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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
--------------------------------
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2005
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-12295
GENESIS ENERGY, L.P.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 76-0513049
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
500 DALLAS, SUITE 2500, HOUSTON, TEXAS 77002
(Address of principal executive offices) (Zip Code)
(713) 860-2500
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined by Rule 12b-2 of the Exchange Act.)
Yes [ ] No [X]
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GENESIS ENERGY, L.P.
FORM 10-Q
INDEX
Page
-----
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets - June 30, 2005 and December 31, 2004.............................. 3
Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2005
and 2004.................................................................................... 4
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2005 and 2004.......... 5
Consolidated Statement of Partners' Capital for the Six Months Ended June 30, 2005............. 6
Notes to Consolidated Financial Statements..................................................... 7
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.......... 18
Item 3. Quantitative and Qualitative Disclosures about Market Risk..................................... 34
Item 4. Controls and Procedures........................................................................ 34
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.............................................................................. 35
Item 6. Exhibits and Reports on Form 8-K............................................................... 35
SIGNATURES.............................................................................................. 35
-2-
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
(Unaudited)
June 30, December 31,
2005 2004
---------- -----------
ASSETS
CURRENT ASSETS
Cash and cash equivalents...................................... $ 1,628 $ 2,078
Accounts receivable:
Trade....................................................... 89,614 68,737
Related party............................................... 617 584
Inventories.................................................... 4,329 1,866
Net investment in direct financing leases, net of
unearned income - current portion............................ 513 318
Insurance receivable........................................... 2,043 2,125
Other.......................................................... 1,503 1,688
---------- ------------
Total current assets........................................ 100,247 77,396
FIXED ASSETS, at cost............................................. 69,863 73,023
Less: Accumulated depreciation................................ (35,274) (39,237)
---------- ------------
Net fixed assets............................................ 34,589 33,786
NET INVESTMENT IN DIRECT FINANCING LEASES, net of
unearned income................................................ 6,211 4,247
CO2 ASSETS, net of amortization................................... 25,023 26,344
INVESTMENT IN T&P SYNGAS SUPPLY COMPANY........................... 13,757 -
OTHER ASSETS, net of amortization................................. 1,289 1,381
---------- ------------
TOTAL ASSETS...................................................... $ 181,116 $ 143,154
========== ============
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable:
Trade....................................................... $ 91,003 $ 74,176
Related party............................................... 1,053 1,239
Accrued liabilities............................................ 8,050 6,523
---------- ------------
Total current liabilities................................... 100,106 81,938
LONG-TERM DEBT.................................................... 34,400 15,300
OTHER LONG-TERM LIABILITIES....................................... 192 160
COMMITMENTS AND CONTINGENCIES (Note 12)
MINORITY INTERESTS................................................ 517 517
PARTNERS' CAPITAL
Common unitholders, 9,314 units issued and outstanding......... 44,975 44,326
General partner................................................ 926 913
---------- ------------
Total partners' capital..................................... 45,901 45,239
---------- ------------
TOTAL LIABILITIES AND PARTNERS' CAPITAL........................... $ 181,116 $ 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 June 30, Six Months Ended June 30,
2005 2004 2005 2004
------------ ----------- ------------ ------------
REVENUES:
Crude oil gathering and marketing:
Unrelated parties (including revenues from
buy/sell arrangements in the three and six
months of 2005 of $90,550 and $176,392 and
$72,639 and $131,435 in the three and six
months of 2004)................................ $ 247,450 $ 225,872 $ 494,274 $ 418,868
Related parties................................... 242 - 426 -
Pipeline transportation, including natural gas sales:
Unrelated parties................................. 5,726 4,086 11,927 8,171
Related parties................................... 1,158 - 2,269 -
CO2 revenues......................................... 2,568 2,149 4,848 3,980
------------ ----------- ------------ -------------
Total revenues.................................... 257,144 232,107 513,744 431,019
COSTS AND EXPENSES:
Crude oil costs:
Unrelated parties (including crude oil costs
from buy/sell arrangements in the three and
six months of 2005 of $90,254 and $176,399
and $72,407 and $130,989 in the three
and six months of 2004)........................ 241,535 192,309 483,346 358,281
Related parties................................... 1,524 28,424 2,001 51,399
Field operating................................... 4,183 3,195 8,015 6,238
Pipeline transportation costs:
Pipeline operating costs.......................... 2,300 2,429 4,533 4,661
Natural gas purchases............................. 1,776 - 4,412 -
CO2 distribution costs:
Transportation costs - related party.............. 773 662 1,490 1,228
Other costs....................................... 38 26 76 51
General and administrative........................... 2,468 2,022 3,326 5,186
Depreciation and amortization........................ 1,568 1,627 3,094 3,174
Net gain on disposal of surplus assets............... (27) (75) (398) (75)
------------ ----------- ------------ -------------
OPERATING INCOME..................................... 1,006 1,488 3,849 876
OTHER INCOME (EXPENSE):
Equity in earnings of investment in T&P Syngas....... 252 - 252 -
Interest income...................................... 22 4 28 28
Interest expense..................................... (528) (332) (889) (526)
------------ ----------- ------------ -------------
INCOME FROM CONTINUING OPERATIONS.................... 752 1,160 3,240 378
(Loss) income from operations of discontinued Texas
System......................................... (9) (61) 273 (284)
------------ ----------- ------------ -------------
NET INCOME........................................... $ 743 $ 1,099 $ 3,513 $ 94
============ =========== ============ =============
NET INCOME (LOSS) PER COMMON UNIT - BASIC AND
DILUTED:
Income from continuing operations.................
$ 0.08 $ 0.12 $ 0.34 $ 0.04
Income (loss) from discontinued operations........ 0.00 0.00 0.03 (0.03)
------------ ----------- ------------ -------------
NET INCOME........................................... $ 0.08 $ 0.12 $ 0.37 $ 0.01
============ =========== ============ =============
WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING.. 9,314 9,314 9,314 9,314
============ =========== ============ =============
The accompanying notes are an integral part of these consolidated
financial statements.
-4-
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
Six Months Ended June 30,
2005 2004
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income...................................................................... $ 3,513 $ 94
Adjustments to reconcile net income to net cash provided by operating
activities -
Depreciation................................................................. 1,773 2,038
Amortization of CO2 contracts................................................ 1,321 1,136
Amortization of credit facility issuance costs............................... 187 194
Amortization of unearned income on direct financing leases................... (349) -
Payments received under direct financing leases.............................. 593 -
Equity in earnings of investment in T&P Syngas............................... (252) -
Change in fair value of derivatives.......................................... (432) (18)
Gain on asset disposals...................................................... (671) (75)
Other non-cash (credits) charges............................................. (510) 592
Changes in components of working capital -
Accounts receivable....................................................... (20,910) (10,495)
Inventories............................................................... (3,163) (529)
Other current assets...................................................... 267 14,582
Accounts payable.......................................................... 15,395 9,871
Accrued liabilities....................................................... 2,383 (11,926)
--------- ---------
Net cash (used in) provided by operating activities............................... (855) 5,464
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment............................................. (4,394) (1,479)
Investment in T&P Syngas Supply Company......................................... (13,505) -
Other, net...................................................................... (53) (11)
Proceeds from sale of assets.................................................... 1,360 79
--------- ---------
Net cash used in investing activities............................................. (16,592) (1,411)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net borrowings (repayments) of debt............................................. 19,100 (1,500)
Credit facility issuance fees................................................... - (839)
Other, net...................................................................... 748 -
Distributions to common unitholders............................................. (2,794) (2,794)
Distributions to General Partner................................................ (57) (57)
--------- ---------
Net cash provided by (used in) financing activities............................... 16,997 (5,190)
--------- ---------
Net decrease in cash and cash equivalents......................................... (450) (1,137)
Cash and cash equivalents at beginning of year.................................... 2,078 2,869
--------- ---------
Cash and cash equivalents at end of period........................................ $ 1,628 $ 1,732
========= =========
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 six months ended June 30, 2005...... - 3,443 70 3,513
Distributions to partners during the six months ended
June 30, 2005........................................ - (2,794) (57) (2,851)
---------- ----------- --------- ---------
Partners' capital at June 30, 2005..................... 9,314 $ 44,975 $ 926 $ 45,901
========== =========== ========= =========
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 (i) our
consolidated financial position as of June 30, 2005 and December 31, 2004, (ii)
our consolidated results of operations and changes in comprehensive income for
the three and six months ended June 30, 2005 and 2004, (iii) our consolidated
cash flows for the six months ended June 30, 2005 and 2004, and (iv) our
consolidated changes in partners' capital for the six months ended June 30,
2005.
The financial statements included herein have been prepared by us without
audit pursuant to the rules and regulations of the Securities and Exchange
Commission (SEC). Accordingly, they reflect all adjustments (which consist
solely of normal recurring adjustments) which are, in the opinion of management,
necessary for a fair presentation of the financial results for interim periods.
