UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington,
D.C. 20549
Form
10-Q
T QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
For the
quarterly period ended September 30, 2008
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 jurisdictions of incorporation or
organization)
|
|
(I.R.S.
Employer Identification No.)
|
|
|
|
919
Milam, Suite 2100, Houston, TX
|
|
77002
|
(Address
of principal executive offices)
|
|
(Zip
code)
|
Registrant's
telephone number, including area code:
|
|
(713)
860-2500
|
Securities
registered pursuant to Section 12(g) of the Act:
NONE
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 þ No £
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,”
“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act.
Large
accelerated filer £
|
Accelerated
filer þ
|
Non-accelerated
filer £
|
Smaller
reporting company £
|
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2) of the Exchange Act).
Yes £ No
þ
Indicate
the number of shares outstanding of each of the issuer’s classes of common
stock, as of the latest practicable date. Common Units outstanding as
of November 6, 2008: 39,452,305
Form
10-Q
INDEX
PART
I. FINANCIAL INFORMATION
Item
1.
|
Financial
Statements
|
Page
|
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3
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4
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5
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6
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7
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Item
2.
|
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32
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Item
3.
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49
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Item
4.
|
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51
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PART
II. OTHER INFORMATION
|
|
Item
1.
|
|
51
|
|
|
|
Item
1A.
|
|
51
|
|
|
|
Item
2.
|
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52
|
|
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|
Item
3.
|
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53
|
|
|
|
Item
4.
|
|
53
|
|
|
|
Item
5.
|
|
53
|
|
|
|
Item
6.
|
|
53
|
|
|
|
|
|
|
|
54
|
UNAUDITED
CONSOLIDATED BALANCE SHEETS
(In
thousands)
|
|
September 30,
2008
|
|
|
December 31,
2007
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
22,371 |
|
|
$ |
11,851 |
|
Accounts
receivable - trade
|
|
|
194,637 |
|
|
|
178,658 |
|
Accounts
receivable - related party
|
|
|
7,494 |
|
|
|
1,441 |
|
Inventories
|
|
|
23,144 |
|
|
|
15,988 |
|
Net
investment in direct financing leases, net of unearned income - current
portion - related party
|
|
|
3,699 |
|
|
|
609 |
|
Other
|
|
|
9,841 |
|
|
|
5,693 |
|
Total
current assets
|
|
|
261,186 |
|
|
|
214,240 |
|
|
|
|
|
|
|
|
|
|
FIXED
ASSETS, at cost
|
|
|
339,837 |
|
|
|
150,413 |
|
Less: Accumulated
depreciation
|
|
|
(60,194 |
) |
|
|
(48,413 |
) |
Net
fixed assets
|
|
|
279,643 |
|
|
|
102,000 |
|
|
|
|
|
|
|
|
|
|
NET
INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income - related
party
|
|
|
178,169 |
|
|
|
4,764 |
|
CO2
ASSETS, net of amortization
|
|
|
25,479 |
|
|
|
28,916 |
|
EQUITY
INVESTEES AND OTHER INVESTMENTS
|
|
|
19,376 |
|
|
|
18,448 |
|
INTANGIBLE
ASSETS, net of amortization
|
|
|
178,510 |
|
|
|
211,050 |
|
GOODWILL
|
|
|
325,046 |
|
|
|
320,708 |
|
OTHER
ASSETS, net of amortization
|
|
|
14,055 |
|
|
|
8,397 |
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
1,281,464 |
|
|
$ |
908,523 |
|
|
|
|
|
|
|
|
|
|
LIABILITIES
AND PARTNERS' CAPITAL
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Current
Maturities of long - term debt
|
|
$ |
48,200 |
|
|
|
|
|
Accounts
payable - trade
|
|
|
169,073 |
|
|
$ |
154,614 |
|
Accounts
payable - related party
|
|
|
3,200 |
|
|
|
2,647 |
|
Accrued
liabilities
|
|
|
34,558 |
|
|
|
17,537 |
|
Total
current liabilities
|
|
|
255,031 |
|
|
|
174,798 |
|
|
|
|
|
|
|
|
|
|
LONG-TERM
DEBT
|
|
|
343,200 |
|
|
|
80,000 |
|
DEFERRED
TAX LIABILITIES
|
|
|
15,767 |
|
|
|
20,087 |
|
OTHER
LONG-TERM LIABILITIES
|
|
|
1,527 |
|
|
|
1,264 |
|
MINORITY
INTERESTS
|
|
|
25,817 |
|
|
|
570 |
|
COMMITMENTS
AND CONTINGENCIES (Note 16)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PARTNERS'
CAPITAL:
|
|
|
|
|
|
|
|
|
Common
unitholders, 39,452 and 38,253 units, respectively, issued and
outstanding
|
|
|
623,432 |
|
|
|
615,265 |
|
General
partner
|
|
|
16,796 |
|
|
|
16,539 |
|
Accumulated
other comprehensive loss
|
|
|
(106 |
) |
|
|
- |
|
Total
partners' capital
|
|
|
640,122 |
|
|
|
631,804 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND PARTNERS' CAPITAL
|
|
$ |
1,281,464 |
|
|
$ |
908,523 |
|
The
accompanying notes are an integral part of these consolidated financial
statements.
UNAUDITED
CONSOLIDATED STATEMENTS OF OPERATIONS
(In
thousands, except per unit amounts)
|
|
Three Months Ended
September 30,
|
|
|
Nine Months Ended
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply
and logistics:
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrelated
parties
|
|
$ |
554,838 |
|
|
$ |
317,244 |
|
|
$ |
1,552,559 |
|
|
$ |
680,380 |
|
Related
parties
|
|
|
1,558 |
|
|
|
409 |
|
|
|
3,432 |
|
|
|
1,287 |
|
Refinery
services
|
|
|
61,306 |
|
|
|
25,349 |
|
|
|
160,945 |
|
|
|
25,349 |
|
Pipeline
transportation, including natural gas sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation
services - unrelated parties
|
|
|
5,062 |
|
|
|
4,596 |
|
|
|
16,139 |
|
|
|
12,519 |
|
Transportation
services - related parties
|
|
|
8,205 |
|
|
|
1,499 |
|
|
|
13,372 |
|
|
|
4,225 |
|
Natural
gas sales revenues
|
|
|
1,158 |
|
|
|
800 |
|
|
|
4,085 |
|
|
|
3,274 |
|
CO2
marketing revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrelated
parties
|
|
|
4,039 |
|
|
|
3,610 |
|
|
|
10,895 |
|
|
|
9,772 |
|
Related
parties
|
|
|
753 |
|
|
|
763 |
|
|
|
2,217 |
|
|
|
2,044 |
|
Total
revenues
|
|
|
636,919 |
|
|
|
354,270 |
|
|
|
1,763,644 |
|
|
|
738,850 |
|
COSTS
AND EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply
and logistics costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product
costs - unrelated parties
|
|
|
521,779 |
|
|
|
304,089 |
|
|
|
1,471,254 |
|
|
|
656,317 |
|
Product
costs - related parties
|
|
|
- |
|
|
|
40 |
|
|
|
- |
|
|
|
69 |
|
Operating
costs
|
|
|
20,927 |
|
|
|
8,564 |
|
|
|
55,294 |
|
|
|
17,295 |
|
Refinery
services operating costs
|
|
|
48,265 |
|
|
|
16,804 |
|
|
|
116,700 |
|
|
|
16,804 |
|
Pipeline
transportation costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline
transportation operating costs
|
|
|
2,647 |
|
|
|
2,315 |
|
|
|
7,493 |
|
|
|
7,996 |
|
Natural
gas purchases
|
|
|
1,136 |
|
|
|
817 |
|
|
|
3,990 |
|
|
|
3,164 |
|
CO2
marketing costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation
costs - related party
|
|
|
1,488 |
|
|
|
1,462 |
|
|
|
4,121 |
|
|
|
3,796 |
|
Other
costs
|
|
|
15 |
|
|
|
40 |
|
|
|
45 |
|
|
|
131 |
|
General
and administrative
|
|
|
9,239 |
|
|
|
4,724 |
|
|
|
26,929 |
|
|
|
13,652 |
|
Depreciation
and amortization
|
|
|
18,100 |
|
|
|
8,372 |
|
|
|
51,610 |
|
|
|
12,346 |
|
Net
(gain) loss on disposal of surplus assets
|
|
|
(58 |
) |
|
|
- |
|
|
|
36 |
|
|
|
(24 |
) |
Total
costs and expenses
|
|
|
623,538 |
|
|
|
347,227 |
|
|
|
1,737,472 |
|
|
|
731,546 |
|
OPERATING
INCOME
|
|
|
13,381 |
|
|
|
7,043 |
|
|
|
26,172 |
|
|
|
7,304 |
|
Equity
in earnings of joint ventures
|
|
|
216 |
|
|
|
361 |
|
|
|
378 |
|
|
|
915 |
|
Interest
income
|
|
|
118 |
|
|
|
141 |
|
|
|
352 |
|
|
|
219 |
|
Interest
expense
|
|
|
(4,601 |
) |
|
|
(4,842 |
) |
|
|
(8,543 |
) |
|
|
(5,467 |
) |
INCOME
BEFORE INCOME TAXES AND MINORITY INTEREST
|
|
|
9,114 |
|
|
|
2,703 |
|
|
|
18,359 |
|
|
|
2,971 |
|
Income
tax benefit (expense)
|
|
|
1,504 |
|
|
|
(1,004 |
) |
|
|
1,233 |
|
|
|
(1,059 |
) |
Income
before minority interest
|
|
|
10,618 |
|
|
|
1,699 |
|
|
|
19,592 |
|
|
|
1,912 |
|
Minority
interest
|
|
|
145 |
|
|
|
- |
|
|
|
144 |
|
|
|
- |
|
NET
INCOME
|
|
$ |
10,763 |
|
|
$ |
1,699 |
|
|
$ |
19,736 |
|
|
$ |
1,912 |
|
GENESIS
ENERGY, L.P.
UNAUDITED
CONSOLIDATED STATEMENTS OF OPERATIONS - CONTINUED
(In
thousands, except per unit amounts)
|
|
Three Months Ended
September 30,
|
|
|
Nine Months Ended
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
NET
INCOME PER COMMON UNIT:
|
|
|
|
|
|
|
|
|
|
|
|
|
BASIC
|
|
$ |
0.25 |
|
|
$ |
0.07 |
|
|
$ |
0.47 |
|
|
$ |
0.11 |
|
DILUTED
|
|
$ |
0.25 |
|
|
$ |
0.07 |
|
|
$ |
0.46 |
|
|
$ |
0.11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE COMMON UNITS OUTSTANDING:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BASIC
|
|
|
39,452 |
|
|
|
24,527 |
|
|
|
38,796 |
|
|
|
17,405 |
|
DILUTED
|
|
|
39,524 |
|
|
|
24,527 |
|
|
|
38,853 |
|
|
|
17,405 |
|
The
accompanying notes are an integral part of these consolidated financial
statements.
UNAUDITED
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
(In
thousands)
|
|
Partners'
Capital
|
|
|
|
Number of Common Units
|
|
|
Common Unitholders
|
|
|
General Partner
|
|
|
Accumulated Other
Comprehensive Loss
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners'
capital, January 1, 2008
|
|
|
38,253 |
|
|
$ |
615,265 |
|
|
$ |
16,539 |
|
|
$ |
- |
|
|
$ |
631,804 |
|
Net
income
|
|
|
- |
|
|
|
17,972 |
|
|
|
1,764 |
|
|
|
- |
|
|
|
19,736 |
|
Cash
contributions
|
|
|
- |
|
|
|
- |
|
|
|
510 |
|
|
|
- |
|
|
|
510 |
|
Cash
distributions
|
|
|
- |
|
|
|
(34,805 |
) |
|
|
(2,017 |
) |
|
|
- |
|
|
|
(36,822 |
) |
Issuance
of units
|
|
|
2,037 |
|
|
|
41,667 |
|
|
|
- |
|
|
|
- |
|
|
|
41,667 |
|
Redemption
of units
|
|
|
(838 |
) |
|
|
(16,667 |
) |
|
|
- |
|
|
|
- |
|
|
|
(16,667 |
) |
Interest
rate swap hedges
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(106 |
) |
|
|
(106 |
) |
Partners'
capital, September 30, 2008
|
|
|
39,452 |
|
|
$ |
623,432 |
|
|
$ |
16,796 |
|
|
$ |
(106 |
) |
|
$ |
640,122 |
|
The
accompanying notes are an integral part of these consolidated financial
statements.
UNAUDITED
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In
thousands)
|
|
Nine
Months Ended September 30,
|
|
|
|
2008
|
|
|
2007
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
19,736 |
|
|
$ |
1,912 |
|
Adjustments
to reconcile net income to net cash provided by operating activities
-
|
|
|
|
|
|
|
|
|
Depreciation
and amortization
|
|
|
51,610 |
|
|
|
12,346 |
|
Amortization
of credit facility issuance costs
|
|
|
962 |
|
|
|
509 |
|
Amortization
of unearned income and initial direct costs on direct financing
leases
|
|
|
(6,342 |
) |
|
|
(468 |
) |
Payments
received under direct financing leases
|
|
|
6,056 |
|
|
|
890 |
|
Equity
in earnings of investments in joint ventures
|
|
|
(378 |
) |
|
|
(915 |
) |
Distributions
from joint ventures - return on investment
|
|
|
971 |
|
|
|
1,276 |
|
Non-cash
effects of unit-based compensation plans
|
|
|
(1,342 |
) |
|
|
1,696 |
|
Deferred
and other tax liabilities
|
|
|
(3,388 |
) |
|
|
- |
|
Other
non-cash items
|
|
|
(1,175 |
) |
|
|
643 |
|
Changes
in components of operating assets and liabilities -
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
(23,670 |
) |
|
|
(9,749 |
) |
Inventories
|
|
|
(6,481 |
) |
|
|
3,810 |
|
Other
current assets
|
|
|
(3,214 |
) |
|
|
(515 |
) |
Accounts
payable
|
|
|
17,076 |
|
|
|
10,819 |
|
Accrued
liabilities
|
|
|
5,809 |
|
|
|
3,399 |
|
Net
cash provided by operating activities
|
|
|
56,230 |
|
|
|
25,653 |
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Payments
to acquire fixed assets
|
|
|
(29,890 |
) |
|
|
(3,292 |
) |
CO2
pipeline transactions and related costs
|
|
|
(228,891 |
) |
|
|
- |
|
Distributions
from joint ventures - return of investment
|
|
|
886 |
|
|
|
389 |
|
Investment
in joint ventures and other investments
|
|
|
(2,210 |
) |
|
|
(552 |
) |
Proceeds
from disposal of assets
|
|
|
573 |
|
|
|
195 |
|
Acquisition
of Grifco assets
|
|
|
(65,693 |
) |
|
|
- |
|
Acquisition
of Davison assets, net of cash acquired
|
|
|
(993 |
) |
|
|
(301,360 |
) |
Acquisition
of Port Hudson assets
|
|
|
- |
|
|
|
(8,103 |
) |
Other,
net
|
|
|
207 |
|
|
|
(1,300 |
) |
Net
cash used in investing activities
|
|
|
(326,011 |
) |
|
|
(314,023 |
) |
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Bank
borrowings
|
|
|
490,900 |
|
|
|
355,800 |
|
Bank
repayments
|
|
|
(179,500 |
) |
|
|
(78,800 |
) |
Credit
facility issuance fees
|
|
|
(2,255 |
) |
|
|
(2,297 |
) |
Issuance
of common units for cash
|
|
|
- |
|
|
|
22,361 |
|
Redemption
of common units for cash
|
|
|
(16,667 |
) |
|
|
- |
|
General
partner contributions
|
|
|
510 |
|
|
|
6,171 |
|
Minority
interest contributions, net of distributions
|
|
|
25,501 |
|
|
|
30 |
|
Distributions
to common unitholders
|
|
|
(34,805 |
) |
|
|
(9,097 |
) |
Distributions
to general partner interest
|
|
|
(2,017 |
) |
|
|
(186 |
) |
Other,
net
|
|
|
(1,366 |
) |
|
|
(163 |
) |
Net
cash provided by financing activities
|
|
|
280,301 |
|
|
|
293,819 |
|
|
|
|
|
|
|
|
|
|
Net
increase in cash and cash equivalents
|
|
|
10,520 |
|
|
|
5,449 |
|
Cash
and cash equivalents at beginning of period
|
|
|
11,851 |
|
|
|
2,318 |
|
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents at end of period
|
|
$ |
22,371 |
|
|
$ |
7,767 |
|
The
accompanying notes are an integral part of these consolidated financial
statements.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
1. Organization
and Basis of Presentation and Consolidation
Organization
We are a
growth-oriented limited partnership focused on the midstream segment of the oil
and gas industry in the Gulf Coast area of the United States. We
conduct our operations through our operating subsidiaries and joint
ventures. We manage our businesses through four
divisions:
|
·
|
Pipeline
transportation of crude oil, carbon dioxide (or CO2)
and, to a lesser degree, natural
gas;
|
|
·
|
Refinery
services involving processing of high sulfur (or “sour”) gas streams for
refineries to remove the sulfur, and sale of the related by-product,
sodium hydrosulfide (or NaHS, commonly pronounced
nash);
|
|
·
|
Industrial
gas activities, including wholesale marketing of CO2 and
processing of syngas through a joint venture;
and
|
|
·
|
Supply
and logistics services, which includes terminaling, blending, storing,
marketing, and transporting by trucks and barge of crude oil and petroleum
products as well as dry goods.
|
Our 2%
general partner interest is held by Genesis Energy, Inc., a Delaware corporation
and an indirect, wholly-owned subsidiary of Denbury Resources
Inc. Denbury and its subsidiaries are hereafter referred to as
Denbury. Our general partner and its affiliates also own 10.2% of our
outstanding common units.
