
was the receipt of $1.3 million for the sale of idle assets.
In 2004 we expended $0.2 million for the first phase of an addition to our
Mississippi System, by acquiring right-of-ways to be used for a crude oil
pipeline and a CO2 pipeline of approximately ten miles. We expended $0.2 million
for other capital improvements related to our corporate office and to handling
the increased volumes on our Mississippi System more efficiently.
Financing. In the first quarters of 2005 and 2004, financing activities
provided net cash of $1.3 million and $1.5 million, respectively. We increased
our borrowings by $2.2 million, primarily to fund the acquisition of the natural
gas assets and to make a deposit for the T&P Syngas interest of $0.5 million. We
utilized cash of $1.4 million to make distributions to our partners.
In the 2004 first quarter, our outstanding debt increased $2.9 million,
primarily related to the funding of a litigation settlement for which we
received reimbursement in May 2004. Distributions to our partners were $1.4
million.
DISTRIBUTIONS
As a master limited partnership, the key consideration of our Unitholders
is the amount and reliability of our distribution, and our prospects for
distribution increases. We are required by our Partnership Agreement to
distribute 100% of our Available Cash within 45 days after the end of each
quarter to Unitholders of record and to the General Partner. Available Cash
consists generally of all of our cash receipts less cash disbursements adjusted
for net changes to reserves. Beginning with the distribution for the fourth
quarter of 2003, which was paid in February 2004, we have paid a quarterly
distribution to $0.15 per unit ($1.4 million in total).
Our general partner is entitled to receive incentive distributions if the
amount we distribute with respect to any quarter exceeds levels specified in our
partnership agreement. Under the quarterly incentive distribution provisions,
the general partner is entitled to receive 13.3% of any distributions in excess
of $0.25 per unit, 23.5% of any distributions in excess of $0.28 per unit, and
49% of any distributions in excess of $0.33 per unit, without duplication. We
have not paid any incentive distributions. The likelihood and timing of the
payment of any incentive distributions will depend on our ability to make
accretive acquisitions and generate cash flows from those acquisitions. We do
not expect to make incentive distributions during 2005.
We believe we will be able to sustain a regular quarterly distribution at
$0.15 per unit during 2005. Our ability to increase distributions during 2005
will depend in part on our success in developing and executing capital projects
and making accretive acquisitions, the results of our integrity management
program testing, and our ability to generate sustained improvements in the
gathering and marketing segment.
Available Cash before Reserves for the year ended March 31, 2005 is as
follows (in thousands):
Net income........................................................... $ 2,770
Depreciation and amortization........................................ 1,526
Cash received from direct financing leases not included in income.... 120
Cash effects from sales of certain asset sales....................... 666
Non-cash charges..................................................... (1,370)
Maintenance capital expenditures..................................... (511)
-----------
Available Cash before Reserves....................................... $ 3,201
===========
-26-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
We have reconciled Available Cash before Reserves (a non-GAAP liquidity
measure) to cash flow from operating activities (the GAAP measure) for the three
months ended March 31, 2005 below.
NON-GAAP FINANCIAL MEASURE
We believe that investors benefit from having access to the same financial
measures being utilized by management. Available Cash is a liquidity measure
used by our management to compare cash flows generated by the Partnership to the
cash distribution we pay to our limited partners and the general partner. This
is an important financial measure to our public unitholders since it is an
indicator of our ability to provide a cash return on their investment.
Specifically, this financial measure tells investors whether or not the
Partnership is generating cash flows at a level that can support a quarterly
cash distribution to our partners. Lastly, Available Cash (also referred to as
distributable cash flow) is a quantitative standard used throughout the
investment community with respect to publicly-traded partnerships.
Several adjustments to net income are required to calculate Available
Cash. These adjustments include: (1) the addition of non-cash expenses such as
depreciation and amortization expense; (2) miscellaneous non-cash adjustments
such as the addition of decreases or the subtraction of increases in the accrual
for our stock appreciation rights plan expense and the value of financial
instruments; and (3) the subtraction of maintenance capital expenditures.