Certain information and notes normally included in financial statements prepared
in accordance with generally accepted accounting principles have been condensed
or omitted pursuant to such rules and regulations. However, we believe that the
disclosures are adequate to make the information presented not misleading. These
financial statements should be read in conjunction with the financial statements
and notes thereto included in our Annual Report on Form 10-K for the year ended
December 31, 2004 filed with the SEC.
All significant intercompany transactions have been eliminated.
We have not included a provision for income taxes in our consolidated
financial statements; 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 and our reported crude oil costs from
unrelated parties for the three and six months ended June 30, 2005 and 2004
would be reduced by the amounts shown on parenthetical notations on the
consolidated statements of operations.
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 us in the first quarter of 2006. The
adoption of this statement will require that the compensation cost associated
with our stock appreciation rights plan be re-measured each reporting period
based on the fair value of the rights. Before the adoption of SFAS 123 (R), we
have accounted for the stock appreciation
-7-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
rights in accordance with FASB Interpretation No. 28, "Accounting for Stock
Appreciation Rights and Other Variable Stock Option or Award Plans" which
required that the liability under the plan be measured at each balance sheet
date based on the market price of our common units at that date. Under SFAS
123(R), the liability will be calculated using a fair value method that will
take into consideration the expected future value of the rights at their
expected exercise dates. We are currently evaluating what effect SFAS 123(R)
will have on our financial statements, but at this time, we do not believe that
the adoption of this statement will have a material effect on our financial
position, results of operations or cash flows.
In March 2005, the FASB issued FASB Interpretation No. 47, "Accounting for
Conditional Asset Retirement Obligations, an interpretation of FASB Statement
No. 143" (FIN 47). FIN 47 clarifies that the term "conditional asset retirement
obligation", as used in SFAS No. 143, "Accounting for Asset Retirement
Obligations", refers to a legal obligation to perform an asset retirement
activity in which the timing and/or method of settlement are conditional upon a
future event that may or may not be within the control of the entity. Although
uncertainty about the timing and/or method of settlement may exist and may be
conditional upon a future event, the obligation to perform the asset retirement
activity is unconditional. Accordingly, an entity is required to recognize a
liability for the fair value of a conditional asset retirement obligation if the
fair value of the liability can be reasonably estimated. FIN 47 clarifies when
an entity would have sufficient information to reasonably estimate the fair
value of an asset retirement obligation and emphasizes that uncertainty about
the timing or method of settlement of the obligation should be factored into the
calculation of the fair value of the obligation. FIN 47 is effective no later
than the end of reporting periods ending after December 15, 2005. We are
currently evaluating what effect FIN 47 will have on our financial statements,
but at this time, we do not believe that the adoption of FIN 47 will have a
material effect on our financial position, results of operations or cash flows.
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 June 30, 2005, the components of the net investment in direct financing
leases were as follows (in thousands):
Total minimum lease payments to be received ................... $ 10,003
Estimated residual values of leased property (unguaranteed) ... 1,287
Less: Unearned income ......................................... (4,566)
--------
Net investment in direct financing leases ..................... $ 6,724
========
At June 30, 2005, minimum lease payments to be received for each of the
five succeeding fiscal years are $1.2 million per year.
4. INVESTMENT IN T&P SYNGAS SUPPLY COMPANY
On April 1, 2005, we acquired a 50% interest in T&P Syngas Supply Company
(T&P Syngas), a Delaware general partnership, for $13.5 million from a
subsidiary of ChevronTexaco Corporation. Praxair Hydrogen Supply Inc. holds the
other 50% partnership interest in T&P Syngas. We paid for our interest in T&P
Syngas with borrowings under our credit facilities.
T&P Syngas processes raw materials provided by its customer into syngas
and steam and earns a fee for its processing services. These operations are
conducted at its facilities in Texas City, Texas.
-8-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We are accounting for our 50% ownership in T&P Syngas under the equity
method of accounting. T&P Syngas is managed by a management committee comprised
of representatives from each partner, therefore we share equally with Praxair in
the control over the partnership. We reflect in our consolidated statements of
operations our equity in T&P Syngas' net income, net of the amortization of the
excess of our investment over our share of partners' capital of T&P Syngas. We
paid $4.0 million more for our interest in T&P Syngas than our share of
partners' capital on the balance sheet of T&P Syngas at the date of the
acquisition. This excess amount of the purchase price over the equity in T&P
Syngas is being amortized using the straight-line method over the remaining
useful life of the assets of T&P Syngas of eleven years. Our consolidated
statements of operations for the three and six months ended June 30, 2005
included $339,000 as our share of the earnings of T&P Syngas for the period
beginning April 1, 2005, reduced by amortization of the excess purchase price of
$87,000.
The table below reflects summarized financial information for T&P Syngas
at June 30, 2005, for the period since we acquired our interest in T&P Syngas.
Three Months Ended
June 30, 2005
------------------
(in thousands)
Revenues ................................ $ 1,093
Operating expenses and depreciation ..... (417)
Other income ............................ 3
-------
Net income .............................. $ 679
=======
June 30, 2005
--------------
(in thousands)
Current assets ............................ $ 1,277
Non-current assets ........................ 17,177
-------
Total assets .............................. $18,454
=======
Current liabilities ....................... $ 252
Partners' capital ......................... 18,202
-------
Total liabilities and partners' capital ... $18,454
=======
The following pro forma information represents the effects on our
consolidated statements of operations assuming the investment in T&P Syngas had
occurred at the beginning of each period presented:
Three Months Ended June 30, Six Months Ended June 30,
2005 2004 2005 2004
---------- ----------- ---------- ------------
(in thousands, except per unit amounts)
Revenues .............................................. $ 257,144 $ 232,107 $ 513,744 $ 431,019
Operating income ...................................... $ 1,006 $ 1,488 $ 3,849 $ 876
Equity in investment in T&P Syngas .................... $ 252 $ 153 $ 412 $ 290
Net interest expense .................................. $ (506) $ (507) $ (1,084) $ (859)
Income from continuing operations ..................... 752 1,134 3,177 307
Net income ............................................ $ 743 $ 1,073 $ 3,540 $ 23
Basic and diluted net income (loss) per Common Unit
Income from continuing operations .................. $ 0.08 $ 0.12 $ 0.33 $ 0.03
Income (loss) from discontinued operations ......... 0.00 0.00 0.03 (0.03)
--------- --------- --------- ---------
Net income ......................................... $ 0.08 $ 0.12 $ 0.36 $ 0.00
========= ========= ========= =========
The acquisition of T&P Syngas occurred at the beginning of the three month
period ended June 30, 2005, so the pro forma results in the table above are the
same as the actual results for that period.
-9-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. DEBT
We have a credit facility that totals to $100 million, with $65 million
available for borrowing and $35 million available for letters of credit. At June
30, 2005, we had $34.4 million outstanding under our credit facility. At June
30, 2005, the weighted average interest rate on this debt was 7.27%. 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 June 30, 2005, we had letters of credit outstanding under the
credit facility totaling $9.7 million, comprised of $4.0 million and $4.9
million for crude oil purchases related to June 2005 and July 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 June 30, 2005, the borrowing base was $50.0
million. The remaining amount available for borrowings at June 30, 2005 was $5
million under the working capital portion and $25.6 million under the
acquisition portion of the credit facility.
Certain restrictive covenants of the credit facility limit our ability to
make distributions to our unitholders and our general partner. The credit
facility requires we maintain a cash flow coverage ratio of 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 June 30, 2005, the calculation
resulted in a ratio of 1.2 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 June 30, 2005, the result of this
calculation was $10.7 million. If we meet these covenants, we are otherwise not
limited by our credit facility in making distributions.
6. PARTNERS' CAPITAL AND DISTRIBUTIONS
Partners' Capital
Partnership equity consists of the general partner interest of 2%
and 9,313,811 common units representing limited partner interests of 98%.
The general partner interest is held by our general partner. We are
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 June 30, 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 the first half of 2005 and in 2004, we paid a
regular quarterly distribution of $0.15 per unit ($1.4 million in total per
quarter). We have declared a $0.15 per unit distribution for the second quarter
of 2005, payable on August 12, 2005 to unitholders of record on July 29, 2005.
Our general partner is entitled to receive 2% of our distributions
plus incentive distributions if the amount we distribute with respect to any
quarter exceeds levels specified in our partnership agreement. Under the
quarterly incentive distribution provisions, our general partner generally is
entitled to receive 13.3% of any distributions in excess of $0.25 per unit,
23.5% of any distributions in excess of $0.28 per unit and 49% of any
distributions in excess of $0.33 per unit without duplication. We have not paid
any incentive distributions through June 30, 2005.
-10-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Net Income Per Common Unit
The following table sets forth the computation of basic net income
per Common Unit.