Our
general partner manages our operations and activities and employs our officers
and personnel, who devote 100% of their efforts to our management.
Basis
of Presentation and Consolidation
Accounting
measurements at interim dates inherently involve greater reliance on estimates
than at year end and the results of operations for the interim periods shown in
this report are not necessarily indicative of results to be expected for the
fiscal year. The consolidated 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)
that 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 when read in
conjunction with the information contained in the periodic reports we file with
the SEC pursuant to the Securities Exchange Act of 1934, including the
consolidated financial statements and notes thereto included in our Annual
Report on Form 10-K for the year ended December 31, 2007.
Except
per unit amounts, or as noted within the context of each footnote disclosure,
the dollar amounts presented in the tabular data within these footnote
disclosures are stated in thousands of dollars.
The
accompanying unaudited consolidated financial statements and related notes
present our consolidated financial position as of September 30, 2008 and
December 31, 2007 and our results of operations for the three and nine months
ended September 30, 2008 and 2007, our cash flows for the nine months ended
September 30, 2008 and 2007 and changes in partners’ capital for the nine months
ended September 30, 2008. Intercompany transactions have been
eliminated. The accompanying unaudited consolidated financial
statements include Genesis Energy, L.P. and its operating subsidiaries, Genesis
Crude Oil, L.P. and Genesis NEJD Holdings, LLC, and their
subsidiaries.
Joint
Ventures
We
participate in three joint ventures: DG Marine, T&P Syngas Supply
Company (T&P Syngas) and Sandhill Group, LLC (Sandhill). As of
July 2008, DG Marine is consolidated in our financial statements. We
account for our 50% investments in T&P Syngas and Sandhill by the equity
method of accounting. See Note 8.
DG Marine
Transportation, LLC
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
In July
2008, we acquired the inland marine transportation business of Grifco
Transportation, Ltd and two of its affiliates through a joint venture (DG
Marine) with TD Marine, LLC, an entity owned by the Davison
family. We own a 49% economic interest and TD Marine, LLC owns a 51%
economic interest in DG Marine. TD Marine, LLC controls the DG Marine
joint venture and the day-to-day operations are conducted by and managed by DG
Marine employees. The provisions of Financial Interpretation No.
46(R) “Consolidation of Variable Interest Entities” (FIN 46R), require us to
consolidate DG Marine in our consolidated financial statements. See
Note 3.
T&P
Syngas Supply Company
We
own a 50% interest in T&P Syngas Supply Company (“T&P Syngas”), a
Delaware general partnership. Praxair Hydrogen Supply Inc.
(“Praxair”) owns the remaining 50% partnership interest in T&P
Syngas. T&P Syngas is a partnership that owns a syngas
manufacturing facility located in Texas City, Texas. That facility
processes natural gas to produce syngas (a combination of carbon monoxide and
hydrogen) and high pressure steam. Praxair provides the raw materials
to be processed and receives the syngas and steam produced by the facility under
a long-term processing agreement. T&P Syngas receives a
processing fee for its services. Praxair operates the
facility.
Sandhill
Group, LLC
We own a
50% interest in Sandhill Group, LLC (“Sandhill”). At September 30,
2008, Reliant Processing Ltd. held the other 50% interest in
Sandhill. Sandhill owns a CO2 processing
facility located in Brandon, Mississippi. Sandhill is engaged in the production
and distribution of liquid carbon dioxide for use in the food, beverage,
chemical and oil industries. The facility acquires CO2 from us
under a long-term supply contract that we acquired in 2005 from
Denbury.
Our
general partner owns a 0.01% general partner interest in Genesis Crude Oil, L.P.
and TD Marine, LLC, a related party, owns the remaining 51% economic interest in
DG Marine. The net interest of those parties in our results of
operations and financial position are reflected in our financial statements as
minority interests.
In July
2007, we acquired the energy-related businesses of the Davison
family. The results of the operations of these businesses have been
included in our consolidated financial statements since August 1,
2007.
2. Recent
Accounting Developments
Implemented
SFAS
157
We
adopted Statement of Financial Accounting Standards (SFAS) No. 157,
“Fair Value Measurements” (SFAS 157), with respect to financial assets and
financial liabilities that are regularly adjusted to fair value, as of January
1, 2008. SFAS 157 provides a common fair value hierarchy to follow in
determining fair value measurements in the preparation of financial statements
and expands disclosure requirements relating to how such measurements were
developed. SFAS 157 does not require any new fair value measurements, but rather
applies to all other accounting pronouncements that require or permit fair value
measurements. On February 12, 2008 the Financial Accounting
Standards Board (FASB) issued Staff Position No. 157-2, “Effective Date of FASB
Statement No. 157” (FSP 157-2) which amends SFAS 157 to delay the effective
date for all non-financial assets and non-financial liabilities, except for
those that are recognized at fair value in the financial statements on a
recurring basis. The partial adoption of SFAS 157 as described above
had no material impact on us. We have not yet determined the impact,
if any, that the second phase of the adoption of SFAS 157 in 2009 will have
relating to its fair value measurements of non-financial assets and
non-financial liabilities. See Note 18 for further information
regarding fair-value measurements.
SFAS
159
In
February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for
Financial Assets and Financial Liabilities” (SFAS 159). This
statement became effective for us as of January 1, 2008. SFAS 159 permits
entities to choose to measure many financial instruments and certain other items
at fair value that are not currently required to be measured at fair value. We
did not elect to utilize voluntary fair value measurements as permitted by the
standard.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Pending
SFAS
141(R)
In
December 2007, the FASB issued SFAS No. 141(R) “Business Combinations” (SFAS
141(R)). SFAS 141(R) replaces FASB Statement No. 141, “Business
Combinations.” This statement retains the purchase method of
accounting used in business combinations but replaces SFAS 141 by establishing
principles and requirements for the recognition and measurement of assets,
liabilities and goodwill, including the requirement that most transaction costs
and restructuring costs be charged to expense as incurred. In
addition, the statement requires disclosures to enable users of the financial
statements to evaluate the nature and financial effects of the business
combination. SFAS 141(R) is effective for business combinations for
which the acquisition date is on or after the beginning of the first annual
reporting period beginning on or after December 15, 2008. SFAS 141(R)
will apply to acquisitions we make after December 31, 2008. The
impact to us will be dependent on the nature of the business
combination.
SFAS
160
In
December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in
Consolidated Financial Statements - an amendment of ARB No. 51” (SFAS 160). This
statement establishes accounting and reporting standards for noncontrolling
interests, which have been referred to as minority interests in prior
literature. A noncontrolling interest is the portion of equity in a
subsidiary not attributable, directly or indirectly, to a parent
company. This new standard requires, among other things, that (i)
ownership interests of noncontrolling interests be presented as a component of
equity on the balance sheet (i.e. elimination of the mezzanine “minority
interest” category); (ii) elimination of minority interest expense as a line
item on the statement of operations and, as a result, that net income be
allocated between the parent and the noncontrolling interests on the face of the
statement of operations; and (iii) enhanced disclosures regarding noncontrolling
interests. SFAS 160 is effective for fiscal years beginning after
December 15, 2008. We will adopt SFAS 160 on January 1,
2009. We are assessing the impact of this statement on our financial
statements and expect it to impact the presentation of the minority interests in
Genesis Crude Oil, L.P. held by our general partner and DG Marine held by our
joint venture partner.
SFAS
161
In
March 2008, the FASB issued SFAS No. 161, “Disclosures about
Derivative Instruments and Hedging Activities-an amendment of FASB Statement
No.133” (SFAS 161). This Statement requires enhanced disclosures about our
derivative and hedging activities. This statement is effective for financial
statements issued for fiscal years and interim periods beginning after
November 15, 2008. We will adopt SFAS No. 161 beginning
January 1, 2009. We are currently evaluating the impact, if any, that the
standard will have on the disclosures in our consolidated financial
statements.
EITF
07-4
In March
2008, the FASB ratified the consensus reached by the Emerging Issues Task Force
(or EITF) of the FASB in issue EITF 07-4, “Application of the Two-Class Method
under FASB Statement No. 128, Earnings per Share, to Master
Limited Partnerships.” Under this consensus, the computation of
earnings per unit will be affected by the incentive distribution rights (“IDRs”)
we are contractually obligated to distribute at the end of the current reporting
period. In periods when earnings are in excess of cash distributions,
we will reduce net income or loss for the current reporting period (for purposes
of calculating earnings or loss per unit) by the amount of available cash that
will be distributed to our limited partners and general partner for its general
partner interest and incentive distribution rights for the reporting period, and
the remainder will be allocated to the limited partner and general partner in
accordance with their ownership interests. When cash distributions
exceed current-period earnings, net income or loss (for purposes of calculating
earnings or loss per unit) will be reduced (or increased) by cash distributions,
and the resulting excess of distributions over earnings will be allocated to the
general partner and limited partner based on their respective sharing of
losses. EITF 07-4 is effective for fiscal years beginning after
December 15, 2008, and interim periods within those fiscal years. We
are currently evaluating the impact of EITF 07-4; however we expect it to have
an impact on our presentation of earnings per unit beginning in
2009. For additional information on our incentive distribution
rights, see Note 10.
FASB
Staff Position No. 142-3
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
In April
2008, the FASB issued FASB Staff Position No. 142-3, “Determination of the
Useful Life of Intangible Assets” (FSP 142-3). This FSP amends the
factors that should be considered in developing renewal or extension assumptions
used to determine the useful life of an intangible asset under Statement of
Financial Accounting Standards No. 142, “Goodwill and other Intangible Assets.”
The purpose of this FSP is to develop consistency between the useful life
assigned to intangible assets and the cash flows from those
assets. FSP 142-3 is effective for fiscal years beginning after
December 31, 2008. We are currently evaluating the impact, if any,
that the standard will have on our consolidated financial
statements.
3. Acquisitions
DG
Marine Transportation Investment
On July
18, 2008, we completed the acquisition of the inland marine transportation
business of Grifco Transportation, Ltd. (“Grifco”) and two of Grifco’s
affiliates through a joint venture with TD Marine, LLC, an entity formed by
members of the Davison family. (See discussion below on the
acquisition of the Davison family businesses in 2007.). TD Marine owns
(indirectly) a 51% economic interest in the joint venture, DG Marine,
and we own (directly and indirectly) a 49% economic interest. This
acquisition gives us the capability to provide transportation services of
petroleum products by barge and complements our other supply and logistics
operations.
Grifco
received initial purchase consideration of approximately $80 million, comprised
of $63.3 million in cash and $16.7 million, or 837,690 of our common
units. A portion of the units are subject to certain lock-up
restrictions. DG Marine acquired substantially all of Grifco’s assets, including
twelve barges, seven push boats, certain commercial agreements, and offices
.. Additionally, DG Marine and/or its subsidiaries acquired
the rights, and assumed the obligations, to take delivery of four new barges in
late third quarter of 2008 and four additional new barges early in first quarter
of 2009 (at a total price of approximately $27 million). Upon delivery of the
eight new barges, the acquisition of three additional push boats (at an
estimated cost of approximately $6 million), and after placing the barges and
push boats into commercial operations, DG Marine will be obligated to pay
additional purchase consideration of up to $12 million. The
estimated discounted present value of that $12 million obligation is included in
current liabilities in our consolidated balance sheets. At September
30, 2008, DG Marine had taken delivery of four of the new barges.
The
Grifco acquisition and related closing costs were funded with $50 million of
aggregate equity contributions from us and TD Marine, in proportion to our
ownership percentages, and with borrowings of $32.4 million under a revolving
credit facility which is non-recourse to us and TD Marine (other than with
respect to our investments in DG Marine). Although DG
Marine’s debt is non-recourse to us, our ownership interest in DG Marine is
pledged to secure its indebtedness. We funded our $24.5 million equity
contribution with $7.8 million of cash and 837,690 of our common units, valued
at $19.896 per unit, for a total value of $16.7 million. At closing,
we also redeemed 837,690 of our common units from the Davison
family. See Notes 9 and 10.
We have
entered into a subordinated loan agreement with DG Marine whereby we may (at our
sole discretion) lend up to $25 million to DG Marine. The loan
agreement provides for DG Marine to pay us interest on any loans at the rate at
which we borrowed funds under our credit facility plus 4%. Those
loans will mature on January 31, 2012. Under that subordinated loan
agreement, DG Marine is required to make monthly payments to us of principal and
interest to the extent DG Marine has any available cash that otherwise would
have been distributed to the owners of DG Marine in respect of their equity
interest. DG Marine’s revolving credit facility includes restrictions
on DG Marine’s ability to make specified payments under the subordinated loan
agreement and distributions in respect of our equity interest. At
September 30, 2008, there were no amounts outstanding under the subordinated
loan agreement.
The
provisions of Financial Interpretation No. 46(R) “Consolidation of Variable
Interest Entities” (FIN 46R), require us to consolidate DG Marine in our
consolidated financial statements. The 51% ownership interest of TD
Marine in the net assets and net income of DG Marine is included in minority
interests in our consolidated financial statements.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
The
acquisition cost allocated to the assets consists of $63.3 million of cash,
$16.7 million of value from the issuance of our limited partnership units to
Grifco, $11.7 million related to the discounted value of the additional
consideration that will be owed to Grifco when the barges under construction are
placed in service and $2.4 million of transaction costs. The
acquisition cost has been allocated to the assets acquired based on estimated
preliminary fair values. Such preliminary values have been developed
by management. The preliminary valuation may change as a result of additional
information we have requested on certain tangible and intangible
assets. We expect to finalize the allocation for this transaction
during the fourth quarter of 2008. We do not expect any material
adjustments to these preliminary purchase price allocations as a result of the
final valuation.
The
preliminary allocation of the acquisition cost is summarized as
follows:
Fuel
inventory in vessels
|
|
$ |
676 |
|
Property
and equipment
|
|
|
91,096 |
|
Amortizable
intangible assets:
|
|
|
|
|
Customer
relationships
|
|
|
800 |
|
Trade
name
|
|
|
900 |
|
Non-compete
agreements
|
|
|
600 |
|
Total
allocated cost
|
|
$ |
94,072 |
|
See
additional information on intangible assets and goodwill in Note 7.
2008
Denbury Drop-Down Transactions
On May
30, 2008, we completed two “drop-down” transactions with Denbury Onshore LLC,
(Denbury Onshore), a wholly-owned subsidiary of Denbury Resources Inc., the
indirect owner of our general partner.
NEJD
Pipeline System
We
entered into a twenty-year financing lease transaction with Denbury Onshore and
acquired certain security interests in Denbury’s North East Jackson Dome (NEJD)
Pipeline System for which we paid $175 million. Under the terms of
the agreement, Denbury Onshore began making quarterly rent payments beginning
August 30, 2008. These quarterly rent payments are fixed at
$5,166,943 per quarter or approximately $20.7 million per year during the lease
term at an interest rate of 10.25%. At the end of the lease term, we
will convey all of our interests in the NEJD Pipeline to Denbury Onshore for a
nominal payment.
The NEJD
Pipeline System is a 183-mile, 20” CO2 pipeline
extending from the Jackson Dome, near Jackson, Mississippi, to near Donaldson,
Louisiana, currently being used by Denbury for its tertiary operations in
southwest Mississippi. Denbury has the rights to exclusive use of the
NEJD Pipeline System, will be responsible for all operations and maintenance on
that system, and will bear and assume all obligations and liabilities with
respect to that system. The NEJD transaction was funded with
borrowings under our credit facility.
See
additional discussion of this direct financing lease in Note 6.
Free
State Pipeline System
We
purchased Denbury’s Free State Pipeline for $75 million, consisting of $50
million in cash, which we borrowed under our credit facility, and $25 million in
the form of 1,199,041 of our common units. The number of common units
issued was based on the average closing price of our common units from May 28,
2008 through June 3, 2008.