Maintenance capital expenditures are capital expenditures (as defined by GAAP)
to replace or enhance partially or fully depreciated assets in order to sustain
the existing operating capacity or efficiency of our assets and extend their
useful lives. See "Distributions" above.
The reconciliation of Available Cash (a non-GAAP liquidity measure) to
cash flow from operating activities (the GAAP measure) for the year ended March
31, 2005, is as follows (in thousands):
Three
Months
Ended
March 31,
2005
---------
Cash flows from operating activities................................ $ 2,539
Adjustments to reconcile operating cash flows to Available Cash:
Maintenance capital expenditures................................ (511)
Proceeds from sales of certain assets........................... 1,319
Amortization of credit facility issuance fees................... (93)
Cash effects of stock appreciation rights plan.................. (50)
Net effect of changes in operating accounts not
included in calculation of Available Cash before
Reserves..................................................... (3)
---------
Available Cash before Reserves...................................... $ 3,201
=========
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, 2005.
-27-
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................. $ - $ - $ 17,500 $ - $ 17,500
Interest Payments (1).......... 1,281 2,412 202 - 3,895
Operating Leases............... 2,461 2,647 1,465 684 7,257
Unconditional Purchase
Obligations (2)............ 196,766 79,861 - - 276,627
--------- --------- --------- ------- ---------
Total Contractual Cash
Obligations............ $ 200,508 $ 84,920 $ 19,167 $ 684 $ 305,279
========= ========= ========= ======= =========
(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, 2005 remained outstanding through the maturity
date of June 1, 2008 and interest rates remained at the March 31, 2005
market levels through June 1, 2008. Actual obligations may differ from the
amounts included above.
(2) The unconditional purchase obligations included above are contracts to
purchase crude oil, generally at market-based prices. For purposes of this
table, market prices at March 31, 2005, were used to value the
obligations. Actual obligations may differ from the amounts included
above.
OFF-BALANCE SHEET ARRANGEMENTS
We have no off-balance sheet arrangements, special purpose entities, or
financing partnerships, other than as disclosed under Contractual Obligation and
Commercial Commitments above, nor do we have any debt or equity triggers based
upon our unit or commodity prices.
NEW 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 statements include, but are not limited to,
statements identified by the words "anticipate," "continue," "believe,"
"estimate," "expect," "plan," "may," "will," or "intend" or the negative of
those terms and similar expressions and statements regarding our business
strategy, plans and objectives of our management for future operations. We make
these statements based on our experience and our perception of historical
trends, current conditions and expected future developments as well as other
considerations we believe are appropriate under the circumstances.
Forward-looking statements are not guarantees of performance. They involve
risks, uncertainties and assumptions. Future actions, conditions or events and
future results of operations may differ materially from those expressed in these
forward-looking statements. Many of the factors that will determine these
results are beyond our ability to control or predict. Specific factors that
could cause actual results to differ from those in the forward-looking
statements include:
- demand for the supply of, changes in forecast data for, and price
trends related to crude oil, liquid petroleum, natural gas and
natural gas liquids in the United States, all of which may be
affected by economic activity, capital expenditures by energy
producers, weather, alternative energy sources, international
events, conservation and technological advances;
- throughput levels and rates;
-28-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
- changes in, or challenges to, our tariff rates;
- our ability to successfully identify and consummate strategic
acquisitions, make cost saving changes in operations and integrate
acquired assets or businesses into our existing operations;
- service interruptions in our pipeline transportation systems;
- shut-downs or cutbacks at refineries, petrochemical plants,
utilities or other businesses for which we transport crude oil or
to whom we sell crude oil;
- changes in laws or regulations to which we are subject;
- our inability to borrow or otherwise access funds needed for
operations, expansions or capital expenditures as a result of
existing debt agreements that contain restrictive covenants;
- loss of key personnel;
- the effects of competition;
- our lack of control over the activities and timing and amount of
distributions of partnerships in which we have invested that we do
not control;
- hazards and operating risks that may not be covered fully by
insurance;
- the condition of the capital markets in the United States;
- the political and economic stability of the oil producing nations of
the world; and
- general economic conditions, including rates of inflation and
interest rates.