Three Months Ended June 30, Six Months Ended June 30,
2005 2004 2005 2004
---------- ---------- --------- ----------
(in thousands, except per unit amounts)
Numerators for basic and diluted net income per common unit:
Income from continuing operations .................................... $ 752 $ 1,160 $ 3,240 $ 378
Less general partner 2% ownership .................................... 15 23 65 8
--------- --------- --------- ---------
Income from continuing operations available for common unitholders ... $ 737 $ 1,137 $ 3,175 $ 370
========= ========= ========= =========
Income (loss) from discontinued operations ........................... $ (9) $ (61) $ 273 $ (284)
Less general partner 2% ownership .................................... - (1) 5 (6)
--------- --------- --------- ---------
Income (loss) from discontinued operations available for common
unitholders ........................................................ $ (9) $ (60) $ 268 $ (278)
========= ========= ========= =========
Denominator for basic and diluted per Common Unit - weighted average
number of Common Units outstanding ....................................... 9,314 9,314 9,314 9,314
========= ========= ========= =========
Basic and diluted net income (loss) per Common Unit:
Income from continuing operations .................................... $ 0.08 $ 0.12 $ 0.34 $ 0.04
Income (loss) from discontinued operations ........................... 0.00 0.00 0.03 (0.03)
--------- --------- --------- ---------
Net income ........................................................... $ 0.08 $ 0.12 $ 0.37 $ 0.01
========= ========= ========= =========
7. BUSINESS SEGMENT INFORMATION
Our operations consist of three operating segments: (1) Crude Oil
Gathering and Marketing - the purchase and sale of crude oil at various points
along the distribution chain; (2) Pipeline Transportation - interstate and
intrastate crude oil, natural gas and CO2 pipeline transportation; and (3) CO2
sales - the sale, under long-term contracts, of CO2 acquired under a volumetric
production payment to industrial customers.
We evaluate segment performance based on segment margin before
depreciation and amortization. All of our revenues are derived from, and all of
our assets are located in, the United States.
-11-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Crude Oil
Gathering
and Pipeline CO2
Marketing Transportation Sales Total
---------- -------------- ---------- ----------
(in thousands)
Three Months Ended June 30, 2005
Revenues:
External Customers ............................................ $ 247,692 $ 5,957 $ 2,568 $ 256,217
Intersegment (a) .............................................. - 927 - 927
---------- ---------- ---------- ----------
Total revenues of reportable segments ......................... $ 247,692 $ 6,884 $ 2,568 $ 257,144
========== ========== ========== ==========
Segment margin excluding depreciation and amortization (b) .... $ 450 2,808 $ 1,757 $ 5,015
Capital expenditures .......................................... $ 254 $ 926 $ - $ 1,180
Maintenance capital expenditures .............................. $ 25 $ 175 $ - $ 200
Three Months Ended June 30, 2004
Revenues:
External Customers ............................................ $ 225,872 $ 3,206 $ 2,149 $ 231,227
Intersegment (a) .............................................. - 880 - 880
---------- ---------- ---------- ----------
Total revenues of reportable segments ......................... $ 225,872 $ 4,086 $ 2,149 $ 232,107
========== ========== ========== ==========
Segment margin excluding depreciation and amortization (b) .... $ 1,944 1,657 $ 1,461 $ 5,062
Capital expenditures .......................................... $ 24 $ 1,055 $ - $ 1,079
Maintenance capital expenditures .............................. $ 24 $ 231 $ - $ 255
Six Months Ended June 30, 2005
Revenues:
External Customers ............................................ $ 494,700 $ 12,590 $ 4,848 $ 512,138
Intersegment (a) .............................................. - 1,606 - 1,606
---------- ---------- ---------- ----------
Total revenues of reportable segments ......................... $ 494,700 $ 14,196 $ 4,848 $ 513,744
========== ========== ========== ==========
Segment margin excluding depreciation and amortization (b) .... $ 1,338 5,251 $ 3,282 $ 9,871
Capital expenditures .......................................... $ 276 $ 4,602 $ - $ 4,878
Maintenance capital expenditures .............................. $ 47 $ 664 $ - $ 711
Net fixed and other long-term assets (c) ...................... $ 6,438 $ 35,651 $ 25,023 $ 67,112
Six Months Ended June 30, 2004
Revenues:
External Customers ............................................ $ 418,868 $ 6,469 $ 3,980 $ 429,317
Intersegment (a) .............................................. - 1,702 - 1,702
---------- ---------- ---------- ----------
Total revenues of reportable segments ......................... $ 418,868 $ 8,171 $ 3,980 $ 431,019
========== ========== ========== ==========
Segment margin excluding depreciation and amortization (b) .... $ 2,950 3,510 $ 2,701 $ 9,161
Capital expenditures .......................................... $ 75 $ 1,404 $ - $ 1,479
Maintenance capital expenditures .............................. $ 75 $ 335 $ - $ 410
Net fixed and other long-term assets (c) ...................... $ 6,654 $ 29,181 $ 22,937 $ 58,772
a) Intersegment sales were conducted on an arm's length basis.
b) Segment margin was calculated as revenues less cost of sales and
operations expense. A reconciliation of segment margin to operating income
from continuing operations for the periods presented is as follows:
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GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended June 30, Six Months Ended June 30,
2005 2004 2005 2004
-------- -------- --------- --------
(in thousands)
Segment margin excluding depreciation and
amortization .............................. $ 5,015 $ 5,062 $ 9,871 $ 9,161
General and administrative expenses ......... 2,468 2,022 3,326 5,186
Depreciation, amortization and impairment ... 1,568 1,627 3,094 3,174
Net gain on disposal of surplus assets ...... (27) (75) (398) (75)
------- ------- ------- -------
Operating income from continuing operations .... $ 1,006 $ 1,488 $ 3,849 $ 876
======= ======= ======= =======
c) Net fixed and other long-term assets are the measure used by management in
evaluating the results of its operations on a segment basis. Current
assets are not allocated to segments as the amounts are shared by the
segments or are not meaningful in evaluating the success of the segment's
operations.
8. TRANSACTIONS WITH RELATED PARTIES
Sales, purchases and other transactions with affiliated companies, in the
opinion of management, are conducted under terms no more or less favorable than
then-existing market conditions.
Sales and Purchases of Crude Oil
Purchases of crude oil from Denbury for the six months ended June
30, 2005 and 2004 were $2.0 million and $51.4 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 own account. Denbury pays us a
fee for this trucking service that varies with the distance the crude oil is
trucked. For the six months ended June 30, 2005, we received fees from Denbury
totaling $0.4 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 $1.9 million for the six
months ended June 30, 2005. We also earned fees from Denbury totaling $0.6
million under the direct financing lease arrangements for the Olive and
Brookhaven crude oil pipelines and the Brookhaven CO2 pipeline and recorded $0.3
million of pipeline transportation income from these arrangements. See Note 3.
We also provide pipeline monitoring services to Denbury for which we
charged $15,000 and $10,000 for the six months ended June 30, 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 our 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 $7.7 million and $6.7 million for
the six months ended June 30, 2005 and 2004, respectively.
Due to and from Related Parties
At June 30, 2005 and December 31, 2004, we owed Denbury $0.5 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
-13-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
services at June 30, 2005 and December 31, 2004, respectively. Denbury owed us
$0.5 million and $0.4 million for transportation services at June 30, 2005 and
December 31, 2004, respectively. We had advanced $0.1 million and $0.1 million
to our general partner at June 30, 2005 and December 31, 2004, respectively, for
administrative services.
Directors' Fees
In each of the six months ended June 30, 2005 and 2004, we paid
$60,000 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 2004 and
2003. Denbury charges us a transportation fee of $0.16 per Mcf (adjusted for
inflation) to deliver the CO2 for us to our customers. For the six months ended
June 30, 2005 and 2004, we paid Denbury $1.5 million and $1.2 million for these
transportation services related to our sales of CO2.
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.
9. 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 integrated and large independent energy
companies with stable payment experience. The credit risk related to contracts
which are traded on the NYMEX is limited due to the daily cash settlement
procedures and other NYMEX requirements.
We have established various procedures to manage our credit exposure,
including initial credit approvals, credit limits, collateral requirements and
rights of offset. Letters of credit, prepayments and guarantees are also
utilized to limit credit risk to ensure that our established credit criteria are
met.
Occidental Energy Marketing, Inc., Shell Oil Company and Plains All
American, L.P. accounted for 27%, 12% and 11% of total revenues for the first
half of 2005, respectively. Occidental Energy Marketing, Inc. and Marathon
Ashland Petroleum LLC accounted for 16% and 15% of total revenues for the six
months ended June 30, 2004, respectively. The majority of the revenues from
these four customers in both periods relate to our crude oil gathering and
marketing operations.
10. SUPPLEMENTAL CASH FLOW INFORMATION
Cash received by the Partnership for interest was $28,000 and $28,000 for
the six months ended June 30, 2005 and 2004, respectively. Payments of interest
and commitment fees were $596,000 and $214,000 for the six months ended June 30,
2005 and 2004, respectively.
At June 30, 2005, we had incurred liabilities for fixed asset additions
totaling $0.5 million that had not been paid at the end of the quarter, and,
therefore, are not included in the caption "Additions to property and equipment"
on the Consolidated Statements of Cash Flows.