The Free
State Pipeline is an 86-mile, 20” pipeline that extends from Denbury’s CO2 source
fields at Jackson Dome, near Jackson, Mississippi, to Denbury’s oil fields in
east Mississippi. We entered into a twenty-year transportation
services agreement to deliver CO2 on the
Free State pipeline for Denbury’s use in its tertiary recovery
operations. Under the terms of the transportation
services agreement, we are responsible for owning, operating, maintaining and
making improvements to that pipeline. Denbury has rights to exclusive
use of that pipeline and is required to use that pipeline to supply CO2 to its
current and certain of its other tertiary operations in east
Mississippi. The transportation services agreement provides for a
$100,000 per month minimum payment, which is accounted for as an operating
lease, plus a tariff based on throughput. Denbury has two renewal options, each
for five years on similar terms. Any sale by us of the Free State Pipeline and
related assets or of an ownership interest in our subsidiary that holds such
assets would be subject to a right of first refusal purchase option in favor of
Denbury.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
2007
Davison Businesses Acquisition
On July
25, 2007, we acquired five energy-related businesses from several entities owned
and controlled by the Davison family of Ruston, Louisiana (the “Davison
Acquisition”) for total consideration of $623 million (including cash and common
units), net of cash acquired and direct transaction costs totaling $8.9
million. The businesses include the operations that comprise our
refinery services division, and other operations included in our supply and
logistics division, which transport, store, procure, and market petroleum
products and other bulk commodities. The assets acquired in this
transaction provide us with opportunities to expand our services to energy
companies in the areas in which we operate.
In
connection with the finalization of our valuation procedures with respect to
certain fixed assets acquired in the Davison Acquisition, we reallocated $3.3
million of the purchase price from fixed assets to goodwill. In
addition, the purchase price was adjusted by $1.0 million during the first half
of 2008 for differences in working capital and fixed assets
acquired. See additional information on intangible assets and
goodwill in Note 7.
2007
Port Hudson Assets Acquisition
Effective
July 1, 2007, we paid $8.1 million for BP Pipelines (North America) Inc.’s Port
Hudson crude oil truck terminal, marine terminal, and marine dock on the
Mississippi River, which includes 215,000 barrels of tankage, a pipeline and
other related assets in East Baton Rouge Parish, Louisiana. The
purchase price was allocated to the assets acquired based on estimated fair
values. See additional information on goodwill in Note
7.
4. Inventories
Inventories
are valued at the lower of cost or market. The costs of inventories
at September 30, 2008 exceeded market values by approximately $0.1 million, and
are reflected below at those market values. The costs of inventories did not
exceed market values at December 31, 2007. The major components of
inventories were as follows:
|
|
September
30, 2008
|
|
|
December
31, 2007
|
|
|
|
|
|
|
|
|
Crude
oil
|
|
$ |
2,018 |
|
|
$ |
3,710 |
|
Petroleum
products
|
|
|
13,150 |
|
|
|
6,527 |
|
Caustic
soda
|
|
|
1,827 |
|
|
|
1,998 |
|
NaHS
|
|
|
6,013 |
|
|
|
3,557 |
|
Other
|
|
|
136 |
|
|
|
196 |
|
Total
inventories
|
|
$ |
23,144 |
|
|
$ |
15,988 |
|
\
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
5. Fixed
Assets and Asset Retirement Obligations
Fixed
assets consisted of the following:
|
|
September
30, 2008
|
|
|
December
31, 2007
|
|
|
|
|
|
|
|
|
Land,
buildings and improvements
|
|
$ |
13,522 |
|
|
$ |
11,978 |
|
Pipelines
and related assets
|
|
|
139,177 |
|
|
|
63,169 |
|
Machinery
and equipment
|
|
|
22,568 |
|
|
|
25,097 |
|
Transportation
equipment
|
|
|
32,960 |
|
|
|
32,906 |
|
Barges
and push boats
|
|
|
95,751 |
|
|
|
- |
|
Office
equipment, furniture and fixtures
|
|
|
4,098 |
|
|
|
2,759 |
|
Construction
in progress
|
|
|
20,124 |
|
|
|
7,102 |
|
Other
|
|
|
11,637 |
|
|
|
7,402 |
|
Subtotal
|
|
|
339,837 |
|
|
|
150,413 |
|
Accumulated
depreciation
|
|
|
(60,194 |
) |
|
|
(48,413 |
) |
Total
|
|
$ |
279,643 |
|
|
$ |
102,000 |
|
Asset
Retirement Obligations
In
general, our future asset retirement obligations relate to future costs
associated with the removal of certain segments of our oil, natural gas and
CO2
pipelines, removal of equipment and facilities from leased acreage and land
restoration. The fair value of a liability for an asset retirement obligation is
recorded in the period in which it is incurred, discounted to its present value
using our credit adjusted risk-free interest rate, and a corresponding amount
capitalized by increasing the carrying amount of the related long-lived asset.
The capitalized cost is depreciated over the useful life of the related
asset. Accretion of the discount increases the liability and is
recorded to expense.
The
following table summarizes the changes in our asset retirement obligations for
the nine months ended September 30, 2008.
Asset
retirement obligations as of December 31, 2007
|
|
$ |
1,173 |
|
Accretion
expense
|
|
|
67 |
|
Asset
retirement obligations as of September 30, 2008
|
|
$ |
1,240 |
|
At
September 30, 2008, $0.1 million of our asset retirement obligation was
classified in “Accrued liabilities” under current liabilities in our Unaudited
Consolidated Balance Sheets. Certain of our unconsolidated affiliates
have asset retirement obligations recorded at September 30, 2008 and December
31, 2007 relating to contractual agreements. These amounts are
immaterial to our financial statements.
6. Direct
Financing Leases
In the
fourth quarter of 2004, we constructed two segments of crude oil pipeline and a
CO2
pipeline segment to transport crude oil from and CO2 to
producing fields operated by Denbury. Denbury pays us a minimum
payment each month for the right to use these pipeline
segments. Those arrangements have been accounted for as direct
financing leases. As discussed in Note 3, we entered into a lease
arrangement with Denbury related to the NEJD Pipeline in May 2008 that is being
accounted for as a direct financing lease. Denbury pays us fixed
payments of $5.2 million per quarter that began in August 2008.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
The
following table lists the components of our net investment in direct financing
leases at September 30, 2008 and December 31, 2007:
|
|
September
30, 2008
|
|
|
December
31, 2007
|
|
|
|
|
|
|
|
|
Total
minimum lease payments to be received
|
|
$ |
412,850 |
|
|
$ |
7,039 |
|
Estimated
residual values of leased property (unguaranteed)
|
|
|
1,286 |
|
|
|
1,287 |
|
Unamortized
initial direct costs
|
|
|
2,631 |
|
|
|
- |
|
Less
unearned income
|
|
|
(234,899 |
) |
|
|
(2,953 |
) |
Net
investment in direct financing leases
|
|
$ |
181,868 |
|
|
$ |
5,373 |
|
At
September 30, 2008, minimum lease payments to be received for the remainder of
2008 are $5.5 million. Minimum lease payments to be received for each
of the five succeeding fiscal years are $21.9 million per year for 2009 through
2011, $21.8 million for 2012 and $21.3 million for 2013.
7. Intangible
Assets and Goodwill
Intangible
Assets
In
connection with the Davison and DG Marine acquisitions (See Note 3), we
allocated a portion of the purchase price to intangible assets based on their
fair values. The following table reflects the components of
intangible assets being amortized at the dates indicated:
|
|
|
|
|
September
30, 2008
|
|
|
December
31, 2007
|
|
|
|
Weighted
Amortization Period in Years
|
|
|
Gross
Carrying Amount
|
|
|
Accumulated
Amortization
|
|
|
Carrying
Value
|
|
|
Gross
Carrying Amount
|
|
|
Accumulated
Amortization
|
|
|
Carrying
Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery
services customer relationships
|
|
3
|
|
|
$ |
94,654 |
|
|
$ |
21,858 |
|
|
$ |
72,796 |
|
|
$ |
94,654 |
|
|
$ |
9,380 |
|
|
$ |
85,274 |
|
Supply
and logistics customer relationships
|
|
5
|
|
|
|
35,430 |
|
|
|
8,293 |
|
|
|
27,137 |
|
|
|
34,630 |
|
|
|
3,287 |
|
|
|
31,343 |
|
Refinery
services supplier relationships
|
|
2
|
|
|
|
36,469 |
|
|
|
20,682 |
|
|
|
15,787 |
|
|
|
36,469 |
|
|
|
9,241 |
|
|
|
27,228 |
|
Refinery
services licensing agreements
|
|
6
|
|
|
|
38,678 |
|
|
|
5,936 |
|
|
|
32,742 |
|
|
|
38,678 |
|
|
|
2,218 |
|
|
|
36,460 |
|
Supply
and logistics trade names-Davison and Grifco
|
|
7
|
|
|
|
18,888 |
|
|
|
2,581 |
|
|
|
16,307 |
|
|
|
17,988 |
|
|
|
930 |
|
|
|
17,058 |
|
Supply
and logistics favorable lease
|
|
15
|
|
|
|
13,260 |
|
|
|
552 |
|
|
|
12,708 |
|
|
|
13,260 |
|
|
|
197 |
|
|
|
13,063 |
|
Other
|
|
5
|
|
|
|
1,322 |
|
|
|
289 |
|
|
|
1,033 |
|
|
|
721 |
|
|
|
97 |
|
|
|
624 |
|
Total
|
|
5
|
|
|
$ |
238,701 |
|
|
$ |
60,191 |
|
|
$ |
178,510 |
|
|
$ |
236,400 |
|
|
$ |
25,350 |
|
|
$ |
211,050 |
|
We are
recording amortization of our intangible assets based on the period over which
the asset is expected to contribute to our future cash
flows. Generally, the contribution to our cash flows of the customer
and supplier relationships, licensing agreements and trade name intangible
assets is expected to decline over time, such that greater value is attributable
to the periods shortly after the acquisition was made. The favorable
lease and other intangible assets are being amortized on a straight-line
basis. Amortization expense on intangible assets was $11.6 million
and $34.8 million for the three and nine months ended September 30, 2008,
respectively. Amortization expense on intangible assets was $4.0
million for the three and nine months ended September 30, 2007.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Estimated
amortization expense for each of the five subsequent fiscal years is expected to
be as follows:
Year Ended December 31
|
|
Amortization Expense to be
Recorded
|
|
Remainder
of 2008
|
|
$ |
11,674 |
|
2009
|
|
$ |
32,600 |
|
2010
|
|
$ |
25,931 |
|
2011
|
|
$ |
21,253 |
|
2012
|
|
$ |
17,612 |
|
2013
|
|
$ |
14,208 |
|
Goodwill
In
connection with the Davison and Port Hudson acquisitions (see Note 3), the
residual of the purchase price over the fair values of the net tangible and
identifiable intangible assets acquired was allocated to
goodwill. The carrying amount of goodwill by business segment at
September 30, 2008 was $302.0 million to refinery services and $23.0 million to
supply and logistics.
8. Equity
Investees and Other Investments
T&P
Syngas Supply Company
We are
accounting for our 50% ownership in T&P Syngas under the equity method of
accounting. We received distributions from T&P Syngas of $1.7
million and $1.6 million during the nine months ended September 30, 2008 and
2007, respectively.
Sandhill
Group, LLC
We are
accounting for our 50% ownership in Sandhill under the equity method of
accounting. We received distributions from Sandhill of $163,000 and $101,000
during the nine months ended September 30, 2008 and 2007,
respectively.
Other
Projects
We have
also invested $4.6 million in the Faustina Project, a petroleum coke to ammonia
project that is in the development stage. All of our investment may
later be redeemed, with a return, or converted to equity after the project has
obtained construction financing. The funds we have invested are being
used for project development activities, which include the negotiation of
off-take agreements for the products and by-products of the plant to be
constructed, securing permits and securing financing for the construction phase
of the plant. We have recorded our investment in this debt security
at cost and classified it as held-to-maturity, since we have the intent and
ability to hold it until it is redeemed.
No events
or changes in circumstances have occurred that indicate a significant adverse
effect on the fair value of our investment at September 30, 2008, therefore our
investment is included in our Unaudited Consolidated Balance Sheet at
cost.
9. Debt
At
September 30, 2008 our obligations under credit facilities consisted of the
following:
|
|
September
30, 2008
|
|
|
December
31, 2007
|
|
|
|
|
|
|
|
|
Genesis
Credit Facility
|
|
$ |
343,200 |
|
|
$ |
80,000 |
|
DG
Marine Credit Facility (non-recourse to Genesis) - current portion of
long-term debt
|
|
|
48,200 |
|
|
|
- |
|
Total
Debt
|
|
$ |
391,400 |
|
|
$ |
80,000 |
|
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Genesis
Credit Facility
Our
credit facility, with a maximum facility amount of $500 million, of which $100
million can be used for letters of credit, is with a group of banks led by
Fortis Capital Corp. and Deutsche Bank Securities Inc. The maximum
facility amount represents the amount the banks have committed to fund pursuant
to the terms of the credit agreement. The borrowing base is
recalculated quarterly and at the time of material acquisitions. The
borrowing base represents the amount that can be borrowed or utilized for
letters of credit from a credit standpoint based on our EBITDA (earnings before
interest, taxes, depreciation and amortization), computed in accordance with the
provisions of our credit facility.
The
borrowing base may be increased to the extent of pro forma additional EBITDA,
(as defined in the credit agreement), attributable to acquisitions or internal
growth projects with approval of the lenders. Our borrowing base as
of September 30, 2008 exceeds $500 million, however amounts committed by the
lenders total $500 million.
At
September 30, 2008, we had $343.2 million borrowed under our credit facility and
we had $6.5 million in letters of credit outstanding. Our debt
increased at September 30, 2008 from the December 31, 2007 level as a result of
funding our CO2 pipeline
transactions with Denbury and our equity investment in DG Marine. 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 November 15, 2011. The total amount available for
borrowings at September 30, 2008 was $150.3 million under our credit
facility.
The key
terms for rates under our credit facility are as follows:
|
·
|
The
interest rate on borrowings may be based on the prime rate or the LIBOR
rate, at our option. The interest rate on prime rate loans can
range from the prime rate plus 0.50% to the prime rate plus
1.875%. The interest rate for LIBOR-based loans can range from
the LIBOR rate plus 1.50% to the LIBOR rate plus 2.875%. The
rate is based on our leverage ratio as computed under the credit
facility. Our leverage ratio is recalculated quarterly and in
connection with each material acquisition. At September
30, 2008, our borrowing rates were the prime rate plus 0.50% or the LIBOR
rate plus 1.50%.
|
|
·
|
Letter
of credit fees will range from 1.50% to 2.875% based on our leverage ratio
as computed under the credit facility. The rate can fluctuate
quarterly. At September 30, 2008, our letter of credit rate was
1.50%.
|
|
·
|
We
pay a commitment fee on the unused portion of the $500 million maximum
facility amount. The commitment fee will range from 0.30% to
0.50% based on our leverage ratio as computed under the credit
facility. The rate can fluctuate quarterly. At
September 30, 2008, the commitment fee rate was
0.30%.
|
Collateral
under the credit facility consists of substantially all our assets, excluding
our security interest in the NEJD pipeline, our ownership interest in the Free
State pipelines, and the assets of and our equity interest in, DG Marine. All of
the equity interest of DG Marine is pledged to secure its credit facility, which
is described below, While our general partner is jointly and
severally liable for all of our obligations unless and except to the extent
those obligations provide that they are non-recourse to our general partner, our
credit facility expressly provides that it is non-recourse to our general
partner (except to the extent of its pledge of its general partner interest in
certain of our subsidiaries), as well as to Denbury and its other
subsidiaries.
Our
credit facility contains customary covenants (affirmative, negative and
financial) that limit the manner in which we may conduct our
business. Our credit facility contains three primary financial
covenants - a debt service coverage ratio, leverage ratio and funded
indebtedness to capitalization ratio – that require us to achieve specific
minimum financial metrics. In general, our debt service coverage
ratio calculation compares EBITDA (as defined and adjusted in accordance with
the credit facility) to interest expense. Our leverage ratio
calculation compares our consolidated funded debt (as calculated in accordance
with our credit facility) to EBITDA (as adjusted). Our funded
indebtedness ratio compares outstanding debt to the sum of our consolidated
total funded debt plus our consolidated net worth.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Financial
Covenant
|
|
Requirement
|
|
Required
Ratio through September 30, 2008
|
|
Actual
Ratio as of September 30, 2008
|
|
|
|
|
|
|
|
Debt
Service Coverage Ratio
|
|
Minimum
|
|
2.75
to 1.0
|
|
6.71
to 1.0
|
Leverage
Ratio
|
|
Maximum
|
|
6.0
to 1.0
|
|
2.97
to 1.0
|
Funded
Indebtedness Ratio
|
|
Maximum
|
|
0.80
to 1.0
|
|
0.40
to
1.0
|
Our
credit facility includes provisions for the temporary adjustment of the required
ratios following material acquisitions and with lender approval. The
ratios in the table above are the required ratios for the period following a
material acquisition. If we meet these financial metrics and are not
otherwise in default under our credit facility, we may make quarterly
distributions; however, the amount of such distributions may not exceed the sum
of the distributable cash (as defined in the credit facility) generated by us
for the eight most recent quarters, less the sum of the distributions made with
respect to those quarters. At September 30, 2008, the excess of
distributable cash over distributions under this provision of the credit
facility was $42.4 million.