You should not put undue reliance on any forward-looking statements. When
considering forward-looking statements, please review the risk factors described
under "Risk Factors" discussed in Item 7. "Management's Discussion and Analysis
of Financial Condition and Results of Operations" in our Annual Report on Form
10-K for the year ended December 31, 2004. Except as required by applicable
securities laws, we do not intend to update these forward-looking statements and
information.
-29-
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We may be exposed to market risks primarily related to volatility in crude
oil commodity prices and interest rates.
Our primary price risk relates to the effect of crude oil price
fluctuations on our inventories and the fluctuations each month in grade and
location differentials and their effect on future contractual commitments. We
seek to maintain a position that is substantially balanced between crude oil
purchases and sales and future delivery obligations. We utilize NYMEX commodity
based futures contracts and forward contracts to hedge our exposure to these
market price fluctuations as needed. At March 31, 2005, the Partnership had
entered into NYMEX future contracts that will settle by July 2005. None of these
contracts qualify for hedge accounting, therefore the fair value of theses
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.
Information about these contracts is contained in the table set forth
below:
Sell (Short)
Contracts
------------
Futures Contracts:
Contract volumes (1,000 bbls)............ 24
Weighted average price per bbl........... $ 55.89
Contract value (in thousands)............ $ 1,332
Mark-to-market change (in thousands)..... 9
------------
Market settlement value (in thousands)... $ 1,341
============
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, 2005 quoted market prices on the NYMEX.
We are also exposed to market risks due to the floating interest rates on
our credit facility. Our debt bears interest at the LIBOR or prime rate plus the
applicable margin. We do not hedge our interest rates. The average interest rate
presented below is based upon rates in effect at March 31, 2005. The carrying
value of our debt in our credit facility approximates fair value primarily
because interest rates fluctuate with prevailing market rates, and the credit
spread on outstanding borrowings reflects market.
Expected Year
Of Maturity
2008
(in thousands)
--------------
Long-term debt - variable rate 17,500
Average interest rate 7.5%
ITEM 4. CONTROLS AND PROCEDURES
We maintain disclosure controls and procedures and internal controls
designed to ensure that information required to be disclosed in our filings
under the Securities Exchange Act of 1934 is recorded, processed, summarized and
reported within the time periods specified in the Securities and Exchange
Commission's rules and forms. As of the end of the period covered by this
report, we carried out an evaluation, under the supervision of our Chief
Executive Officer and Chief Financial Officer, of the effectiveness of the
design and operation of our disclosure controls and procedures pursuant to Rule
13a-14 of the Exchange Act. Based upon that evaluation, our Chief Executive
Officer and Chief Financial Officer concluded that our disclosure controls and
procedures are adequate
-30-
and effective in all material respects in providing to them in a timely manner
material information relating to us (including our consolidated subsidiaries)
required to be disclosed in this quarterly report.
In addition, there have been no significant changes in our internal
controls over financial reporting during the three months ended March 31, 2005,
that have materially affected, or are reasonably likely to materially affect,
our internal controls over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See Part I. Item 1. Note 11 to the Consolidated Financial Statements
entitled "Contingencies", which is incorporated herein by reference.
ITEM 6. EXHIBITS.
(a) Exhibits.
Exhibit 31.1 Certification by Chief Executive Officer Pursuant to
Rule 13a-14(a) under the Securities Exchange Act of 1934.
Exhibit 31.2 Certification by Chief Financial Officer Pursuant to
Rule 13a-14(a) under the Securities Exchange Act of 1934.
Exhibit 32.1 Certification by Chief Executive Officer Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit 32.2 Certification by Chief Financial Officer Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
GENESIS ENERGY, L.P.
(A Delaware Limited Partnership)
By: GENESIS ENERGY, INC., as
General Partner
Date: May 9, 2005 By: /s/ ROSS A. BENAVIDES
------------------------------
Ross A. Benavides
Chief Financial Officer
-31-
EXHIBIT INDEX
Exhibit 31.1 Certification by Chief Executive Officer Pursuant to Rule
13a-14(a) under the Securities SExchange 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.