11. DERIVATIVES
Our market risk in the purchase and sale of crude oil contracts is the
potential loss that can be caused by a change in the market value of the asset
or commitment. In order to hedge our exposure to such market fluctuations,
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GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 fair value our derivative instruments at each period end with changes
in the 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. The effective portion of unrealized gains
or losses on derivative transactions qualifying as cash flow hedges are
reflected in other comprehensive income. Derivative transactions qualifying as
fair value hedges are evaluated for hedge effectiveness and the resulting hedge
ineffectiveness is recorded as a gain or loss in the consolidated statements of
operations.
We review our contracts to determine if the contracts meet the definition
of derivatives pursuant to SFAS 133. At June 30, 2005, we had futures contracts
on the NYMEX that were considered free-standing derivatives that are accounted
for at fair value. The fair value of these contracts was determined based on the
closing price for such contracts on the NYMEX on June 30, 2005. We marked these
contracts to fair value at June 30, 2005. During the three months and six months
ended June 30, 2005, we recorded gains of $84,000 and $8,000, respectively,
related to derivative transactions, which are included in the consolidated
statements of operations under the caption "Crude Oil Costs".
At June 30, 2005, we had futures contracts on the NYMEX that qualified as
derivatives and were formally documented and designated as fair value hedges of
inventory. During the three and six months ended June 30, 2005, we recognized a
loss, due to hedge ineffectiveness, on the fair value hedge of 60,000 barrels of
inventory totaling $9,000. This loss is included in the caption "Crude Oil
Costs" in the consolidated statements of operations. The time value component of
the derivative gain or loss excluded from the assessment of hedge effectiveness
was not material.
The consolidated balance sheet at June 30, 2005 includes $13,000 in other
current assets as a result of these derivative transactions.
At June 30, 2004, we had one swap contract that was considered a
free-standing derivative that was accounted for at fair value. The fair value of
this contract was determined based on quoted prices from independent sources. We
marked this contract to fair value at June 30, 2004, and recorded income of
$18,000 which is included in the consolidated statements of operations under the
caption "Crude Oil Costs".
We determined that the remainder of our derivative contracts qualified for
the normal purchase and sale exemption and were designated and documented as
such at June 30, 2005 and December 31, 2004.
12. CONTINGENCIES
Guarantees
We have guaranteed $3.5 million of residual value related to the
leases of tractors and trailers from Ryder Transportation, Inc. We believe the
likelihood we would be required to perform or otherwise incur any significant
losses associated with this guaranty is remote.
Along with our general partner, we have guaranteed the payments by
GCOLP to the banks under the terms of the Credit Facility related to borrowings
and letters of credit. Borrowings at June 30, 2005 were $34.4 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.
-15-
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 $2.4 million during the
remainder of 2005 and approximately $0.2 million in 2006 for testing, repairs
and improvements under regulations requiring assessment of the integrity of
crude oil pipelines.
Pennzoil Litigation
We were named a defendant in a complaint filed on January 11, 2001,
in the 125th District Court of Harris County, Texas, Cause No. 2001-01176.
Pennzoil-Quaker State Company (PQS) was seeking from us property damages, loss
of use and business interruption suffered as a result of a fire and explosion
that occurred at the Pennzoil Quaker State refinery in Shreveport, Louisiana, on
January 18, 2000. PQS claimed the fire and explosion were caused, in part, by
crude oil we sold to PQS that was contaminated with organic chlorides. In
December 2003, our insurance carriers settled this litigation for $12.8 million.
PQS is also a defendant in five consolidated class action/mass tort
actions brought by neighbors living in the vicinity of the PQS Shreveport,
Louisiana refinery in the First Judicial District Court, Caddo Parish,
Louisiana, Cause Nos. 455,647-A, 455,658-B, 455,655-A, 456,574-A, and 458,379-C.
PQS has brought a third party demand against us and others for indemnity with
respect to the fire and explosion of January 18, 2000. We believe that the
demand against us is without merit and intend to vigorously defend ourselves in
this matter. We currently 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 a one acre tract of land located in Santa Rosa
County, Florida to operate a crude oil trucking station, known as Jay Station.
The sublease provided that Howell would indemnify Koch for environmental
contamination on the property under certain circumstances. Howell operated the
Jay Station from 1992 until December of 1996 when this operation was sold to us
by Howell. We operated the Jay Station as a crude oil trucking station until
2003. Koch has indicated that it has incurred certain investigative and/or other
costs, for which Koch alleges some or all should be reimbursed by us, under the
indemnification provisions of the sublease for environmental contamination on
the site and surrounding areas. Koch has also alleged that we are responsible
for future environmental obligations relating to the Jay Station.
Howell was acquired by Anadarko Petroleum Corporation (Anadarko) in
2002. During the second quarter of 2005, we entered into a joint defense and
cost allocation agreement with Anadarko (the Joint Allocation Agreement). Under
the terms of the Joint Allocation Agreement, we agreed to reasonably cooperate
with each other to address any liabilities or defense costs with respect to the
Jay Station. Additionally under the Joint Allocation Agreement, Anadarko will be
responsible for sixty percent of the costs related to any liabilities or defense
costs incurred with respect to contamination at the Jay Station.
We were formed in 1996 by the sale and contribution of assets from
Howell and Basis Petroleum, Inc. (Basis). Anadarko's liability with respect to
the Jay Station is derived largely from contractual obligations entered into
upon our formation. We believe that Basis has contractual obligations under the
same formation agreements. We are preparing a formal demand seeking Basis' share
of potential liabilities and defense costs with respect to Jay Station.
We have contacted the appropriate state regulatory agencies
regarding developing a plan of remediation for certain affected soils at the Jay
Station. It is possible that we will also need to develop a plan for other
affected soils and/or affected groundwater. Through the second quarter of 2005,
we have accrued our best estimate of our share of liability for this matter in
the amount of $0.5 million. If we are required to remediate the site on a more
extensive basis than this estimate, we could incur additional obligations of up
to $0.8 million. The time period over which our liability would be paid is
uncertain and could be several years. This liability may decrease if
indemnification and/or cost reimbursement is obtained by us for Basis' potential
liabilities with respect to this matter. At this time, our
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GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
estimate of potential obligations does not assume any specific amount
contributed on behalf of the Basis obligations, although we believe that Basis
is responsible for a significant part of these potential obligations.
We are subject to various environmental laws and regulations.
Policies and procedures are in place to monitor compliance and to detect and
address any releases of crude oil from our pipelines or other facilities,
however no assurance can be made that such environmental releases may not
substantially affect our business.
Other Matters
We have taken additional security measures since the terrorist
attacks of September 11, 2001 in accordance with guidance provided by the
Department of Transportation and other government agencies. We cannot assure you
that these security measures would prevent our facilities from a concentrated
attack. Any future attacks on us or our customers or competitors could have a
material effect on our business, whether insured or not. We believe we are
adequately insured for public liability and property damage to others and that
our coverage is similar to other companies with operations similar to ours. No
assurance can be made that we will be able to maintain adequate insurance in the
future at premium rates that we consider reasonable.
We are subject to lawsuits in the normal course of business and
examination by tax and other regulatory authorities. Such matters presently
pending are not expected to have a material adverse effect on our financial
position, results of operations or cash flows.
13. SUBSEQUENT EVENT
On July 13, 2005, the Board of Directors of the general partner declared a
cash distribution of $0.15 per unit for the quarter ended June 30, 2005. The
distribution will be paid August 12, 2005, to our general partner and all common
unitholders of record as of the close of business on July 29, 2005.
-17-
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Included in Management's Discussion and Analysis are the following
sections:
- Overview
- Acquisitions in 2005
- Results of Operations and Outlook for 2005 and Beyond
- Liquidity and Capital Resources
- Commitments and Off-Balance Sheet Arrangements
- Other Matters
- New Accounting Pronouncements
In the discussions that follow, we will focus on two measures that we use
to manage the business and to review the results of our operations. Those two
measures are segment margin and Available Cash before Reserves. Our
profitability depends to a significant extent upon our ability to maximize
segment margin. Segment margin is calculated as revenues less cost of sales and
operating expense, and does not include depreciation and amortization. A
reconciliation of Segment Margin to income from continuing operations is
included in our segment disclosures in Note 7 to the consolidated financial
statements. Available Cash before Reserves is a non-GAAP measure calculated as
net income with several adjustments, the most significant of which are the
elimination of gains and losses on asset sales, except those from the sale of
surplus assets, the addition of non-cash expenses such as depreciation, and the
subtraction of maintenance capital expenditures, which are expenditures to
sustain existing cash flows but not to provide new sources of revenues. For
additional information on Available Cash before Reserves and a reconciliation of
this measure to cash flows from operations, see "Liquidity and Capital Resources
- - Non-GAAP Financial Measure" below.