DG
Marine Credit Facility
In
connection with its acquisition of the Grifco assets on July 18, 2008, DG Marine
entered into a $90 million revolving credit facility with a syndicate of banks
led by SunTrust Bank and BMO Capital Markets Financing, Inc. In
addition to partially financing the Grifco acquisition, DG Marine may borrow
under that facility for general corporate purposes, such as paying for its newly
constructed barges and funding working capital requirements, including up to $5
million in letters of credit. That facility, which matures on July
18, 2011, is secured by all of the equity interests issued by DG Marine and
substantially all of DG Marine’s assets. Other than the pledge of our
equity interest in DG Marine, that facility is non-recourse to us and TD
Marine. At September 30, 2008, our consolidated balance sheet
included $113.5 million of DG Marine’s assets in our total assets.
At
September 30, 2008, DG Marine had $48.2 million outstanding under its credit
facility. Due to the revolving nature of loans under the DG Marine
credit facility, additional borrowings and periodic repayments and re-borrowings
may be made until the maturity date. The total amount available for
borrowings at September 30, 2008 was $41.8 million under this credit
facility.
The key
terms for rates under the DG Marine credit facility are as follows:
|
·
|
The
interest rate on borrowings may be based on the prime rate or the LIBOR
rate, at our option. The interest rate on prime rate loans can
range from the prime rate plus 1.50% to the prime rate plus
3.00%. The interest rate for LIBOR-based loans can range from
the LIBOR rate plus 2.50% to the LIBOR rate plus 4.00%. The
rate is based on DG Marine’s leverage ratio as computed under the credit
facility. Under the terms of DG Marine’s credit facility, the rates will
be the prime rate plus 3.00% and the LIBOR rate plus 4.00% for the period
from July 18, 2008 until October 31, 2008, after which time the rates will
fluctuate monthly based on the leverage
ratio.
|
|
·
|
Letter
of credit fees will range from 2.50% to 4.00% based on DG Marine’s
leverage ratio as computed under the credit facility. The rate
can fluctuate monthly. At September 30, 2008, there were no
letters of credit outstanding under the DG Marine credit
facility.
|
|
·
|
DG
Marine pays a commitment fee on the unused portion of the $90 million
facility amount. The commitment fee will range from 0.25% to
0.50% based on its leverage ratio as computed under the credit
facility. Under the terms of the DG Marine credit facility, the
commitment fee rate was 0.50% for the period from July 18, 2008 until
October 31, 2008, after which time the rate will fluctuate monthly based
on the leverage ratio.
|
\
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
In August
2008, DG Marine entered into a series of interest rate swap agreements to
effectively fix the underlying LIBOR rate on $32.9 million of its
borrowings under its credit facility through July 18, 2011. The fixed interest
rates in the swap agreements range from the three-month interest rate of 3.03%
in effect at September 30, 2008 to 4.68% at July 18, 2011.
DG
Marine’s credit facility contains customary covenants (affirmative, negative and
financial) that limit the manner in which it may conduct its
business. DG Marine’s credit facility contains three primary
financial covenants – an interest coverage ratio, leverage ratio and asset
coverage ratio – that require DG Marine to achieve specific minimum financial
metrics. In general, the interest coverage ratio calculation compares
EBITDA (as defined and adjusted in accordance with the credit facility) to
interest expense. The leverage ratio calculation compares DG Marine’s
funded debt (as calculated in accordance with the credit facility) to EBITDA (as
adjusted). The asset coverage ratio compares an estimated liquidation
value of DG Marine’s boats and barges to DG Marine’s outstanding
debt.
At
September 30, 2008, DG Marine was not in technical compliance with the leverage
ratio or interest coverage ratio in its credit facility, primarily due to timing
of costs related to the start-up of operations as a new entity and the
acquisition of new vessels, and the effects of hurricanes on operations. Based
on the nature of the issues resulting in such non-compliance and based on
discussions with each of the banks comprising its lending syndicate, the
management of DG Marine currently believes DG Marine’s lenders will agree to a
waiver of the non-compliance and to an amendment to its credit facility to
adjust those ratios, the terms of which are still to be determined, but which
will result in DG Marine being in full compliance with the terms of its credit
agreement. DG Marine’s management does not believe such non-compliance will
materially and adversely affect its operations or financial condition; however,
until that joint venture complies with the terms of its credit agreement, we
will classify its outstanding debt as a current liability on our balance
sheet.
10. Partners’
Capital and Distributions
Partners’
Capital
Partner’s
capital at September 30, 2008 consists of 39,452,305 common units, including
4,028,096 units owned by our general partner and its affiliates, representing a
98% aggregate ownership interest in the Partnership and its subsidiaries (after
giving affect to the general partner interest), and a 2% general partner
interest.
Our
general partner owns all of our general partner interest, including incentive
distribution rights, all of the 0.01% general partner interest in Genesis Crude
Oil, L.P. (which is reflected as a minority interest in the Unaudited
Consolidated Balance Sheet at September 30, 2008) and operates our
business.
Our
partnership agreement authorizes our general partner to cause us to issue
additional limited partner interests and other equity securities, the proceeds
from which could be used to provide additional funds for acquisitions or other
needs.
On July
18, 2008, we issued 837,690 of our common units to Grifco. The units
were issued at a value of $19.896 per unit, for a total value of $16.7 million,
as a portion of the consideration for the acquisition of the inland marine
transportation business of Grifco. See Note 3.
Additionally,
on July 18, 2008, we redeemed 837,690 of our common units owned by members of
the Davison family. Those units had been issued as a portion of the
consideration for the acquisition of the energy-related business of the Davison
family in July 2007. The redemption was at a value of $19.896 per
unit, for a total value of $16.7 million. After giving effect to the
issuance and redemption described above, we did not experience a change in the
number of common units outstanding.
Distributions
Generally,
we will distribute 100% of our available cash (as defined by our partnership
agreement) within 45 days after the end of each quarter to unitholders of record
and to our general partner. Available cash consists generally of all
of our cash receipts less cash disbursements adjusted for net changes to
reserves. As discussed in Note 9, our credit facility limits the
amount of distributions we may pay in any quarter.
Pursuant
to our partnership agreement, our general partner receives incremental incentive
cash distributions when unitholders’ cash distributions exceed certain target
thresholds, in addition to its 2% general partner interest. The
allocations of distributions between our common unitholders and our general
partner, including the incentive distribution rights is as
follows:
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
|
Unitholders
|
|
General
Partner
|
Quarterly
Cash Distribution per Common Unit:
|
|
|
|
Up
to and including $0.25 per Unit
|
98.00%
|
|
2.00%
|
First
Target - $0.251 per Unit up to and including $0.28 per
Unit
|
84.74%
|
|
15.26%
|
Second
Target - $0.281 per Unit up to and including $0.33 per
Unit
|
74.26%
|
|
25.74%
|
Over
Second Target - Cash distributions greater than $0.33 per
Unit
|
49.02%
|
|
50.98%
|
We paid
or will pay the following distributions in 2007 and 2008:
Distribution For
|
|
Date Paid
|
|
Per Unit Amount
|
|
|
Limited Partner Interests
Amount
|
|
|
General Partner Interest
Amount
|
|
|
General Partner Incentive Distribution
Amount
|
|
|
Total Amount
|
|
|
|
|
|
|
|
|
|
|
Second
quarter 2007
|
|
August
2007
|
|
$ |
0.2300 |
|
|
$ |
3,170 |
(1)
|
|
$ |
65 |
|
|
$ |
- |
|
|
$ |
3,235 |
(1)
|
Third
quarter 2007
|
|
November
2007
|
|
$ |
0.2700 |
|
|
$ |
7,646 |
|
|
$ |
156 |
|
|
$ |
90 |
|
|
$ |
7,892 |
|
Fourth
quarter 2007
|
|
February
2008
|
|
$ |
0.2850 |
|
|
$ |
10,903 |
|
|
$ |
222 |
|
|
$ |
245 |
|
|
$ |
11,370 |
|
First
quarter 2008
|
|
May
2008
|
|
$ |
0.3000 |
|
|
$ |
11,476 |
|
|
$ |
234 |
|
|
$ |
429 |
|
|
$ |
12,139 |
|
Second
quarter 2008
|
|
August
2008
|
|
$ |
0.3150 |
|
|
$ |
12,427 |
|
|
$ |
254 |
|
|
$ |
633 |
|
|
$ |
13,314 |
|
Third
quarter 2008
|
|
November
2008(2)
|
|
$ |
0.3225 |
|
|
$ |
12,723 |
|
|
$ |
260 |
|
|
$ |
728 |
|
|
$ |
13,711 |
|
(1) The
distribution paid on August 14, 2007 to holders of our common units is net of
the amounts payable with respect to the common units issued in connection with
the Davison transaction. The Davison unitholders and our general
partner waived their rights to receive such distributions, instead receiving
purchase price adjustments with us.
(2) This
distribution will be paid on November 14, 2008 to the general partner and
unitholders of record as of November 4, 2008.
Net
Income Per Common Unit
Our net
income is first allocated to the general partner based on the amount of
incentive distributions. The remainder is then allocated 98% to the limited
partners and 2% to the general partner. Basic net income per limited partner
unit is determined by dividing net income attributable to limited partners by
the weighted average number of outstanding limited partner units during the
period. Diluted net income per common unit is calculated in the same
manner, but also considers the impact to common units for the potential dilution
from phantom units outstanding. (See Note 17 for discussion of phantom
units.)
In a
period of net operating losses, incremental phantom units are excluded from the
calculation of diluted earnings per unit due to their anti-dilutive effect.
During 2008, we have reported net income; therefore incremental phantom units
have been included in the calculation of diluted earnings per
unit.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
The
following table sets forth the computation of basic net income per common
unit.
|
|
Three
Months Ended September 30,
|
|
|
Nine
Months Ended September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
Numerators
for basic and diluted net income per common unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
10,763 |
|
|
$ |
1,699 |
|
|
$ |
19,736 |
|
|
$ |
1,912 |
|
Less: General
partner's incentive distribution paid
|
|
|
(633 |
) |
|
|
- |
|
|
|
(1,307 |
) |
|
|
- |
|
Subtotal
|
|
|
10,130 |
|
|
|
1,699 |
|
|
|
18,429 |
|
|
|
1,912 |
|
Less
general partner 2% ownership
|
|
|
(203 |
) |
|
|
(34 |
) |
|
|
(369 |
) |
|
|
(38 |
) |
Net
income available for common unitholders
|
|
$ |
9,927 |
|
|
$ |
1,665 |
|
|
$ |
18,060 |
|
|
$ |
1,874 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator
for basic per common unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Units
|
|
|
39,452 |
|
|
|
24,527 |
|
|
|
38,796 |
|
|
|
17,405 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator
for diluted per common unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Units
|
|
|
39,452 |
|
|
|
24,527 |
|
|
|
38,796 |
|
|
|
17,405 |
|
Phantom
Units
|
|
|
72 |
|
|
|
- |
|
|
|
57 |
|
|
|
- |
|
|
|
|
39,524 |
|
|
|
24,527 |
|
|
|
38,853 |
|
|
|
17,405 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
net income per common unit
|
|
$ |
0.25 |
|
|
$ |
0.07 |
|
|
$ |
0.47 |
|
|
$ |
0.11 |
|
Diluted
net income per common unit
|
|
$ |
0.25 |
|
|
$ |
0.07 |
|
|
$ |
0.46 |
|
|
$ |
0.11 |
|
11. Business
Segment Information
We
evaluate segment performance based on segment margin. We calculate
segment margin as revenues less costs of sales and operating expenses, and we
include income from investments in joint ventures. We do not deduct depreciation
and amortization. All of our revenues are derived from, and all of
our assets are located in, the United States. The pipeline
transportation segment information includes the revenue, segment margin and
assets of our direct financing leases. The tables below reflect our
segment information.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
|
|
Pipeline
Transportation
|
|
|
Refinery
Services
|
|
|
Industrial
Gases (a)
|
|
|
Supply &
Logistics
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended September 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin excluding depreciation and amortization (b)
|
|
$ |
10,642 |
|
|
$ |
13,041 |
|
|
$ |
3,505 |
|
|
$ |
13,690 |
|
|
$ |
40,878 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
$ |
2,299 |
|
|
$ |
992 |
|
|
$ |
- |
|
|
$ |
107,075 |
|
|
$ |
110,366 |
|
Maintenance
capital expenditures
|
|
$ |
261 |
|
|
$ |
351 |
|
|
$ |
- |
|
|
$ |
1,371 |
|
|
$ |
1,983 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
customers
|
|
$ |
11,836 |
|
|
$ |
61,306 |
|
|
$ |
4,792 |
|
|
$ |
556,396 |
|
|
$ |
634,330 |
|
Intersegment
(d)
|
|
|
2,589 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,589 |
|
Total
revenues of reportable segments
|
|
$ |
14,425 |
|
|
$ |
61,306 |
|
|
$ |
4,792 |
|
|
$ |
556,396 |
|
|
$ |
636,919 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin excluding depreciation and amortization (b)
|
|
$ |
3,763 |
|
|
$ |
8,545 |
|
|
$ |
3,232 |
|
|
$ |
4,960 |
|
|
$ |
20,500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
$ |
1,812 |
|
|
$ |
553 |
|
|
$ |
552 |
|
|
$ |
441 |
|
|
$ |
3,358 |
|
Maintenance
capital expenditures
|
|
$ |
1,624 |
|
|
$ |
269 |
|
|
$ |
- |
|
|
$ |
255 |
|
|
$ |
2,148 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
customers
|
|
$ |
5,949 |
|
|
$ |
25,349 |
|
|
$ |
4,373 |
|
|
$ |
317,653 |
|
|
$ |
353,324 |
|
Intersegment
(d)
|
|
|
946 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
946 |
|
Total
revenues of reportable segments
|
|
$ |
6,895 |
|
|
$ |
25,349 |
|
|
$ |
4,373 |
|
|
$ |
317,653 |
|
|
$ |
354,270 |
|
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
|
|
Pipeline
Transportation
|
|
|
Refinery
Services
|
|
|
Industrial
Gases (a)
|
|
|
Supply &
Logistics
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin excluding depreciation and amortization (b)
|
|
$ |
22,113 |
|
|
$ |
44,245 |
|
|
$ |
9,324 |
|
|
$ |
29,443 |
|
|
$ |
105,125 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
$ |
80,926 |
|
|
$ |
2,700 |
|
|
$ |
2,210 |
|
|
$ |
111,575 |
|
|
$ |
197,411 |
|
Maintenance
capital expenditures
|
|
$ |
463 |
|
|
$ |
856 |
|
|
$ |
- |
|
|
$ |
1,648 |
|
|
$ |
2,967 |
|
Net
fixed and other long-term assets (c)
|
|
$ |
284,926 |
|
|
$ |
441,110 |
|
|
$ |
44,855 |
|
|
$ |
249,387 |
|
|
$ |
1,020,278 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
customers
|
|
$ |
27,509 |
|
|
$ |
160,945 |
|
|
$ |
13,112 |
|
|
$ |
1,555,991 |
|
|
$ |
1,757,557 |
|
Intersegment
(d)
|
|
|
6,087 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
6,087 |
|
Total
revenues of reportable segments
|
|
$ |
33,596 |
|
|
$ |
160,945 |
|
|
$ |
13,112 |
|
|
$ |
1,555,991 |
|
|
$ |
1,763,644 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin excluding depreciation and amortization (b)
|
|
$ |
8,858 |
|
|
$ |
8,545 |
|
|
$ |
8,804 |
|
|
$ |
7,986 |
|
|
$ |
34,193 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
$ |
2,365 |
|
|
$ |
553 |
|
|
$ |
552 |
|
|
$ |
582 |
|
|
$ |
4,052 |
|
Maintenance
capital expenditures
|
|
$ |
2,177 |
|
|
$ |
269 |
|
|
$ |
- |
|
|
$ |
396 |
|
|
$ |
2,842 |
|
Net
fixed and other long-term assets (c)
|
|
$ |
31,558 |
|
|
$ |
409,510 |
|
|
$ |
48,188 |
|
|
$ |
226,791 |
|
|
$ |
716,047 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
customers
|
|
$ |
16,956 |
|
|
$ |
25,349 |
|
|
$ |
11,816 |
|
|
$ |
681,667 |
|
|
$ |
735,788 |
|
Intersegment
(d)
|
|
|
3,062 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,062 |
|
Total
revenues of reportable segments
|
|
$ |
20,018 |
|
|
|
25,349 |
|
|
$ |
11,816 |
|
|
$ |
681,667 |
|
|
$ |
738,850 |
|
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
|
a)
|
Industrial
gases includes our CO2
marketing operations and our equity income from our investments in T&P
Syngas and Sandhill.