OVERVIEW
We operate in three business segments - crude oil gathering and marketing,
pipeline transportation and CO2 sales. We generate revenues by selling crude oil
and CO2 and by charging fees for the transportation of crude oil, natural gas
and CO2 on our pipelines. Our focus is on the margin we earn on these revenues,
which is calculated by subtracting the costs of the crude oil, the costs of
transporting the crude oil, natural gas and CO2 to the customer, and the costs
of operating our assets. We also made a 50% investment in T&P Syngas Supply
Company (T&P Syngas) on April 1, 2005.
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 second quarter of 2005, we generated Available
Cash before Reserves that enabled us to pay our regular quarterly distribution
and build reserves toward any future distribution shortfalls.
We generated net income for the six months of 2005 from a combination of
four main sources. These sources included the results of our operating
activities, the sale of idle assets, our equity in the earnings from our
investment in T&P Syngas, and the effects of decreasing the liability under our
incentive compensation plan.
We have a stock appreciation rights plan under which employees and
directors are granted rights to receive cash upon exercise for the difference
between the strike price of the rights and the market price for our units at the
time of exercise. These rights vest over several years. As our unit price
declined from $12.60 at December 31, 2004 to $8.90 per unit at March 31, 2005,
we decreased our liability during the first quarter from $1.3 million to zero,
recording a credit of $1.3 million. The unit price then increased in the second
quarter of 2005 to $9.39, for which we provided a liability of $43,000.
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
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GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
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. Praxair
operates the facility.
T&P Syngas is managed by a management committee consisting of two
representatives each from Praxair and us. The T&P Syngas management committee
has an approved resolution that provides that cash distributions will be paid
quarterly to the partners in the amount of cash on hand in excess of $100,000.
In July 2005, we received a distribution of $0.3 million from T&P Syngas related
to the second quarter of 2005.
The acquisition of our interest in T&P Syngas 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
approximately equivalent amounts. Because period-to-period variations in
revenues and costs of sales are not generally meaningful in analyzing the
variation in segment margin for 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.
-19-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Operating results from continuing operations for our crude oil
gathering and marketing segment were as follows:
Three Months Ended June 30, Six Months Ended June 30,
2005 2004 2005 2004
---------- ---------- ---------- ----------
(in thousands, except volumes per day)
Revenues ..................................... $ 247,692 $ 225,872 $ 494,700 $ 418,868
Crude oil costs .............................. 243,500 220,751 485,779 409,698
Field operating costs ........................ 4,183 3,195 8,015 6,238
Change in fair value of derivatives .......... (441) (18) (432) (18)
--------- --------- --------- ---------
Segment margin ............................ $ 450 $ 1,944 $ 1,338 $ 2,950
========= ========= ========= =========
Volumes per day from continuing operations:
Crude oil wellhead - barrels .............. 40,323 49,128 41,142 48,787
Crude oil total - barrels ................. 55,722 65,164 57,027 62,877
Crude oil transported only - barrels ...... 2,702 705 3,905 484
Three Months Ended June 30, 2005 Compared with Three Months Ended
June 30, 2004
Crude oil gathering and marketing segment margins from continuing
operations decreased $1.5 million for the three months ended June 30, 2005, as
compared to the three months ended June 30, 2004. Segment margin decreased
primarily due to two factors with a third factor partially offsetting the
decrease. These three factors were as follows:
- A $1.0 million increase in field operating costs. $0.4 million
of this increase is attributable to a reserve we recorded for
40% of the expected costs to remediate Jay Station. (See
additional discussion at Note 12 to the Consolidated Financial
Statements.) The majority of the remaining increase of $0.6
million over the 2004 second quarter related to higher fuel
costs and higher personnel costs. Fuel costs have increased
approximately $0.60 per gallon, or 39%, 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.
- A 14% decrease in wellhead, bulk and exchange purchase volumes
resulting in a $0.7 million reduction in segment margin.
- A $0.2 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.
Six Months Ended June 30, 2005 Compared with Six Months Ended June
30, 2004
For the six month period, crude oil gathering and marketing segment
margins from continuing operations decreased $1.6 million in 2005 from the prior
year period. Contributing to this reduction in segment margin were the following
two factors that reduced segment margin:
- A $1.8 million increase in field operating costs. $0.4 million
of this increase is attributable to a reserve for the clean-up
of a site as discussed above in the three month comparison.
The majority of the remaining increase of $1.4 million over
the 2004 second quarter related again to higher fuel costs,
higher employee costs and the costs related to the additional
tractor/trailers.
-20-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
- A 5,850 barrel per day decrease in purchased volumes. This 9%
decrease reduced segment margin by $0.9 million.
Partially offsetting the decrease from higher field costs and lower
volumes were increases in three factors. These factors were:
- A $0.6 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 $0.4 million increase in the average difference between the
price of crude oil at the point of purchase and the price of
crude oil at the point of sale;
- A $0.1 million decrease in credit costs related to crude oil
transactions.
Outlook
Based on past experience and knowledge of assets in the crude oil
gathering and marketing segment, we continue to expect volatility from this
segment. 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 five
state area. We refer to these pipelines as our Texas System, Mississippi System
and Jay System. Average volumes shipped on these systems for the three months
and six months ended June 30, 2005 and 2004 are as follows:
Three Months Ended June 30, Six Months Ended June 30,
2005 2004 2005 2004
------ ------ ------ ------
(barrels per day)
Texas.......... 33,234 39,672 31,540 40,939
Jay............ 15,204 15,523 15,030 15,702
Mississippi.... 15,655 11,961 15,896 11,228
Volumes on our Texas System averaged 33,234 barrels per day during
the second 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. Substantially all of the volume being shipped
on our Texas System goes to two refineries on the Texas Gulf Coast.
The Mississippi System begins in Soso, Mississippi and extends to
Liberty, Mississippi. At Liberty, shippers can transfer the crude oil to a
connection to Capline, a pipeline system that moves crude oil from the Gulf
Coast to refineries in the Midwest. The system has been improved to handle the
increased volumes produced by Denbury and transported on the pipeline. In order
to handle expected future increases in production volumes in the area, we have
made capital expenditures for tank, station and pipeline improvements, and we
intend to make further improvements. See Capital Expenditures under "Liquidity
and Capital Resources" below.
Beginning in September 2004, Denbury became a shipper on the
Mississippi System under an incentive tariff designed to encourage shippers to
increase volumes shipped on the pipeline. Prior to this point, Denbury sold its
production to us before it was injected into the pipeline.
-21-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
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:
Three Months Ended June 30, Six Months Ended June 30,
2005 2004 2005 2004
--------- --------- --------- ---------
(in thousands, except volumes per day)
Revenues from crude oil and CO2 tariffs, including
revenues from direct financing leases .............. $ 4,993 $ 4,086 $ 9,561 $ 8,171
Revenues from natural gas tariffs and sales .......... 1,891 - 4,635 -
Natural gas purchases ................................ (1,776) - (4,412) -
Pipeline operating costs ............................. (2,300) (2,429) (4,533) (4,661)
-------- -------- -------- --------
Segment margin ..................................... $ 2,808 $ 1,657 $ 5,251 $ 3,510
======== ======== ======== ========
Volumes per day from continuing operations:
Crude oil pipeline - barrels ....................... 64,093 67,156 62,466 67,869
A breakdown of revenues from tariffs is as follows:
Three Months Ended June 30, Six Months Ended June 30,
2005 2004 2005 2004
------ ------ ------- ------
(in thousands)
Crude oil tariffs and revenues from direct financing
leases of crude oil pipelines ................................... $3,517 $3,267 $6,781 $6,565
Sales of crude oil pipeline loss allowance volumes ................ 1,219 808 2,298 1,595
Revenues from direct financing leases of CO2 pipelines ............ 91 - 183 -
Tank rental reimbursements and other miscellaneous revenues ....... 166 11 299 11
------ ------ ------ ------
Revenues from crude oil and CO2 tariffs and related sources .... $4,993 $4,086 $9,561 $8,171
====== ====== ====== ======
Three Months Ended June 30, 2005 Compared with Three Months Ended
June 30, 2004
Pipeline segment margin increased $1.2 million or 69% to $2.8
million for the three months ended June 30, 2005, as compared to the three
months ended June 30, 2004. The increase in pipeline segment margin is primarily
attributable to an increase in pipeline revenues. Crude oil and CO2 tariff
revenues increased $0.9 million in the 2005 second quarter compared to the prior
year period due to the combination of higher tariffs, offset by a slight decline
in
-22-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
volume. Also contributing to the improved segment margin were $0.1 million of
net profit from the sales of natural gas and a $0.1 decrease in pipeline
operating costs.
Crude oil tariffs and revenues from direct financing leases of crude
oil pipelines contributed $0.2 million of the increased tariff revenues. 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 $0.4 million in
the 2005 second 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, each of which
added $0.1 million of additional tariff revenues. 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, which also added $0.1 million of additional tariff revenues.
Operating costs decreased $0.1 million due to a combination of a
reduction in costs related to an out-of-service offshore pipeline that was
recorded in the second quarter of 2004 offset by higher operating costs on the
active pipelines. In the 2004 second quarter, we increased, by $0.5 million, an
accrual to remove the offshore pipeline. In 2005, costs increased for numerous
items including liability insurance, maintenance projects and various
operational costs.