|
|
b)
|
Segment
margin was calculated as revenues less cost of sales and operating
expenses, excluding depreciation and amortization. It includes
our share of the operating income of equity joint ventures. A
reconciliation of segment margin to income before income taxes and
minority interest for the periods presented is as
follows:
|
|
|
Three
Months Ended September 30,
|
|
|
Nine
Months Ended September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin excluding depreciation and amortization
|
|
$ |
40,878 |
|
|
$ |
20,500 |
|
|
$ |
105,125 |
|
|
$ |
34,193 |
|
General
and administrative expenses
|
|
|
(9,239 |
) |
|
|
(4,724 |
) |
|
|
(26,929 |
) |
|
|
(13,652 |
) |
Depreciation
and amortization expense
|
|
|
(18,100 |
) |
|
|
(8,372 |
) |
|
|
(51,610 |
) |
|
|
(12,346 |
) |
Net
gain (loss) on disposal of surplus assets
|
|
|
58 |
|
|
|
- |
|
|
|
(36 |
) |
|
|
24 |
|
Interest
expense, net
|
|
|
(4,483 |
) |
|
|
(4,701 |
) |
|
|
(8,191 |
) |
|
|
(5,248 |
) |
Income
before income taxes and minority interest
|
|
$ |
9,114 |
|
|
$ |
2,703 |
|
|
$ |
18,359 |
|
|
$ |
2,971 |
|
|
c)
|
Net
fixed and other long-term assets are the measure used by management in
evaluating performance 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.
|
|
d)
|
Intersegment
sales were conducted on an arm’s length
basis.
|
12. 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. The transactions with related
parties were as follows:
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
|
|
Nine
Months Ended September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
Truck
transportation services provided to Denbury
|
|
$ |
2,343 |
|
|
$ |
1,287 |
|
Pipeline
transportation services provided to Denbury
|
|
$ |
6,899 |
|
|
$ |
3,878 |
|
Payments
received under direct financing leases from Denbury
|
|
$ |
6,056 |
|
|
$ |
890 |
|
Pipeline
transportation income portion of direct financing lease fees with
Denbury
|
|
$ |
6,450 |
|
|
$ |
479 |
|
Pipeline
monitoring services provided to Denbury
|
|
$ |
80 |
|
|
$ |
90 |
|
CO2
transportation services provided by Denbury
|
|
$ |
4,120 |
|
|
$ |
3,796 |
|
Crude
oil purchases from Denbury
|
|
$ |
- |
|
|
$ |
69 |
|
Directors'
fees paid to Denbury
|
|
$ |
147 |
|
|
$ |
112 |
|
Operations,
general and administrative services provided by our general
partner
|
|
$ |
38,669 |
|
|
$ |
15,966 |
|
Distributions
to our general partner on its limited partner units and general partner
interest
|
|
$ |
4,563 |
|
|
$ |
1,111 |
|
Sales
of CO2 to
Sandhill
|
|
$ |
2,217 |
|
|
$ |
2,040 |
|
Petroleum
products sales to Davison family businesses
|
|
$ |
1,089 |
|
|
$ |
- |
|
Transportation
Services
We
provide truck transportation services to Denbury to move their crude oil from
the wellhead to our Mississippi pipeline. Denbury pays us a fee for
this trucking service that varies with the distance the crude oil is
trucked. These fees are reflected in the statement of operations as
supply and logistics revenues.
Denbury
is the only shipper on our Mississippi pipeline other than us, and we earn
tariffs for transporting their oil. We also earned fees from Denbury
under the direct financing lease arrangements for the Olive and Brookhaven crude
oil pipelines and the Brookhaven CO2 pipeline
and recorded pipeline transportation income from these
arrangements.
We also
provide pipeline monitoring services to Denbury. This revenue is
included in pipeline revenues in the unaudited statements of
operations.
Directors’
Fees
We paid
Denbury for the services of each of four of Denbury’s officers who serve as
directors of our general partner, at an annual rate that is the same as the rate
at which our independent directors were paid.
CO2 Operations
and Transportation
Denbury
charges us a transportation fee of $0.16 per Mcf (adjusted for inflation) to
deliver CO2 for us to
our customers. In the first nine months of 2008, the
inflation-adjusted transportation fee averaged $0.1909 per Mcf.
Operations,
General and Administrative Services
We do not
directly employ any persons to manage or operate our business. Those
functions are provided by our general partner. We reimburse the
general partner for all direct and indirect costs of these
services.
Amounts
due to and from Related Parties
At
September 30, 2008 and December 31, 2007, we owed Denbury $1.1 million and $1.0
million, respectively, for purchases of crude oil and CO2
transportation charges. Denbury owed us $1.9 million and $0.9 million
for transportation services at September 30, 2008 and December 31, 2007,
respectively. We owed our general partner $2.1 million and $0.7
million for administrative services at September 30, 2008 and December 31, 2007,
respectively. At September 30, 2008 and December 31, 2007, Sandhill
owed us $0.8 and $0.5 million for purchases of CO2,
respectively. At December 31, 2007, we owed the Davison family
entities $0.8 million for reimbursement of costs paid primarily related to
employee transition services.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Drop-down
transactions
On May
30, 2008, we entered into a $175 million financing lease arrangement with
Denbury Onshore for its NEJD Pipeline System, and acquired its Free State
CO2
pipeline system for $75 million, consisting of $50 million cash and $25 million
of our common units. See Note 3.
Unit
redemption
As
discussed in Note 10, we redeemed 837,690 of our common units owned by members
of the Davison family. The total value of the units redeemed was
$16.7 million.
DG
Marine joint venture
Our
partner in the DG Marine joint venture is TD Marine, LLC, a joint venture
consisting of three members of the Davison family. See Note
3.
Financing
Our
general partner, a wholly owned subsidiary of Denbury, guarantees our
obligations under our credit facility. Our general partner’s
principal assets are its general and limited partnership interests in
us. Our credit agreement obligations are not guaranteed by Denbury or
any of its other subsidiaries. Our credit facility is non-recourse to
our general partner, except to the extent of its pledge of its 0.01% general
partner interest in Genesis Crude Oil, L.P.
We
guarantee 50% of the obligation of Sandhill to a bank. At September
30, 2008, the total amount of Sandhill’s obligation to the bank was $3.3
million; therefore, our guarantee was for $1.65 million.
A bank
which participates in the DG Marine credit facility is owned partially by
members of the Davison family. Approximately 14% of the outstanding
common shares of Community Trust Bank are held by Davison family
members. Community Trust Bank is an 11% participant in the DG Marine
credit facility.
13. Major
Customers and Credit Risk
Due to
the nature of our supply and logistics operations, a disproportionate percentage
of our trade receivables consist of obligations of energy
companies. This industry concentration has the potential to impact
our overall exposure to credit risk, either positively or negatively, in that
our customers could be affected by similar changes in economic, industry or
other conditions. However, we believe that the credit risk posed by
this industry concentration is offset by the creditworthiness of our customer
base. Our portfolio of accounts receivable is comprised in large part
of integrated and large independent energy companies with stable payment
experience. The credit risk related to contracts which are traded on
the NYMEX is limited due to the daily cash settlement procedures and other NYMEX
requirements.
We have
established various procedures to manage our credit exposure, including initial
credit approvals, credit limits, collateral requirements and rights of
offset. Letters of credit, prepayments and guarantees are also
utilized to limit credit risk to ensure that our established credit criteria are
met.
Shell Oil
Company accounted for 15% of total revenues in the first nine months of
2008. Shell Oil Company, Occidental Energy Marketing, Inc., and
Calumet Specialty Products Partners, L.P. accounted for 22%, 14% and 10% of
total revenues in the first nine months of 2007, respectively. The
majority of the revenues from these customers in both periods relate to our
crude oil supply and logistics operations.
14. Supplemental
Cash Flow Information
Cash
received by us for interest for the nine months ended September 30, 2008 and
2007 was $118,000 and $158,000, respectively. Payments of interest
and commitment fees were $8,212,000 and $462,000 for the nine months ended
September 30, 2008 and 2007, respectively.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Cash paid
for income taxes during the nine months ended September 30, 2008 was
$376,000.
At
September 30, 2008, we had incurred liabilities for fixed asset and other asset
additions totaling $0.5 million that had not been paid at the end of the third
quarter, and, therefore, are not included in the caption “Payments to acquire
fixed assets” and “Other, net” under investing activities on the Unaudited
Consolidated Statements of Cash Flows. At September 30, 2007, we had
incurred $0.3 million of liabilities that had not been paid at that date and are
not included in “Payments to acquire fixed assets” under investing
activities.
In May
2008, we issued common units with a value of $25 million as part of the
consideration for the acquisition of the Free State Pipeline from
Denbury. In July 2008, we issued common units with a value of $16.7
million as part of the consideration for the acquisition of the inland marine
transportation assets of Grifco. These common unit issuances are non-cash
transactions and the value of the assets acquired is not included in investing
activities and the issuance of the common units is not reflected under financing
activities in our Unaudited Consolidated Statements of Cash Flows.
15. Derivatives
The
derivative instruments that we use consist primarily of futures and options
contracts traded on the NYMEX which we use to hedge our exposure to commodity
prices, primarily crude oil, fuel oil and petroleum products. Additionally, we
use interest rate swap contracts with financial institutions to hedge interest
rates.
We review
our contracts to determine if the contracts meet the definition of derivatives
pursuant to SFAS 133, “Accounting for Derivative Instruments and Hedging
Activities.” At September 30, 2008, we had commodity futures
contracts that were considered free-standing derivatives that are accounted for
at fair value. The fair value of these contracts was determined based
on the closing price for such contracts on September 30, 2008. We
marked these contracts to fair value at September 30, 2008. During
the three months ended September 30, 2008, we recorded a gain of $3.4 million,
related to derivative transactions, which are included in the Unaudited
Consolidated Statements of Operations under the caption “Supply and logistics
costs.” During the nine months ended September 30, 2008 we recorded a
loss of $0.6 million related to derivative transactions. We did not
utilize any commodity derivatives that were accounted for as hedges during the
three and nine months ended September 30, 2008.
During
the three months ended September 30, 2008, DG Marine entered into a series of
interest rate swap contracts with two financial institutions related to $32.9
million of the outstanding debt under the DG Marine credit
facility. These swaps effectively convert this portion of DG Marine’s
debt from floating LIBOR rate to a series of fixed rates through July
2011. We have determined that these swaps are effective cash flow
hedges of DG Marine’s interest rate exposure. The net loss on these
cash flow derivatives of $0.2 million at September 30, 2008 is included in our
consolidated balance sheets in Accumulated Other Comprehensive Income ($0.1
million) and Minority Interest ($0.1 million), and is expected to be
reclassified to future earnings contemporaneously as interest expense associated
with the underlying debt under the DG Marine credit facility is
recorded. We expect the total net loss to be reclassified into
earnings during the period the swaps are outstanding. Because a
portion of these amounts is based on market prices at the current period end,
actual amounts to be reclassified to earnings will differ and could vary
materially as a result of changes in market conditions.
The
consolidated balance sheet at September 30, 2008 includes increases in other
current assets of $0.3 million and other liabilities of $0.2 million as a result
of open commodity and interest rate derivative transactions. The
consolidated balance sheet at December 31, 2007 included a decrease in other
current assets of $0.7 million as a result of derivative
transactions. These changes in the consolidated balance sheet result
from settlement of derivative contacts and changes in market prices or interest
rates.
We
determined that the remainder of our derivative contracts qualified for the
normal purchase and sale exemption and were designated and documented as such at
September 30, 2008 and December 31, 2007.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
16. Contingencies
Guarantees
We
guaranteed $1.2 million of residual value related to the leases of trailers from
a lessor. We believe the likelihood that we would be required to
perform or otherwise incur any significant losses associated with this guarantee
is remote.
We
guaranteed 50% of the obligations of Sandhill under a credit facility with a
bank. At September 30, 2008, Sandhill owed $3.3 million; therefore
our guaranty was $1.65 million. Sandhill makes principal payments for
this obligation totaling $0.6 million per year.
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, or 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 third party claims against us for indemnity with respect to the fire and
explosion of January 18, 2000. We believe that the demand against us
is without merit and intend to vigorously defend ourselves in this
matter. We currently believe that this matter will not have a
material financial effect on our financial position, results of operations, or
cash flows.
Environmental
In 1992,
Howell Crude Oil Company (“Howell”) entered into a sublease with Koch
Industries, Inc. (“Koch”), covering a one acre tract of land located in Santa
Rosa County, Florida to operate a crude oil trucking station, known as Jay
Station. The sublease provided that Howell would indemnify Koch for
environmental contamination on the property under certain
circumstances. Howell operated the Jay Station from 1992 until
December of 1996 when this operation was sold to us by Howell. We
operated the Jay Station as a crude oil trucking station until
2003. Koch has indicated that it has incurred certain
investigative and/or other costs, for which Koch alleges some or all should be
reimbursed by us, under the indemnification provisions of the sublease for
environmental contamination on the site and surrounding areas. Koch
has also alleged that we are responsible for future environmental obligations
relating to the Jay Station.
Howell
was acquired by Anadarko Petroleum Corporation (“Anadarko”) in
2002. In 2005, we entered into a joint defense and cost allocation
agreement with Anadarko. Under the terms of the joint allocation
agreement, we agreed to reasonably cooperate with each other to address any
liabilities or defense costs with respect to the Jay
Station. Additionally under the joint allocation agreement, Anadarko
will be responsible for sixty percent of the costs related to any liabilities or
defense costs incurred with respect to contamination at the Jay
Station.
We were
formed in 1996 by the sale and contribution of assets from Howell and Basis
Petroleum, Inc. (“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 intend to seek recovery of
Basis' share of potential liabilities and defense costs with respect to Jay
Station.
We have
developed a plan of remediation for affected soil and groundwater at Jay Station
which has been approved by appropriate state regulatory agencies. We
have accrued an estimate of our share of liability for this matter in the amount
of $0.8 million. The time period over which our liability would be
paid is uncertain and could be several years. This liability may
decrease if indemnification and/or cost reimbursement is obtained by us for
Basis' potential liabilities with respect to this matter. At this
time, our estimate of potential obligations does not assume any specific amount
contributed on behalf of the Basis obligations, although we believe that Basis
is responsible for a significant part of these potential obligations.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
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.
In
connection with the sale of pipeline assets in Texas in the fourth quarter of
2003, we retained responsibility for environmental matters related to the
operations of those pipelines in the periods prior to the date of the sales,
subject to certain conditions. On the majority of the pipelines sold,
our responsibility for any environmental claim will not exceed an aggregate
total of $2 million. Our responsibility for indemnification related
to these sales will cease in 2013.
Other
Matters
Our
facilities and operations may experience damage as a result of an accident or
natural disaster. These hazards can cause personal injury or loss of
life, severe damage to and destruction of property and equipment, pollution or
environmental damage and suspension of operations. We maintain
insurance that we consider adequate to cover our operations and properties, in
amounts we consider reasonable. Our insurance does not cover every
potential risk associated with operating our facilities, including the potential
loss of significant revenues. The occurrence of a significant event
that is not fully-insured could materially and adversely affect our results of
operations. We believe we are adequately insured for public liability
and property damage to others and that our coverage is similar to other
companies with operations similar to ours. No assurance can be made
that we will be able to maintain adequate insurance in the future at premium
rates that we consider reasonable.
We are
subject to lawsuits in the normal course of business and examination by tax and
other regulatory authorities. We do not expect such matters presently
pending to have a material adverse effect on our financial position, results of
operations, or cash flows.
17. Unit-Based
Compensation Plans
Stock
Appreciation Rights Plan
The
adjustment of the liability for our stock appreciation rights plan to its fair
value at September 30, 2008 resulted in a net credit to expense for the nine
months ended September 30, 2008 of $1.4 million, with $1.0 million, $0.2 million
and $0.2 million included in general and administrative expenses, pipeline
operating costs, and supply and logistics operating costs, respectively. Expense
of $0.1 million was recorded to refinery services operating costs related to
grants awarded in the first quarter of 2008. The decrease in our
common unit market price from December 31, 2007 to September 30, 2008 of $9.21
reduced the accrual for the plan, providing a credit to the expense we recorded
under our plan during the nine months ended September 30, 2008. For
the three months ended September 30, 2008, we recorded a credit of $0.8 million
for our stock appreciation rights plan, with $0.6 million included in general
and administrative expenses and $0.1 million included in both pipeline operating
costs and supply and logistics costs.