Six Months Ended June 30, 2005 Compared with Six Months Ended June
30, 2004
For the six months ended June 30, 2005, pipeline segment margin
increased $1.7 million or 50%, as compared to the same period in 2004. Revenues
from crude oil and CO2 tariffs and related sources added $1.4 million of the
increase for the period, with $0.2 million of the increase resulting from net
profit from natural gas transportation and sales and $0.1 million from lower
operating costs.
Although crude oil pipeline volumes declined, this decrease was
almost entirely on the Texas System where the tariff rate is much lower than the
other crude oil pipeline systems. Increased volumes on the Mississippi System
combined with higher tariffs on that system more than offset the decrease from
the Texas System. Overall, crude oil pipeline tariffs, including income from
direct financing leases of crude oil pipelines increased $0.2 million between
the six month periods. Higher market prices for crude oil added $0.7 million to
pipeline loss allowance revenues between the periods, and tariffs from the CO2
pipeline added another $0.2 million. The tank rental agreement on the Texas
System combined with other miscellaneous revenues added $0.3 million to tariff
revenues between the periods.
Operating costs declined $0.1 million. The 2004 six month period
included the charge described above related to the offshore pipeline. The 2005
period included increases in the items described for the three month comparison
above as well as increased compliance costs related to certification and
monitoring of contractors.
Outlook
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. 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 potential decrease in tariff revenues.
We completed a hydrotest during the first quarter of 2005 that we
believe will allow us to continue to operate the West Columbia to Webster
segment of pipeline in heavy oil service. This oil is being 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.
-23-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
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.
As a result of new production in the area surrounding the Jay
System, volumes have stabilized on that system. Historically, producing wells in
the area have had rapidly declining future production curves, therefore we do
not know if this new production will be sufficient to continue to offset
declining production from existing wells in the area.
Should the production surrounding the Jay System decline such that
it becomes uneconomic to continue to operate the pipeline in crude oil service,
we believe that the best use of the Jay System may be to convert it to natural
gas service. We continue to review opportunities to effect such a conversion.
Part of the process will involve finding alternative methods for us to continue
to provide crude oil transportation services in the area. While we believe this
initiative has long-term potential, it is not expected to have a substantial
impact on us during 2005 or 2006.
We will continue to evaluate opportunities to dispose of or to make
further investments in components of this segment in order to improve its
performance.
CARBON DIOXIDE (CO2) OPERATIONS
In November 2003, we acquired a volumetric production payment, or
VPP, of 167.5 Bcf of CO2 from Denbury and in September 2004 we acquired an
additional 33.0 Bcf VPP. Denbury owns 2.7 trillion cubic feet of estimated
proved reserves of CO2 in the Jackson Dome area near Jackson, Mississippi. In
addition to the production payments, Denbury also assigned to us five of their
existing long-term CO2 contracts with industrial customers. Denbury owns the
pipeline that is used to transport the CO2 to our customers as well as to its
own tertiary recovery operations.
The volumetric production payments entitle us to a maximum daily
quantity of CO2 of 65,250 thousand cubic feet (Mcf) per day through December 31,
2009, 55,750 Mcf per day for the calendar years 2010 through 2012, and 37,750
Mcf per day beginning in 2013 until we have received all volumes under the
production payments. Under the terms of transportation agreements with Denbury,
Denbury will process and deliver this CO2 to our industrial customers and
receive a fee from us of $0.16 per Mcf, subject to adjustments for inflation,
for those transportation services.
The industrial customers treat the CO2 and transport it to their own
customers. The primary industrial applications of CO2 by these customers include
beverage carbonation and food chilling and freezing. Based on Denbury's and our
experience in 2003 and 2004, we can expect some seasonality in our sales of CO2.
The dominant months for beverage carbonation and freezing food are from April to
October, when warm weather increases demand for beverages and the approaching
holidays increase demand for frozen foods.
-24-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
The average daily sales (in Mcfs) of CO2 for each quarter in 2005
and 2004 under these contracts (including volumes sold by Denbury on the
contracts we acquired in the third quarter of 2004) were as follows:
Quarter 2005 2004
- ------- ------ ------
First 47,808 45,671
Second 51,049 51,164
Third 53,095
Fourth 48,217
The terms of our contracts with the industrial customers include
minimum take-or-pay and maximum delivery volumes. The maximum daily contract
quantity per year in the contracts totals 61,500 Mcf. Under the minimum
take-or-pay volumes, the customers must purchase a total of 31,292 Mcf per day
whether received or not. Any volume purchased under the take-or-pay provision in
any year can then be recovered in a future year as long as the minimum
requirement is met in that year. In the two years ended December 31, 2004, all
three customers purchased more than their minimum take-or-pay quantities.
Our five industrial contracts expire at various dates beginning in
2010 and extending through 2016. The sales contracts contain provisions for
adjustments for inflation to sales prices based on the Producer Price Index,
with a minimum price.
Operating results from continuing operations for our CO2 Sales
segment were as follows:
Three Months Ended June 30, Six Months Ended June 30,
2005 2004 2005 2004
------- ------- ------- -------
(in thousands, except volumes per day)
Revenues ............................................. $ 2,568 $ 2,149 $ 4,848 $ 3,980
CO2 transportation and other costs ................... 811 688 1,566 1,279
------- ------- ------- -------
Segment margin .................................... $ 1,757 $ 1,461 $ 3,282 $ 2,701
======= ======= ======= =======
Volumes per day from continuing operations:
CO2 Sales - Mcf ................................... 51,049 45,480 49,437 42,164
Three Months Ended June 30, 2005 Compared with Three Months Ended
June 30, 2004
The increase in volume in the second quarter was due to the effects
of the additional contracts acquired in September 2004. The average revenue per
Mcf sold increased by $0.04, due to inflation adjustments in the contracts and
variations in the volumes sold under each contract.
Transportation costs for the CO2 on Denbury's pipeline increased by
$0.1 million when comparing the second quarters. This increase is attributable
to the increased volume and the effect of the annual inflation adjustment factor
in the rate paid to Denbury. The rate in the second quarter of 2005 averaged
$0.1664 per Mcf as compared to $0.16 per Mcf in the 2004 period
Six Months Ended June 30, 2005 Compared with Six Months Ended June
30, 2004
For the six month period, the increased revenues are attributable to
the same effects as in the 2004 period. Volumes increased due to the additional
contracts, and the average sales price increased by $0.02 per Mcf.
The rate for transportation costs increased from an average of $0.16
per Mcf to $0.1665 per Mcf, due to the inflation provision in the transportation
contract.
Outlook
We may be able to acquire additional volumetric production payments
from Denbury that could increase segment margin for this operation.
-25-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
DISCONTINUED OPERATIONS
In the first and second quarters of 2005, we sold assets that were
no longer in service related to the Texas operations that we sold in 2003,
receiving $0.3 million and recognizing a gain of $0.3 million. During the first
and second quarters of 2004, we incurred costs totaling $0.3 million related to
the dismantlement of assets that we abandoned in 2003.
OTHER COSTS AND INTEREST
General and administrative expenses. General and administrative
expenses were as follows:
Three Months Ended June 30, Six Months Ended June 30,
2005 2004 2005 2004
------- -------- -------- -------
(in thousands)
Expenses excluding effect of stock appreciation rights plan ..... $ 2,425 $ 2,534 $ 4,612 $ 4,594
Stock appreciation rights plan expense (credit) ................. 43 (512) (1,286) 592
------- ------- ------- -------
Total general and administrative expenses .................... $ 2,468 $ 2,022 $ 3,326 $ 5,186
======= ======= ======= =======
Three Months Ended June 30, 2005 Compared with Three Months Ended
June 30, 2004
General and administrative expenses increased by $0.4 million,
however, the increase is attributable to our employee stock appreciation rights
(SAR) plan. This plan is a long-term incentive plan whereby rights are granted
for the grantee to receive cash equal to the difference between the grant price
and common unit price at date of exercise. The rights vest over several years.
Between the end of the first quarter of 2005 and the end of the second quarter
of 2005, the market price for our units rose from an amount where the exercise
price of all rights was below the market price at March 31, 2005, to a market
price at June 30, 2005 where the rights had a small amount of value. In the 2004
three month period, the market price declined, resulting in a credit to general
and administrative expense of $0.5 million.
The remainder of our general and administrative expenses declined
slightly between the two quarterly periods.
Six Months Ended June 30, 2005 Compared with Six Months Ended June
30, 2004
For the six month periods, general and administrative expenses
decreased by $1.9 million, with the decrease attributable entirely to our
employee stock appreciation rights plan. In the 2004 period, the market price
for our common units rose so that we recorded a liability of $0.6 million. In
the 2005 period, our unit price declined from $12.60 per unit at December 31,
2004 to $9.39 per unit at June 30, 2005. As a result, a reduction in the accrual
was recorded, resulting in a total difference of $1.9 million.