The
adjustment of the liability to its fair value at September 30, 2007, resulted in
expense for the nine months ended September 30, 2007 of $3.1 million, with $2.0
million, $0.6 million and $0.5 million included in general and administrative
expenses, supply and logistics operating costs, and pipeline operating costs,
respectively. For the three months ended September 30, 2007, we
recorded a reduction to our expense of $1.2 million, with $0.8 million, $0.2
million and $0.2 million included in general and administrative expenses, supply
and logistics operating costs, and pipeline operating costs,
respectively.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
The
following table reflects rights activity under our plan during the nine months
ended September 30, 2008:
Stock
Appreciation Rights
|
|
Rights
|
|
|
Weighted
Average Exercise Price
|
|
|
Weighted
Average Contractual Remaining Term (Yrs)
|
|
|
Aggregate
Intrinsic Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
at January 1, 2008
|
|
|
593,458 |
|
|
$ |
15.45 |
|
|
|
|
|
|
|
Granted
|
|
|
536,308 |
|
|
$ |
20.83 |
|
|
|
|
|
|
|
Exercised
|
|
|
(38,759 |
) |
|
$ |
19.56 |
|
|
|
|
|
|
|
Forfeited
or expired
|
|
|
(62,269 |
) |
|
$ |
17.40 |
|
|
|
|
|
|
|
Outstanding
at September 30, 2008
|
|
|
1,028,738 |
|
|
$ |
18.14 |
|
|
|
8.2 |
|
|
$ |
1,072 |
|
Exercisable
at September 30, 2008
|
|
|
307,760 |
|
|
$ |
14.89 |
|
|
|
6.4 |
|
|
$ |
758 |
|
The
weighted-average fair value at September 30, 2008 of rights granted during the
first nine months of 2008 was $1.73 per right, determined using the following
assumptions:
Assumptions
Used for Fair Value of Rights
Granted
in 2008
|
Expected
life of rights (in years)
|
5.50
- 6.25
|
Risk-free
interest rate
|
2.97% -
3.11%
|
Expected
unit price volatility
|
36.02%
|
Expected
future distribution yield
|
6.00%
|
The total
intrinsic value of rights exercised during the first nine months of 2008 was
$0.4 million, which was paid in cash to the participants.
At
September 30, 2008, there was $0.6 million of total unrecognized compensation
cost related to rights that we expect will vest under the plan. This
amount was calculated as the fair value at September 30, 2008 multiplied by
those rights for which compensation cost has not been recognized, adjusted for
estimated forfeitures. This unrecognized cost will be recalculated at
each balance sheet date until the rights are exercised, forfeited, or
expire. For the awards outstanding at September 30, 2008, the
remaining cost will be recognized over a weighted average period of 1.4
years.
2007
Long Term Incentive Plan
Subject
to adjustment as provided in the 2007 LTIP, awards up to an aggregate of
1,000,000 units may be granted under the 2007 LTIP, of which 928,472 remain
authorized for issuance at September 30, 2008. In February 2008, a
total of 9,166 Phantom Units were granted with vesting at the end of three
years. The aggregate grant date fair value of these Phantom Unit
awards was $0.2 million based on the grant date market price of our common units
of $17.89 per unit, adjusted for distributions that holders of phantom units
will not receive during the vesting period. In June 2008, a total of
23,000 Phantom Units were granted with vesting at the end of one
year. The aggregate grant date fair value of these Phantom Unit
awards was $0.5 million based on the grant date market price of our common units
of $20.12 per unit, adjusted for distributions that holders of phantom units
will not receive during the vesting period.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
As of
September 30, 2008, there was $1.0 million of unrecognized compensation expense
related to these units. This unrecognized compensation cost is
expected to be recognized over a weighted-average period of 2.0
years.
The
following table summarizes information regarding our non-vested Phantom Unit
grants as of September 30, 2008:
Non-vested Phantom Unit
Grants
|
|
Number of Units
|
|
|
Weighted Average Grant-Date Fair
Value
|
|
|
|
|
|
|
|
|
Non-vested
at January 1, 2008
|
|
|
39,362 |
|
|
$ |
21.92 |
|
Granted
|
|
|
32,166 |
|
|
$ |
19.48 |
|
Non-vested
at September 30, 2008
|
|
|
71,528 |
|
|
$ |
20.82 |
|
18. Fair-Value
Measurements
As
discussed in Note 2, effective January 1, 2008 we partially adopted SFAS 157
which defines fair value as the exchange price that would be received for an
asset or paid to transfer a liability (an exit price) in the principal or most
advantageous market for the asset or liability in an orderly transaction between
market participants at the measurement date. SFAS 157 establishes a
three-level fair value hierarchy that prioritizes the inputs used to measure
fair value. This hierarchy requires entities to maximize the use of
observable inputs and minimize the use of unobservable inputs. The
three levels of inputs used to measure fair value are as follows:
|
Level
1:
|
Quoted
prices in active markets for identical, unrestricted assets or
liabilities.
|
|
Level
2:
|
Observable
market-based inputs or unobservable inputs that are corroborated by market
data.
|
|
Level
3:
|
Unobservable
inputs that are not corroborated by market data, which require us to
develop our own assumptions. These inputs include certain
pricing models, discounted cash flow methodologies and similar techniques
that use significant unobservable
inputs.
|
Our
commodity derivative contracts are exchange-traded futures and exchange-traded
option contracts. The fair value of these exchange-traded derivative
contracts is based on unadjusted quoted prices in active markets and is,
therefore, included in Level 1. See Note 15 for additional
information on our derivative instruments.
The fair
value of our interest rate swaps is based on indicative broker price
quotations. These derivatives are included in Level 3 of the fair
value hierarchy because broker price quotations used to measure fair value are
indicative quotations rather than quotations whereby the broker or dealer is
ready and willing to transact. However, the fair value of these Level
3 derivatives is not based upon significant management assumptions or subjective
inputs.
We
generally apply fair value techniques on a non-recurring basis associated with
(1) valuing the potential impairment loss related to goodwill pursuant to SFAS
142, and (2) valuing potential impairment loss related to long-lived assets
accounted for pursuant to SFAS 144.
GENESIS
ENERGY, L.P.
NOTES
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Assets
and liabilities measured at fair value on a recurring basis are summarized
below:
|
|
Carrying
Amount
|
|
|
Quoted
Prices in Active Markets for Identical Assets
(Level
1)
|
|
|
Significant
Other Observable Inputs
(Level
2)
|
|
|
Significant
Unobservable Inputs
(Level
3)
|
|
Crude
oil and petroleum products derivative instruments (based on quoted market
prices on NYMEX)
|
|
$ |
(12,320 |
) |
|
$ |
(12,320 |
) |
|
$ |
- |
|
|
$ |
- |
|
Interest
rate swaps
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(216 |
) |
19. Income
Taxes
We are
not a taxable entity for federal income tax purposes. As such, we do
not directly pay federal income taxes. Our taxable income or loss is
includible in the federal income tax returns of each of our
partners.
A portion
of the operations we acquired in the Davison transaction are owned by
wholly-owned corporate subsidiaries that are taxable as
corporations. We pay federal and state income taxes on these
operations. The income taxes associated with these operations are
accounted for in accordance with SFAS 109 “Accounting for Income
Taxes.”
In May
2006, the State of Texas enacted a law which will require us to pay a tax of
0.5% on our “margin,” as defined in the law, beginning in 2008 based on our 2007
results. The “margin” to which the tax rate will be applied generally
will be calculated as our revenues (for federal income tax purposes) less the
cost of the products sold (for federal income tax purposes), in the State of
Texas.
For the
nine months ended September 30, 2008, we have provided current tax expense in
the amount of $3.1 million as the estimate of the taxes that will be owed on our
income for the period, and a deferred tax benefit of $4.3 million related to
temporary differences, related primarily to differences between amortization of
intangible assets for financial reporting and tax purposes. For the
three months ended September 30, 2008, we provided a current tax benefit in the
amount of $2.5 million and deferred tax expense of $1.0 million. We
recorded an increase of $1.3 million in the liability for uncertain tax benefits
during the nine months ended September 30, 2008. This increase was
attributable to uncertain tax positions associated with deferred tax liabilities
and goodwill.
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:
|
·
|
Available
Cash before Reserves
|
|
·
|
Liquidity
and Capital Resources
|
|
·
|
Commitments
and Off-Balance Sheet Arrangements
|
|
·
|
New
Accounting Pronouncements
|
In the
discussions that follow, we will focus on two measures that we use to manage our
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 revenues less cost of sales and
operating expenses (excluding depreciation and amortization) plus our equity in
the operating income of joint ventures. A reconciliation of segment
margin to income from continuing operations is included in our segment
disclosures in Note 11 to the consolidated financial statements.
Available
Cash before Reserves (a non-GAAP measure) is net income as adjusted for specific
items, the most significant of which are the elimination of gains and losses on
asset sales (except those from the sale of surplus assets), the addition of
non-cash expenses (such as depreciation), the substitution of cash generated by
our joint ventures in lieu of our equity income attributable to our joint
ventures, and the subtraction of maintenance capital expenditures, which are
expenditures that are necessary to sustain existing (but not to provide new
sources of) cash flows. 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
In the
third quarter of 2008, we reported net income of $10.8 million, or $0.25 per
common unit. Non-cash depreciation and amortization totaling $18.1
million reduced net income during the third quarter. For the nine
months ended September 30, 2008, we generated net income of $19.7 million, or
$0.47 per common unit.
During
the third quarter of 2008, we generated $23.6 million of Available Cash before
Reserves, and we will distribute $13.7 million to holders of our common units
and general partner for the third quarter. During the third quarter
of 2008, cash provided by operating activities was $33.5 million.
The third
quarter of 2008 was the fourth full quarter that included the operations
acquired from the Davison family in July 2007. The increases in
Available Cash before Reserves resulting from this acquisition enabled us to
declare our thirteenth consecutive increase in our quarterly
distribution. On October 10, 2008, we announced that our distribution
to our common unitholders relative to the third quarter of 2008 will be $0.3225
per unit (to be paid in November 2008). This distribution
amount represents a 19% increase from our distribution of $0.27 per unit for the
third quarter of 2007. During the third quarter of 2008, we paid a
distribution of $0.315 per unit related to the second quarter of
2008.
The
current economic crisis has restricted the availability of credit and access to
capital in our business environment. We are monitoring the impact
that these conditions may have on our operations. We believe that our
current cash balances, future internally-generated funds and funds available
under our credit facility will provide sufficient resources to meet our working
capital liquidity needs for the foreseeable future. With the current
conditions in the credit and equity markets, there may be limits on our ability
to issue new debt or equity financing.
Available
Cash before Reserves
Available
Cash before Reserves for the three and nine months ended September 30, 2008 is
as follows (in thousands):
|
|
Three
Months
Ended
September
30, 2008
|
|
|
Nine
Months
Ended
September
30, 2008
|
|
Net
income
|
|
$ |
10,763 |
|
|
$ |
19,736 |
|
Depreciation
and amortization
|
|
|
18,100 |
|
|
|
51,610 |
|
Cash
received from direct financing leases not included in
income
|
|
|
893 |
|
|
|
1,437 |
|
Cash
effects of sales of certain assets
|
|
|
147 |
|
|
|
573 |
|
Effects
of available cash generated by investments in joint ventures not included
in income
|
|
|
401 |
|
|
|
1,467 |
|
Cash
effects of stock appreciation rights plan
|
|
|
(113 |
) |
|
|
(384 |
) |
Loss
on asset disposals
|
|
|
(58 |
) |
|
|
36 |
|
Non-cash
tax expense (benefits)
|
|
|
(2,462 |
) |
|
|
(3,388 |
) |
Other
non-cash credits
|
|
|
(2,136 |
) |
|
|
(2,596 |
) |
Maintenance
capital expenditures
|
|
|
(1,983 |
) |
|
|
(2,967 |
) |
Available
Cash before Reserves
|
|
$ |
23,552 |
|
|
$ |
65,524 |
|
We have
reconciled Available Cash before Reserves (a non-GAAP measure) to cash flow from
operating activities (the GAAP measure) for the three and nine months ended
September 30, 2008 below. For the three and nine months ended
September 30, 2008, cash flows provided by operating activities were $33.5
million and $56.2 million, respectively.
This
quarterly report includes the financial measure of Available Cash before
Reserves, which is a “non-GAAP” measure because it is not contemplated by or
referenced in accounting principles generally accepted in the U.S., also
referred to as GAAP. The accompanying schedule provides a
reconciliation of this non-GAAP financial measure to its most directly
comparable GAAP financial measure. Our non-GAAP financial measure
should not be considered as an alternative to GAAP measures such as net income,
operating income, cash flow from operating activities or any other GAAP measure
of liquidity or financial performance. We believe that investors
benefit from having access to the same financial measures being utilized by
management, lenders, analysts, and other market participants.
Available
Cash before Reserves, also referred to as discretionary cash flow, is commonly
used as a supplemental financial measure by management and by external users of
financial statements, such as investors, commercial banks, research analysts and
rating agencies, to assess: (1) the financial performance of our assets without
regard to financing methods, capital structures, or historical cost basis; (2)
the ability of our assets to generate cash sufficient to pay interest cost and
support our indebtedness; (3) our operating performance and return on capital as
compared to those of other companies in the midstream energy industry, without
regard to financing and capital structure; and (4) the viability of projects and
the overall rates of return on alternative investment
opportunities. Because Available Cash before Reserves excludes some,
but not all, items that affect net income or loss and because these measures may
vary among other companies, the Available Cash before Reserves data presented in
this Quarterly Report on Form 10-Q may not be comparable to similarly titled
measures of other companies. The GAAP measure most directly
comparable to Available Cash before Reserves is net cash provided by operating
activities.
Available
Cash before Reserves is a liquidity measure used by our management to compare
cash flows generated by us to the cash distribution paid to our limited partners
and general partner. This is an important financial measure to our
public unitholders since it is an indicator of our ability to provide a cash
return on their investment. Specifically, this financial measure aids
investors in determining whether or not we are generating cash flows at a level
that can support a quarterly cash distribution to the
partners. Lastly, Available Cash before Reserves (also referred to as
distributable cash flow) is the quantitative standard used throughout the
investment community with respect to publicly-traded
partnerships.
The
reconciliation of Available Cash before Reserves (a non-GAAP liquidity measure)
to cash flow from operating activities (the GAAP measure) for the three and nine
months ended September 30, 2008, is as follows (in thousands):
|
|
Three Months
Ended
September 30, 2008
|
|
|
Nine Months
Ended
September 30, 2008
|
|
Cash
flows from operating activities
|
|
$ |
33,534 |
|
|
$ |
56,230 |
|
Adjustments
to reconcile operating cash flows to Available Cash:
|
|
|
|
|
|
|
|
|
Maintenance
capital expenditures
|
|
|
(1,983 |
) |
|
|
(2,967 |
) |
Proceeds
from sales of certain assets
|
|
|
147 |
|
|
|
573 |
|
Amortization
of credit facility issuance fees
|
|
|
(427 |
) |
|
|
(962 |
) |
Effects
of available cash generated by investments in joint ventures not included
in cash flows from operating activities
|
|
|
35 |
|
|
|
447 |
|
Available
cash from NEJD pipeline not yet received and included in cash flows from
operating activities
|
|
|
- |
|
|
|
1,723 |
|
Net
effect of changes in operating accounts not included in calculation of
Available Cash
|
|
|
(7,754 |
) |
|
|
10,480 |
|
Available
Cash before Reserves
|
|
$ |
23,552 |
|
|
$ |
65,524 |
|
Results
of Operations
The
contribution of each of our segments to total segment margin in the third
quarters and nine-month periods of 2008 and 2007 was as follows:
|
|
Three Months Ended
September 30,
|
|
|
Nine Months Ended
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
thousands)
|
|
|
(in
thousands)
|
|
Pipeline
transportation
|
|
$ |
10,642 |
|
|
$ |
3,763 |
|
|
$ |
22,113 |
|
|
$ |
8,858 |
|
Refinery
services
|
|
|
13,041 |
|
|
|
8,545 |
|
|
|
44,245 |
|
|
|
8,545 |
|
Industrial
gases
|
|
|
3,505 |
|
|
|
3,232 |
|
|
|
9,324 |
|
|
|
8,804 |
|
Supply
and logistics
|
|
|
13,690 |
|
|
|
4,960 |
|
|
|
29,443 |
|
|
|
7,986 |
|
Total
segment margin
|
|
$ |
40,878 |
|
|
$ |
20,500 |
|
|
$ |
105,125 |
|
|
$ |
34,193 |
|
Pipeline
Transportation Segment
Operating
results for our pipeline transportation segment were as
follows:
|
|
Three Months Ended
September 30,
|
|
|
Nine Months Ended
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
thousands)
|
|
|
(in
thousands)
|
|
Crude
oil tariffs and revenues from direct financing leases of crude oil
pipelines
|
|
$ |
4,228 |
|
|
$ |
3,912 |
|
|
$ |
12,333 |
|
|
$ |
10,907 |
|
Sales
of crude oil pipeline loss allowance volumes
|
|
|
2,333 |
|
|
|
1,845 |
|
|
|
7,659 |
|
|
|
4,985 |
|
CO2
tariffs and revenues from direct financing leases of CO2
pipelines
|
|
|
6,647 |
|
|
|
79 |
|
|
|
8,971 |
|
|
|
241 |
|
Tank
rental reimbursements and other miscellaneous revenues
|
|
|
35 |
|
|
|
164 |
|
|
|
468 |
|
|
|
491 |
|
Total
revenues from crude oil and CO2
tariffs, including revenues from direct financing leases
|
|
|
13,243 |
|
|
|
6,000 |
|
|
|
29,431 |
|
|
|
16,624 |
|
Revenues
from natural gas tariffs and sales
|
|
|
1,182 |
|
|
|
895 |
|
|
|
4,165 |
|
|
|
3,394 |
|
Natural
gas purchases
|
|
|
(1,136 |
) |
|
|
(817 |
) |
|
|
(3,990 |
) |
|
|
(3,164 |
) |
Pipeline
operating costs
|
|
|
(2,647 |
) |
|
|
(2,315 |
) |
|
|
(7,493 |
) |
|
|
(7,996 |
) |
Segment
margin
|
|
$ |
10,642 |
|
|
$ |
3,763 |
|
|
$ |
22,113 |
|
|
$ |
8,858 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barrels
per day on crude oil pipelines:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
64,676 |
|
|
|
60,311 |
|
|
|
66,043 |
|
|
|
58,531 |
|
Mississippi
System
|
|
|
25,232 |
|
|
|
22,818 |
|
|
|
24,323 |
|
|
|
20,938 |
|
Jay
System
|
|
|
13,817 |
|
|
|
14,596 |
|
|
|
13,422 |
|
|
|
13,027 |
|
Texas
System
|
|
|
25,627 |
|
|
|
22,897 |
|
|
|
28,298 |
|
|
|
24,566 |
|
Three
Months Ended September 30, 2008 Compared with Three Months Ended September 30,
2007
Pipeline
segment margin for the third quarter of 2008 increased $6.9 million as compared
to the third quarter of 2007. The significant components of this
change are an increase in revenues from crude oil tariffs and related sources of
$0.3 million, an increase in revenues from sales of pipeline loss allowance
volumes of $0.5 million and an increase in revenues from CO2 financing
leases and tariffs of $6.6 million. Pipeline operating costs
increased $0.3 million between the two periods.