General and administrative expenses, excluding the effects of our
stock appreciation rights (SAR) plan, were flat between the two six month
periods.
Equity in T&P Syngas. On April 1, 2005, we acquired a 50% interest
in T&P Syngas. Our share of the earnings of T&P Syngas for the second quarter of
2005 was $339,000. We are amortizing the excess of the price we paid for our
interest in T&P Syngas over our share of the equity of T&P Syngas over the
remaining useful life of the assets of T&P Syngas. This excess of $4.0 million
is being amortized over eleven years. The effect of this amortization was to
reduce the amount we recorded as our equity in T&P Syngas for the second quarter
by $87,000. In July 2005, we received a distribution from T&P Syngas of $313,000
related to the second quarter.
-26-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Interest expense, net. Interest expense, net was as follows:
Three Months Ended June 30, Six Months Ended June 30,
2005 2004 2005 2004
------------- ------------ --------- -----------
(in thousands)
Interest expense, including commitment fees....... $ 440 $ 245 $ 713 $ 349
Amortization of facility fees..................... 88 87 176 177
Interest income................................... (22) (4) (28) (28)
------------ ----------- -------- ----------
Net interest expense........................... $ 506 $ 328 $ 861 $ 498
============ =========== ======== ==========
In the second quarter and first half of 2005, we had more debt
outstanding and market interest rates rose. Additionally in June 2004, we
increased the size of our credit facility resulting in increased commitment
fees. These factors contributed to an increase in interest expense in these
periods as compared to the same periods in 2004.
In the 2005 second quarter, our average outstanding balance of bank
debt was $18.0 million higher than in the 2004 second quarter and our average
interest rate was 2.1% greater than in the 2004 period. The debt increase is
attributable primarily to acquisitions in the 2005 period.
In the 2005 six month period, our average outstanding balance of
debt was $12.4 million higher than in the 2004 period and our average interest
rate was 1.8% greater than the 2004 period.
Gain on disposal of surplus assets. In the first half of 2005, we
sold the Liberty to Maryland segment of our Mississippi pipeline. This segment
had been out-of-service since February 2002. Additionally, we sold an idle site
in Houma, Louisiana and other surplus assets. We received $1.1 million from the
sales of these assets and realized gains totaling $0.4 million.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL RESOURCES
At June 30, 2005, we had borrowed $34.4 million under our credit
facility. Due to the revolving nature of loans under our credit facility,
additional borrowings and periodic repayments and re-borrowings may be made
until the maturity date of June 1, 2008. At June 30, 2005, we had letters of
credit outstanding under our credit facility totaling $9.7 million, comprised of
$4.0 million and $4.9 million for crude oil purchases related to June 2005 and
July 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 June 30, 2005, the borrowing base was
$50.0 million. The total amount available for borrowings at June 30, 2005 was $5
million under the working capital portion and $25.6 million under the
acquisition portion of our credit facility.
We were in compliance with the credit facility covenants at June 30,
2005.
Certain restrictive covenants in the credit facility limit our
ability to make distributions to our unitholders and the general partner. The
credit facility requires we maintain a cash flow coverage ratio of 1.1 to 1.0.
In general, this calculation compares operating cash inflows, as adjusted in
accordance with the credit facility, less maintenance capital expenditures, to
the sum of interest expense and distributions. At June 30, 2005, the calculation
resulted in a ratio of 1.2 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 June 30, 2005, the result of this
calculation was $10.7 million. If we meet these covenants, we are otherwise not
limited in making distributions.
Our average daily outstanding balance under our credit facility
during the first half of 2005 was $15.1 million. The average interest rate we
paid during this same period was 7.26%. The average interest rate on our
outstanding borrowings at June 30, 2005 was 7.27%.
-27-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
CAPITAL EXPENDITURES
A summary of our capital expenditures in the six months ended June
30, 2005 and 2004 is as follows:
Six Months Ended June 30,
-----------------------------
2005 2004
----------- ------------
(in thousands)
Maintenance capital expenditures:
Texas pipeline system................................................. $ 93 $ 86
Mississippi pipeline system........................................... 566 240
Jay pipeline system................................................... 5 9
Crude oil gathering assets............................................ 9 -
Administrative assets................................................. 38 75
----------- ------------
Total maintenance capital expenditures............................. 711 410
Growth capital expenditures:
Mississippi pipeline system........................................... 828 1,069
Natural gas gathering assets.......................................... 3,110 -
T&P Syngas Company investment......................................... 13,505 -
Crude oil gathering assets............................................ 229 -
----------- ------------
Total growth capital expenditures.................................. 17,672 1,069
----------- ------------
Total capital expenditures...................................... $ 18,383 $ 1,479
=========== ============
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 half 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. The investment
in T&P Syngas was made in April 2005. Crude oil gathering assets included a
crude oil gathering pipeline to move oil from a producer's wellhead to a
connection with a third party pipeline.
Although we have no commitments to make capital expenditures, based
on the information available to us at this time, we currently anticipate that
our maintenance capital expenditures for the remainder of 2005 will total to
approximately $1.0 million. These expenditures are expected to relate primarily
to our Mississippi System, including minor facility improvements and
improvements to the pipeline as a result of integrity management test results.
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. In
addition our estimated capital expenditures, we expect to spend $1.6 million in
the remainder of 2005 and $0.2 million in 2006 for pipeline integrity testing
and repairs that will be charged to pipeline operating expense as incurred. As
testing is completed, we are required to take prompt remedial action to address
integrity issues raised by the assessment.
Expenditures for capital assets to grow the partnership distribution
will depend on our access to debt and capital discussed below in "Sources of
Future Capital." We will look for opportunities to acquire assets from other
parties that meet our criteria for stable cash flows such as the two
acquisitions discussed in "Acquisitions in 2005" above.
-28-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
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 June 30, 2005, we had
$34.4 million outstanding under the Credit Facility, and $30.6 million available
for borrowings.
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 and credit
facilities. Our primary uses of cash flows are capital expenditures and
distributions. A summary of our cash flows is as follows:
Six Months Ended June 30,
------------------------------
2005 2004
------------ -------------
(in thousands)
Cash provided by (used in):
Operating activities.................................................. $ (855) $ 5,464
Investing activities.................................................. $ (16,592) $ (1,411)
Financing activities.................................................. $ 16,997 $ (5,190)
Operating. Net cash from operating activities for each period have
been comprised of the following:
Six Months Ended June 30,
------------------------------
2005 2004
------------ -------------
(in thousands)
Net income............................................................ $ 3,513 $ 94
Depreciation and amortization......................................... 3,094 3,174
Gain on sales of assets............................................... (671) (75)
Direct financing leases............................................... 244 -
Equity in T&P Syngas earnings......................................... (252) -
Other non-cash items.................................................. (755) 768
Changes in components of working capital, net......................... (6,028) 1,503
----------- ------------
Net cash from operating activities................................. $ (855) $ 5,464
=========== ============
Our operating cash flows are affected significantly by changes in
items of working capital. Affecting all periods is the timing of capital
expenditures and their effects on our recorded liabilities.
Our accounts receivable settle monthly and collection delays
generally relate only to discrepancies or disputes as to the appropriate price,
volume or quality of crude oil delivered. Of the $90.2 million aggregate
receivables on our consolidated balance sheet at June 30, 2005, approximately
$88.8 million, or 98.4%, were less than 30 days past the invoice date.
Investing. Cash flows used in investing activities in the first half
of 2005 were $16.6 million as compared to $1.4 million in 2004 period. In 2005,
we expended $4.4 million for property additions, including $3.1 million for the
natural gas gathering assets acquired from Multifuels. We made an investment in
T&P Syngas Supply Company utilizing $13.5 million. Offsetting these expenditures
was the receipt of $1.3 million for the sale of idle assets.
In 2004 we expended $1.5 million for property and equipment
additions, and received $0.1 million from the sale of surplus assets. In 2004 we
expended cash for the first phase of an addition to our Mississippi System. We
also expended funds to begin construction of a new tank on the Mississippi
System. We expended cash for other
-29-
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
capital improvements related to our corporate office and to handle the increased
volumes on our Mississippi System more efficiently.
Financing. In the first half of 2005, financing activities provided
net cash of $17.0 million. We increased our borrowings by $19.1 million,
primarily to fund the investment in T&P Syngas and the acquisition of the
natural gas assets. We utilized $2.9 million of cash to make distributions to
our partners.
In the first half of 2004, financing activities utilized net cash of
$5.2 million. Our outstanding debt decreased $1.5 million. Distributions to our
partners utilized $2.9 million. We also incurred $0.8 million of costs related
to our new credit facility.
DISTRIBUTIONS
As a master limited partnership, the key consideration of our
Unitholders is the amount and reliability of our distribution, and our prospects
for distribution increases. We are required by our Partnership Agreement to
distribute 100% of our Available Cash within 45 days after the end of each
quarter to unitholders of record and to our general partner. Available Cash
consists generally of all of our cash receipts less cash disbursements adjusted
for net changes to reserves. Beginning with the distribution for the fourth
quarter of 2003, which was paid in February 2004, we have paid a quarterly
distribution to $0.15 per unit ($1.4 million in total).
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 three and six months ended
June 30, 2005, is as follows:
Three Six
Months Months
Ended Ended
June 30, June 30,
2005 2005
--------- ----------
(in thousands)
AVAILABLE CASH BEFORE RESERVES:
Net income........................................................... $ 743 $ 3,513
Depreciation and amortization........................................ 1,568 3,094
Cash received from direct financing leases not included in income.... 124 244
Cash proceeds in excess of gains on certain asset sales.............. 23 689
Distribution to be received from T&P Syngas in excess of equity
recorded 61 61
Net non-cash (credits) charges....................................... 378 (992)
Maintenance capital expenditures..................................... (200) (711)
--------- ---------
Available Cash before reserves....................................... $ 2,697 $ 5,898
========= =========
Distributions for the three and six month period total $1.4 million
and $2.9 million, respectively.
Available Cash (a non-GAAP liquidity measure) has been reconciled to
cash flow from operating activities (the GAAP measure) for the three and six
months ended June 30, 2005 below.
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GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
NON-GAAP FINANCIAL MEASURE
We believe that investors benefit from having access to the same
financial measures being utilized by management. Available Cash is a liquidity
measure used by our management to compare cash flows generated by us to the cash
distribution we pay to our limited partners and the general partner. This is an
important financial measure to our public unitholders since it is an indicator
of our ability to provide a cash return on their investment. Specifically, this
financial measure tells investors whether or not we are 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 three and six
months ended June 30, 2005, is as follows:
Three Six
Months Months
Ended Ended
June 30, June 30,
2005 2005
---------- ----------
(in thousands)
Cash flows from operating activities ................................. $ (3,394) $ (855)
Adjustments to reconcile operating cash flows to Available Cash:
Maintenance capital expenditures ................................. (200) (711)
Proceeds from sales of certain assets ............................ 41 1,360
Amortization of credit facility issuance fees .................... (94) (187)
Cash effects of stock appreciation rights plan ................... - (50)
Distribution from T&P Syngas for second quarter .................. 313 313
Net effect of changes in working capital accounts not included
in calculation of Available Cash .............................. 6,031 6,028
--------- ---------
Available Cash before reserves ....................................... $ 2,697 $ 5,898
========= =========
COMMITMENTS AND OFF-BALANCE SHEET ARRANGEMENTS
CONTRACTUAL OBLIGATION AND COMMERCIAL COMMITMENTS
In addition to our credit facility discussed above, we have
contractual obligations under operating leases as well as commitments to
purchase crude oil. The table below summarizes our obligations and commitments
at June 30, 2005.
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GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Payments Due by Period
---------------------------------------------------------
Less than 1 - 3 4 - 5 After 5
Contractual Cash Obligations 1 Year Years Years Years Total
- --------------------------------------------- --------- -------- -------- -------- --------
(in thousands)
Long-term Debt .............................. $ - $ 34,400 $ - $ - $ 34,400
Operating Leases ............................ 2,005 2,510 1,434 523 6,472
Interest Payments (1) ....................... 2,516 4,832 - - 7,348
Unconditional Purchase Obligations (2) ...... 155,372 83,347 - - 238,719
--------- -------- -------- -------- --------
Total Contractual Cash Obligations .......... $ 159,893 $125,089 $ 1,434 $ 523 $286,939
========= ======== ======== ======== ========
(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 June 30, 2005 remained outstanding through the maturity
date of June 1, 2008 and interest rates remained at the June 30, 2005
market levels through June 1, 2008. Actual obligations may differ from the
amounts included above.
(2) The unconditional purchase obligations included above are contracts to
purchase crude oil, generally at market-based prices. For purposes of this
table, market prices at June 30, 2005, were used to value the obligations.
Actual obligations may differ from the amounts included above.
OFF-BALANCE SHEET ARRANGEMENTS
We have no off-balance sheet arrangements, special purpose entities,
or financing partnerships, other than as disclosed under Contractual Obligation
and Commercial Commitments above, nor do we have any debt or equity triggers
based upon our unit or commodity prices.
NEW ACCOUNTING PRONOUNCEMENTS
For information on new accounting pronouncements see Note 2 to the
consolidated financial statements.
FORWARD LOOKING STATEMENTS
The statements in this Quarterly Report on Form 10-Q that are not
historical information may be "forward looking statements" within the meaning of
the various provisions of the Securities Act of 1933 and the Securities Exchange
Act of 1934. All statements, other than historical facts, included in this
document that address activities, events or developments that we expect or
anticipate will or may occur in the future, including things such as plans for
growth of the business, future capital expenditures, competitive strengths,
goals, references to future goals or intentions and other such references are
forward-looking statements. These statements include, but are not limited to,
statements identified by the words "anticipate," "continue," "believe,"
"estimate," "expect," "plan," "may," "will," or "intend" or the negative of
those terms and similar expressions and statements regarding our business
strategy, plans and objectives of our management for future operations. We make
these statements based on our experience and our perception of historical
trends, current conditions and expected future developments as well as other
considerations we believe are appropriate under the circumstances.
Forward-looking statements are not guarantees of performance. They involve
risks, uncertainties and assumptions. Future actions, conditions or events and
future results of operations may differ materially from those expressed in these
forward-looking statements. Many of the factors that will determine these
results are beyond our ability to control or predict. Specific factors that
could cause actual results to differ from those in the forward-looking
statements include:
- demand for the supply of, changes in forecast data for, and price
trends related to crude oil, liquid petroleum, natural gas and
natural gas liquids in the United States, all of which may be
affected by economic activity, capital expenditures by energy
producers, weather, alternative energy sources, international
events, conservation and technological advances;
- throughput levels and rates;
- changes in, or challenges to, our tariff rates;
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GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
- 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.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Price Risk Management and Financial Instruments
We may be exposed to market risks primarily related to volatility in crude
oil commodity prices and interest rates.
Our primary price risk relates to the effect of crude oil price
fluctuations on our inventories and the fluctuations each month in grade and
location differentials and their effect on future contractual commitments. We
seek to maintain a position that is substantially balanced between crude oil
purchases and sales and future delivery obligations. We utilize NYMEX commodity
based futures contracts and forward contracts to hedge our exposure to these
market price fluctuations as needed. At June 30, 2005, we had entered into NYMEX
future contracts that will settle by September 2005. These contracts either do
not qualify for hedge accounting or are fair value hedges, therefore the fair
value of these derivatives have received mark-to-market treatment in current
earnings. This accounting treatment is discussed further under Note 2 "Summary
of Significant Accounting Policies" of our Consolidated Financial Statements in
our Annual Report on Form 10-K.
Sell (Short)
Contracts
------------
Futures Contracts
Contract volumes (1,000 bbls)......................... 65
Weighted average price per bbl........................ $ 57.485
Contract value (in thousands)......................... $ 3,737
Mark-to-market change (in thousands).................. 13
-----------
Market settlement value (in thousands)................ $ 3,750
===========
The table above presents notional amounts in barrels, the weighted average
contract price, total contract amount and total fair value amount in U.S.
dollars. Fair values were determined by using the notional amount in barrels
multiplied by the June 30, 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 June 30, 2005. The carrying
value of our debt in our credit facility approximates fair value primarily
because interest rates fluctuate with prevailing market rates, and the credit
spread on outstanding borrowings reflects market.
Expected Year
Of Maturity
2008
(in thousands)
-------------
Long-term debt - variable rate ............................ 34,400
Average interest rate ..................................... 7.27%
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
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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 June 30, 2005,
that have materially affected, or are reasonably likely to materially affect,
our internal controls over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See Part I. Item 1. Note 12 to the Consolidated Financial Statements
entitled "Contingencies", which is incorporated herein by reference.
ITEM 6. EXHIBITS.
(a) Exhibits.
Exhibit 31.1 Certification by Chief Executive Officer Pursuant
to Rule 13a-14(a) under the Securities Exchange Act of 1934.
Exhibit 31.2 Certification by Chief Financial Officer Pursuant
to Rule 13a-14(a) under the Securities Exchange Act of 1934.
Exhibit 32.1 Certification by Chief Executive Officer Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit 32.2 Certification by Chief Financial Officer Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
GENESIS ENERGY, L.P.
(A Delaware Limited Partnership)
By: GENESIS ENERGY, INC., as
General Partner
Date: August 9, 2005 By: /s/ ROSS A. BENAVIDES
------------------------------------
Ross A. Benavides
Chief Financial Officer
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Exhibit Index
Exhibit 31.1 Certification by Chief Executive Officer Pursuant to Rule 13a-14(a)
under the Securities Exchange Act of 1934.
Exhibit 31.2 Certification by Chief Financial Officer Pursuant to Rule 13a-14(a)
under the Securities Exchange Act of 1934.
Exhibit 32.1 Certification by Chief Executive Officer Pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002.
Exhibit 32.2 Certification by Chief Financial Officer Pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002.
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