Tariff
and direct financing lease revenues from our crude oil pipelines increased $0.3
million primarily due to volume increases on our Texas and Mississippi pipeline
systems totaling 5,144 barrels per day. Volumes on the Mississippi and Texas
systems were affected by two hurricanes in the third quarter that disrupted
operations for a brief period. The tariff on the Mississippi System
is an incentive tariff, such that the average tariff per barrel decreases as the
volumes increase, however the overall impact of an annual tariff increase on
July 1, 2008 with the volume increase still resulted in improved revenues from
this system by $0.1 million. As a result of the annual tariff
increase on July 1, 2008, average tariffs on the Jay System increased by
approximately $0.10 per barrel between the two periods. This tariff
increase partially offset the effects of a decrease in volumes of 779 barrels
per day, with the resulting increase in revenues from this system of $0.1
million. Volumes on the Texas System increased by 2,730 barrels per
day, resulting in an increase in revenues of $0.1 million. The impact
on revenues of increases in volumes on the Texas System is not very significant
due to the relatively low tariffs on that system. Approximately 77%
of the volume on that system is shipped on a tariff of $0.31 per
barrel.
Higher
market prices for crude oil added $0.5 million to pipeline loss allowance
revenues. Average crude oil market prices have increased
approximately $40 per barrel between the two quarters. Based on
historic volumes, a change in crude oil market prices of $10 per barrel has the
effect of decreasing or increasing our pipeline loss allowance revenues by
approximately $0.1 million per month.
CO2 tariff and
direct financing lease revenues increased $6.6 million between the two quarters,
with $4.4 million attributable to the NEJD pipeline and $2.2 million to the Free
State pipeline. The average volume transported on the Free State
pipeline for the third quarter of 2008 was 155 MMcf per day, with the
transportation fee and the minimum payment totaling $1.9 million and $0.3
million, respectively.
Historically,
the largest operating costs in our crude oil pipeline segment have consisted of
personnel costs, power costs, maintenance costs, and costs of compliance with
regulations. Some of these costs are not predictable, such as
failures of equipment or power cost increases. We perform regular
maintenance on our assets in an effort to keep them in good operational
condition and to minimize cost increases. In the third quarter of
2008, our power costs were $0.1 million more than in the prior period; the
credit to expense for our stock appreciation rights plan was $0.1 million less
than in the prior year quarter; and costs for regulatory testing of the
pipelines and tanks were $0.2 million greater than in the 2007
quarter. Offsetting these increases was a decrease of $0.1 million in
tank rental expense related to the change in the rental rate. This
rental rate change affected the rental income we receive from a third party as
reimbursement for tank rental expense we pay.
Nine
Months Ended September 30, 2008 Compared with Nine Months Ended September 30,
2007
For the
nine month periods, pipeline segment margin increased $13.3
million. $1.4 million of this increase is attributable to crude oil
tariffs and related sources; $2.7 to pipeline loss allowance revenue increases
and $8.7 million to CO2 pipelines;
and $0.5 million to a decrease in pipeline operating costs.
Revenues
from transportation on the Mississippi System increased $0.4 million from an
increase in volumes of 3,385 barrels per day. As discussed above, the
tariff for the Mississippi System is an incentive tariff under which incremental
volumes result in a smaller tariff per barrel.
Volumes
on the Jay System increased 395 barrels per day, increasing revenue by $0.4
million. The volume increase is due in part to the renewed interest
by oil producers in the fields in the area and additional volumes we are
bringing to the system from other locations. Volumes fluctuated slightly during
the 2008 period due to maintenance at several separation plants providing
volumes to the system and maintenance work on a tank which resulted in diversion
of volumes to other entry points on the pipeline. Variances in the
average tariff per barrel on this system are affected by the annual tariff
increase each year in July and the varying tariff rates depending on the
distance volumes are transported.
Volumes
on the Texas System increased 3,732 barrels per day, contributing $0.6 million
of additional revenue between the six-month periods. Shippers on the
system have increased the crude oil production they acquire and ship on our
pipeline to their refineries.
Revenues
from pipeline loss allowance volumes have increased by $2.7 million due to the
significant increase in the average market prices for crude oil between the
first nine months of 2007 and the first nine months of 2008.
The
decrease in pipeline operating costs between the two nine-month periods is
attributable primarily to our stock appreciation rights plan. In the
first nine months of 2007, we included $0.5 million in pipeline operating costs
for the plan, resulting from the increase in our common unit price of $8.37
during the period. In the 2008 period, our common unit price
decreased by $9.21, resulting in a credit to expense of $0.2 million, for a
total variation of $0.7 million. Partially offsetting this decrease
was an increase of $0.3 million in costs related to integrity testing of the
pipelines and tank inspection costs. The remaining variation in costs
resulted from slight changes in personnel costs, power costs and other
maintenance and operational expenses.
Refinery
Services Segment
We
acquired our refinery services segment in the Davison transaction in July
2007. That segment provides services to eight refining operations
primarily located in Texas, Louisiana, and Arkansas. In our
processing, we apply proprietary technology that uses large quantities of
caustic soda (the primary input used by our proprietary process). Our
refinery services business generates revenue by providing a service for which it
receives NaHS as compensation and by selling the NaHS, the by-product of our
process, to approximately 100 customers. Some of the largest
customers for the NaHS are copper mining companies in the United States and
South America and paper mills in the United States.
The
largest cost component of providing the service is acquiring and delivering
caustic soda to our operations. Caustic soda, or NaOH, is the
scrubbing agent introduced in the sour gas stream to remove the sulfur and
generate the by-product, NaHS. Therefore the contribution to segment
margin involves the revenues generated from the sales of NaHS less our total
cost of providing the services, including the costs of acquiring and delivering
caustic soda to our service locations. We estimate that approximately
60% of our NaHS sales by volume are indexed, in one form or another, to our cost
of caustic soda. We engage in other activities such as selling
caustic soda, buying NaHS from other producers for re-sale to our customers and
buying and selling sulfur, the financial results of which are also reported in
our refinery services segment.
Segment
margin from our refinery services for the third quarter of 2008 was $13.0
million, which when combined with the first half segment margin of $31.2
million, totals $44.2 million for the first nine months of 2008. As we have only
owned the operations of this segment since July 25, 2007, we are providing
information comparing the first, second and third quarters of
2008. We believe the most meaningful measure of our success in this
segment is the revenue generated from sales of NaHS after deducting delivery
expenses, from both the volumes received as payment for rendering service as
well as volumes obtained from third party producers. Included in the
table below is information on our NaHS sales activity in the first three
quarters of 2008.
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
March
31, 2008
|
|
|
June
30, 2008
|
|
|
September
30, 2008
|
|
|
September
30, 2008
|
|
NaHS
Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
Dry
Short Tons (DST)
|
|
|
41,742 |
|
|
|
46,655 |
|
|
|
38,319 |
|
|
|
126,716 |
|
Net
Sales
|
|
$ |
27,530 |
|
|
$ |
37,664 |
|
|
$ |
37,515 |
|
|
$ |
102,709 |
|
Contribution
Margin per DST
|
|
$ |
260 |
|
|
$ |
342 |
|
|
$ |
289 |
|
|
$ |
299 |
|
Our
average quarterly sales volume of NaHS for the first nine months was 42,239
DST. Sales volumes between quarters may fluctuate based on the timing
of availability of capacity on container ships for product to be sold and loaded
for delivery to customers in South America. Additionally the ability
to ship product in the third quarter was hindered by Hurricanes Gustav and Ike,
which disrupted the Port of Houston where product is loaded. The average sales
price of NaHS has increased from $660 per DST in the first quarter of 2008 to
$807 per DST in the second quarter of 2008 to $979 per DST in the third
quarter. We increased our sales prices to compensate for increased
raw materials and increased transportation costs for both delivery of raw
materials to us and product to our customers. As we expand our sour
gas processing services to additional refineries, we expect these NaHS sales
volumes to continue to increase. The increased worldwide demand for
copper in 2008 has contributed to the increased demand for NaHS by mining
customers in both the United States and South America.
The
largest input to processing of the sour gas streams that result in NaHS is
caustic soda. We also market caustic soda and sulfidic caustic not
used for our processing. During the third quarter of 2008, our sales
price for caustic soda was $695 per DST, an increase of $164 per DST over the
market price in the second quarter of 2008. We have generally been
successful in increasing the sales price of NaHS to compensate for increases in
caustic soda prices and maintaining or expanding the contribution of NaHS sales
to our segment margin.
During
the second quarter, we extended a contract with a refiner for an additional
ten-year period. Contract extensions with major customers and changes
to pricing in the contracts helped increase our contribution margin per DST by
32%.
Industrial
Gases Segment
Our
industrial gases segment includes the results of our CO2 sales to
industrial customers and our share of the operating income of our 50% joint
venture interests in T&P Syngas and Sandhill.
CO2 -
Industrial Customers - We supply CO2 to
industrial customers under seven long-term CO2 sales
contracts. The sales contracts contain provisions for adjustments for
inflation to sales prices based on the Producer Price Index, with a minimum
price.
Our
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 historical data for 2004 through the first quarter
of 2008, 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. Volumes sold in each of
the last five quarters were as follows:
|
|
Sales
Mcf per Day
|
|
|
|
|
|
Third
Quarter 2007
|
|
|
85,705 |
|
Fourth
Quarter 2007
|
|
|
80,667 |
|
First
Quarter 2008
|
|
|
73,062 |
|
Second
Quarter 2008
|
|
|
79,968 |
|
Third
Quarter 2008
|
|
|
83,816 |
|
Operating
Results - Operating results from our industrial gases segment were as
follows:
|
|
Three Months Ended
September 30,
|
|
|
Nine Months Ended
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
thousands)
|
|
|
(in
thousands)
|
|
Revenues
from CO2
sales
|
|
$ |
4,792 |
|
|
$ |
4,373 |
|
|
$ |
13,112 |
|
|
$ |
11,816 |
|
CO2
transportation and other costs
|
|
|
(1,503 |
) |
|
|
(1,502 |
) |
|
|
(4,166 |
) |
|
|
(3,927 |
) |
Equity
in (losses) earnings of joint ventures
|
|
|
216 |
|
|
|
361 |
|
|
|
378 |
|
|
|
915 |
|
Segment
margin
|
|
$ |
3,505 |
|
|
$ |
3,232 |
|
|
$ |
9,324 |
|
|
$ |
8,804 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes
per day:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2
sales - Mcf
|
|
|
83,816 |
|
|
|
85,705 |
|
|
|
78,967 |
|
|
|
76,035 |
|
Three
Months Ended September 30, 2008 Compared with Three Months Ended September 30,
2007
The
increase in margin from the industrial gases segment between the two quarterly
periods was the result of an increase in the average sales price of CO2
to our customers. Variations in the volumes sold among
contracts with different pricing terms combined with inflation adjustment
factors in the sales contracts resulted in the average sales price of the
CO2
increasing $0.07 per Mcf, or 12%. Volumes declined in total,
with customers with contractually higher pricing terms increasing volumes
purchased and volumes sold under lower priced contracts decreasing.
The
increased volumes and the inflation adjustment to the rate we pay Denbury to
transport the CO2
to our customers resulted in greater CO2
transportation costs in the third quarter of 2008 when compared to the 2007
quarter. The transportation rate increase between the two quarters
was 4.3%.
Our share
of the operating income from our equity investees, T&P Syngas and Sandhill
was $0.2 million and $0.4 million, respectively, for the three months ended
September 30, 2008 and 2007. We received cash distributions from the
joint ventures totaling $0.6 million during the quarter.
Nine
Months Ended September 30, 2008 Compared with Nine Months Ended September 30,
2007
For the
nine month periods, our industrial gases segment margin increased by $0.5
million. CO2 sales
revenues, net of transportation costs, increased $1.0 million and our share of
the equity in the earnings of joint ventures decreased by $0.5
million. CO2 sales
volumes increased by 2,932 Mcf per day; the average sales price per Mcf
increased by $0.04; and the average transportation rate per Mcf increased by
$0.01. Although equity in our joint ventures declined, the decrease
was due to non-cash charges, and distributions to us during the nine-month
period in 2008 were $1.9 million, an increase of $0.2 million over the
distributions in the same period of 2007. Due to maintenance that is
expected to occur in late 2008 and early 2009, we expect the distributions to us
from our equity investees in 2009 to be approximately half of the 2008
levels.
Additional
discussion of our joint ventures is included in Note 8 of the Notes to the
Unaudited Consolidated Financial Statements.
Supply
and Logistics Segment
Operating
results from our supply and logistics segment were as follows:
|
|
Three Months Ended
September 30,
|
|
|
Nine Months Ended
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
thousands)
|
|
|
(in
thousands)
|
|
Supply
and logistics revenue
|
|
$ |
556,396 |
|
|
$ |
317,653 |
|
|
$ |
1,555,991 |
|
|
$ |
691,220 |
|
Crude
oil and products costs
|
|
|
(521,779 |
) |
|
|
(304,129 |
) |
|
|
(1,471,254 |
) |
|
|
(665,939 |
) |
Operating
costs
|
|
|
(20,927 |
) |
|
|
(8,564 |
) |
|
|
(55,294 |
) |
|
|
(17,295 |
) |
Segment
margin
|
|
$ |
13,690 |
|
|
$ |
4,960 |
|
|
$ |
29,443 |
|
|
$ |
7,986 |
|
Three
Months Ended September 30, 2008 as Compared to Three Months Ended September 30,
2007
The 2008
third quarter includes three complete months of the operations acquired from the
Davison family as compared to two months in 2007. We also acquired
the inland marine transportation operations of Grifco in the third quarter of
2008. The effects on the change in segment margin from not having
these operations in both periods accounts for approximately $3.7 million of the
$8.7 million increase in segment margin between the two periods. See
additional discussion of the factors that influence the operations acquired from
the Davison family below in the year-to-date comparison.
Segment
margin for the third quarter of 2008 includes a mark-to-market unrealized gain
under SFAS 133 of approximately $0.9 million as compared to a loss of
approximately $0.7 million for third quarter of 2007. The
mark-to-market gain in the 2008 period was caused by the decline in crude oil
market prices in the third quarter of 2008. In the third quarter of
2007, prices increased resulting in a mark-to-market loss. This gain
and loss are primarily related to risk management strategies for which we
currently do not receive hedge accounting due to various factors including that
the required documentation is extensive and some amount of ineffectiveness is
likely. These gains and losses are generally offset by future or
current physical positions that do not receive mark-to market treatment because
they qualify for the normal purchase and sale exception under SFAS
133. As the physical positions are realized through purchase or sale
of crude oil or petroleum products, we will recognize the offsetting
position. In total the difference in this mark-to-market gain and
loss accounted for $1.6 million of the variation in segment margin between the
quarterly periods. See Note 15 to the Consolidated Financial
Statements for discussion of our hedging activities.
Volumes
of crude oil and petroleum products sold in the third quarter of 2008 were
approximately 54,000 barrels per day. The types of petroleum products
sold in a period impact the contribution of these volumes to segment
margin. In 2008, we have focused our petroleum products marketing
efforts on products that efficiently utilize the combination of our trucking
capacity, our crude oil and petroleum products terminals and our access to
marine transportation through the Grifco acquisition. These efforts
contributed most of the additional margin in the period.
Offsetting
the increase in segment margin is an increase in the costs to operate our
equipment utilized in our supply and logistics activities. Our
tractor-trailers travel over 6 million miles quarterly. Between the
third quarter of 2008 and 2007, we have seen an increase in diesel fuel prices
of approximately 50%, equating to an increase in the costs to operate our fleet
of approximately $1.1 million. Through fuel adjustment charges put in
place in many contracts during the second quarter of 2008, we have been able to
recoup the effects on segment margin that these increases might have otherwise
had.
Nine
Months Ended September 30, 2008 as Compared to Nine Months Ended September 30,
2007
The
portions of our supply and logistics operations acquired in the Davison
transaction added approximately $19.8 million to our supply and logistics
segment margin for the nine months ended September 30, 2008. Our
historic crude oil operations provided an increase to supply and logistics
segment margin of $8.1 million and the barge operations added in July 2008 added
$1.5 million, for total segment margin of $29.4 million.
As we
only owned the operations acquired from the Davison family for two of the nine
months in 2007, a meaningful comparison between the two periods cannot be
made. Changes that we have made to this business in 2008 had a
significant impact by focusing on products and operations that contribute the
largest possible margin and utilize our asset base. In the three
quarters of 2008, we have seen an improvement in segment margin from these
operations from $3.6 million in the first quarter to $7.0 million in the second
quarter to $9.2 million in the third quarter.
Significant
factors affecting the operations of the Davison assets include the availability
of products for our use in blending to a quality that meets the requirements of
our customers and the costs of the transportation services we
provide. A key factor influencing our transportation services is the
price of diesel for operating our trucks. We use over 900,000 gallons
of diesel fuel per quarter. While we include fuel price adjustments
in the pricing for many of our transportation services to third parties, we can
experience timing differences between when we pay higher prices for the fuel and
when we are able to pass that cost through to our customers.
The
significant improvement in the segment margin contribution between the quarters
was primarily a result of an improvement in the availability of products for
blending and an improvement in the ability of river barges to access our
terminals and product supplies for our customers. We utilize our
terminal assets to maximize our refined products activities. Because
of river flooding on the Red River and other rivers connected to the Mississippi
River system during the first quarter of 2008, our customers were limited in
their ability to access our product supply. In the second quarter of
2008, river levels returned to normal and barge loading became more
consistent. Our access to barges and declining diesel prices in the
third quarter of 2008 contributed the additional segment margin in the third
quarter.
Results
from our historic crude oil operations improved by $3.1 million between the nine
month periods. Grade differentials related to the chemical
composition of the crude oil and the desire in the market for that grade of
crude oil create fluctuations in the differentials that can affect the margin we
make on our crude oil transactions. Between the nine month periods,
those opportunities added $5.4 million to segment margin, which was offset by a
$2.3 million increase in field operating costs in our crude oil
operations. Fuel costs increased over $1.4 million, personnel costs
increased $0.3 million, regulatory compliance testing and maintenance at our
Port Hudson facility increased $0.6 million and other repair and maintenance
cost increased $0.5 million, but a decrease in the expense related to our stock
appreciation rights plan offset $0.9 million of that difference. The remaining
increase in costs of $0.4 million was attributable to numerous
factors.
Market
Volatility
As a
result of recent volatility in crude oil markets, we wanted to reiterate the
risk management practices of our supply and logistics segment. Our
risk management policy requires that, with limited specific exceptions, our
transactions be balanced (back-to-back) purchases and sales. We
experience limited commodity risk, because our risk management practices help
limit our exposure to price fluctuations. Our policies require us to
hedge inventory above certain base levels needed for operations, and our
policies and procedures are consistently monitored, with daily reports reviewed
by persons not directly involved in the supply and logistics
operations.
We use
derivatives as an effective element of our risk management strategy that, while
not always meeting accounting requirements to be treated as hedges for financial
reporting, help reduce our exposure to market price fluctuations. The
use of derivatives is limited to managing or effecting balanced purchase and
sales or otherwise managing commodity risk with respect to physical
inventory. As discussed in Note 15, for financial accounting and
reporting purposes, these derivative instruments that are not treated as hedges
are reflected in our Unaudited Consolidated Balance Sheets at fair value and
changes in fair value are reflected in our earnings. These derivative
instruments consist almost exclusively of futures and options contracts on the
New York Mercantile Exchange (NYMEX) financial market.
Like any
participant in the commodities markets, we post margin or receive margin related
to our hedging instruments on a daily basis, depending on the fluctuations in
the prices of the commodities underlying the hedging instruments. At
September 30, 2008 and October 31, 2008, our margin balance requirement
including initial margin requirements totaled less than $1.5
million. During the past year while we have owned the Davison assets,
our margin requirement has not exceeded $1.5 million.
Additionally,
we regularly review the credit standing of our customers. When
circumstances warrant, we will require our customers to provide us with credit
support in the form of letters of credit, prepayments or right of
offset. The majority of the accounts receivable reflected on our
consolidated balance sheets relate to our crude oil operations. Those
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. Accounts receivable in our fuel procurement
business also settle within 30 days of delivery. Approximately 80% of
the $202.1 million aggregate receivables on our consolidated balance sheet at
September 30, 2008 relate to our crude oil and fuel procurement
businesses.
Other
Costs, Interest, and Income Taxes
General
and administrative expenses. General
and administrative expenses consisted of the following:
|
|
Three Months Ended
September 30,
|
|
|
Nine Months Ended
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
thousands)
|
|
|
(in
thousands)
|
|
Expenses
excluding bonus expense and effects of stock appreciation rights
plan
|
|
$ |
8,422 |
|
|
$ |
5,212 |
|
|
$ |
24,151 |
|
|
$ |
10,401 |
|
Bonus
plan expense
|
|
|
1,416 |
|
|
|
315 |
|
|
|
3,863 |
|
|
|
1,194 |
|
Stock
appreciation rights plan (credit) expense
|
|
|
(599 |
) |
|
|
(803 |
) |
|
|
(1,085 |
) |
|
|
2,057 |
|
Total
general and administrative expenses
|
|
$ |
9,239 |
|
|
$ |
4,724 |
|
|
$ |
26,929 |
|
|
$ |
13,652 |
|
Between
the third quarter periods, general and administrative expenses increased by $4.5
million. Several factors contributed to this
increase. These factors are:
|
-
|
We
acquired the Davison business at the end of July in 2007. As a
result, the third quarter of 2007 only included two months of expense
related to the administrative personnel at the Davison
locations. This difference resulted in an increase in 2008
third quarter expense as compared to 2007 of $1.3 million, however average
monthly expense was consistent between the two
periods.
|
|
-
|
We
acquired DG Marine in July 2008. The general and administrative
expense related to this operation was $0.5 million in the third quarter of
2008.
|
|
-
|
Professional
services fees increased $0.9 million between the two periods as a result
of more complex legal, financial accounting and tax matters to be
addressed.
|
|
-
|
Bonus
plan expense increase $1.0 million between the two quarters as a result of
the additional personnel covered by the plan and improved performance of
the partnership.
|
|
-
|
The
credit to expense in the third quarter related to our stock appreciation
rights plan was $0.2 million less in the 2008
period.
|
|
-
|
The
remaining $0.6 million increase in expense was related to several items
including increased personnel costs at the corporate offices, increased
travel costs and costs related to moving to new corporate
offices.
|
For the
nine-month periods, general and administrative expenses increased $13.3 million
for many of the same factors. The difference in general and
administrative expenses related to the Davison locations between the periods was
$6.6 million. Bonus plan expense was $2.7 million more. DG
Marine general and administrative expenses accounted for $0.5
million. Professional services fees accounted for $5.0 million of the
increase. Costs related to personnel in the headquarters office,
travel costs and other administrative expenses accounted for $1.6 million of the
increase. Offsetting these increases was a decline in the expense for
our stock appreciation rights plan of $3.1 million.
Depreciation
and amortization expense. Depreciation and
amortization expense increased in the third quarter and nine-month periods
primarily as a result of the depreciation and amortization expense recognized on
the fixed and intangible assets acquired in the Davison, Port Hudson and Grifco
acquisitions. Depreciation and amortization totaled $18.1 million for
the third quarter and $51.6 million for the nine months.
The
intangibles acquired in the Davison and Grifco acquisitions are being amortized
over the period during which the intangible asset is expected to contribute to
our future cash flows. As intangible assets such as customer
relationships and trade names are generally more valuable in the first years
after an acquisition, the amortization we will record on these assets will be
greater in the initial years after the acquisition. As a result, we
expect to record significantly more amortization expense related to our
intangible assets in 2008 through 2010 than in subsequent years. See Note 7 to
the Unaudited Consolidated Financial Statements for information on the amount of
amortization we expect to record in each of the next five years.
Interest
expense, net.
Interest
expense, net was as follows:
|
|
Three Months Ended
September 30,
|
|
|
Nine Months Ended
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
thousands)
|
|
|
(in
thousands)
|
|
Interest
expense, including commitment fees
|
|
$ |
3,516 |
|
|
$ |
4,728 |
|
|
$ |
7,229 |
|
|
$ |
5,226 |
|
Capitalized
interest
|
|
|
(47 |
) |
|
|
(27 |
) |
|
|
(148 |
) |
|
|
(33 |
) |
Amortization
of facility fees
|
|
|
167 |
|
|
|
141 |
|
|
|
497 |
|
|
|
274 |
|
Interest
expense, facility fees and commitment fees - DG Marine
|
|
|
965 |
|
|
|
- |
|
|
|
965 |
|
|
|
- |
|
Interest
income
|
|
|
(118 |
) |
|
|
(141 |
) |
|
|
(352 |
) |
|
|
(219 |
) |
Net
interest expense
|
|
$ |
4,483 |
|
|
$ |
4,701 |
|
|
$ |
8,191 |
|
|
$ |
5,248 |
|
The
Davison acquisition was partially financed with borrowings under our credit
facility beginning on July 25, 2007. In December 2007, we reduced our
debt with an equity offering. On May 30, 2008, we increased our debt
to fund the drop-down transactions. As a result of these debt
changes, our average outstanding debt balance increased $103.0 million over the
average outstanding debt balance in the third quarter of 2007. The
average interest rate on our debt, however, was 3.8% lower during the 2008
quarter, resulting in an overall decrease for the quarter for interest on our
credit facility of $1.2 million. DG Marine incurred interest expense
in the third quarter of $0.8 million under its credit
facility Additionally DG Marine recorded accretion of discount
on the payment to be made to Grifco upon successful launch of the barges under
construction. (See Note 3 to the Unaudited Consolidated Financial
Statements.) The net effect of these changes was a decrease in net
interest expense between the third quarter periods of $0.2
million. For the nine month periods, average outstanding debt under
our credit facility was $109.7 million greater in the 2008 period and our
average interest rate was 3.5% less. When combined with the interest
on the DG Marine credit facility and the accretion of the discount on the
payment to be made to Grifco, net interest expense for the nine month periods
increased $2.9 million.
Income
taxes.
A small
portion of the operations we acquired in the Davison transaction are owned by
wholly-owned corporate subsidiaries that are taxable as
corporations. As a result, the income tax expense we record relates
only to the operations of those corporations, and will vary from period to
period as a percentage of our income before taxes based on the percentage of our
income or loss that is derived from those corporations. In the 2008
third quarter and nine-month periods, we recorded an income tax benefit related
to the operations of those corporations.
Acquisitions
in 2008
Investment
in DG Marine Transportation, LLC
On July
18, 2008, we completed the acquisition of the inland marine transportation
business of Grifco Transportation, Ltd. (“Grifco”) and two of Grifco’s
affiliates through a joint venture with TD Marine, LLC, an entity formed by
members of the Davison family. (See discussion below on the
acquisition of the Davison family businesses in 2007.). TD Marine owns
(indirectly) a 51% economic interest in the joint venture, DG Marine,
and we own (directly and indirectly) a 49% economic interest. This
acquisition gives us the capability to provide transportation services of
petroleum products by barge and complements our other supply and logistics
operations.
Grifco
received initial purchase consideration of approximately $80 million, comprised
of $63.3 million in cash and $16.7 million, or 837,690 of our common
units. A portion of the units are subject to certain lock-up
restrictions. DG Marine acquired substantially all of Grifco’s assets, including
twelve barges, seven push boats, certain commercial agreements, and offices
.. Additionally, DG Marine and/or its subsidiaries acquired
the rights, and assumed the obligations, to take delivery of four new barges in
late third quarter of 2008 and four additional new barges early in first quarter
of 2009 (at a total price of approximately $27 million). Upon delivery of the
eight new barges, the acquisition of three additional push boats (at an
estimated cost of approximately $6 million), and after placing the barges and
push boats into commercial operations, DG Marine will be obligated to pay
additional purchase consideration of up to $12 million. The
estimated discounted present value of that $12 million obligation is included in
current liabilities in our consolidated balance sheets. At September
30, 2008, DG Marine had taken delivery of four of the new barges.
The
Grifco acquisition and related closing costs were funded with $50 million of
aggregate equity contributions from us and TD Marine, in proportion to our
ownership percentages, and with borrowings of $32.4 million under a revolving
credit facility which is non-recourse to us and TD Marine (other than with
respect to our investments in DG Marine). Although DG
Marine’s debt is non-recourse to us, our ownership interest in DG Marine is
pledged to secure its indebtedness. We funded our $24.5 million equity
contribution with $7.8 million of cash and 837,690 of our common units, valued
at $19.896 per unit, for a total value of $16.7 million. At closing,
we also redeemed 837,690 of our common units from the Davison family. The total
number of our outstanding common units did not change as a result of that
investment.
Drop-down
Transactions
We
completed two “drop-down” transactions with Denbury in 2008 involving two of
their existing CO2 pipelines
- the NEJD and Free State CO2
pipelines. We paid for these pipeline assets with $225 million in cash and
1,199,041 common units valued at $25 million based on the average closing price
of our units for the five trading days surrounding the closing date of the
transaction. We expect to receive approximately $30 million per annum, in the
aggregate, under the lease agreement for the NEJD pipeline and the Free State
pipeline transportation services agreement. Future payments for the
NEJD pipeline are fixed at $20.7 million per year during the term of the
financing lease, and the payments related to the Free State pipeline are
dependent on the volumes of CO2
transported therein, with a minimum monthly payment of $0.1
million.
On August
5, 2008, Denbury announced that the economic impact of an approved tax
accounting method change providing for an acceleration of tax deductions will
likely affect certain types of future asset “drop-downs” to
us. Transactions which are not sales for tax purposes for Denbury,
such as the lease arrangement for the NEJD pipeline, would not be affected
provided the transactions meet other tax structuring criteria for Denbury and
us. Transactions which constitute a sale for tax purposes for
Denbury, like the Free State pipeline transaction, are likely to be
discontinued. While Denbury has also stated it would consider other
options and ways to use us as a financing vehicle, there can be no assurances as
to the amount, or timing, of any potential future asset “drop-downs” from
Denbury to us.
Liquidity
and Capital Resources
Capital
Resources/Sources of Cash
We
anticipate that cash generated from our operations will be the primary source of
cash used to fund our distributions and our maintenance capital
expenditures. For the nine months ended September 30, 2008, cash
generated from our operations was $56.2 million. We periodically
utilize our existing credit facility to fund working capital
needs. We also expect to utilize our existing credit facility to fund
internal growth projects. Our credit facility has a maximum
facility amount of $500 million, of which up to $100 million may be used for
letters of credit. The borrowing base under the facility at September
30, 2008 exceeds $500million, and is recalculated quarterly and at the time of
acquisitions (however amounts committed by the lenders total $500
million). At September 30, 2008, our remaining availability under the
credit facility was $150.3 million and we had approximately $22 million of cash
on hand.
In the
last two years, we have adopted a growth strategy that has dramatically
increased our cash requirements. Our existing credit facility and
cash on hand give us approximately $170 million of growth capital. To
the extent any of our possible growth initiatives requires a greater amount of
capital, we would have to access new sources of capital, including public and
private debt and equity markets. Current conditions in the capital
markets for debt and equity may make the terms related to the cost of credit or
equity prohibitive in relation to the economics of an
acquisition. Additionally, availability of capital may be limited
while financial institutions and investors assess their liquidity
positions. Accordingly, no assurance can be made that we will be able
to raise the necessary funds on satisfactory terms to execute our growth
strategy. If we are unable to raise the necessary funds, we may be
required to defer our growth plans until such time as funds become
available.
The terms
of our credit facility also effectively limit the amount of distributions that
we may pay to our general partner and holders of common units. Such
distributions may not exceed the sum of the distributable cash generated for the
eight most recent quarters, less the sum of the distributions made with respect
to those quarters. See Note 9 of the Notes to the Unaudited Consolidated
Financial Statements.
At
September 30, 2008, DG Marine was not in technical compliance with the leverage
ratio or interest coverage ratio in its credit facility, primarily due to timing
of costs related to the start-up of operations as a new entity and the
acquisition of new vessels, and the effects of hurricanes on
operations. Based on the nature of the issues resulting in such
non-compliance and based on discussions with each of the banks comprising its
lending syndicate, the management of DG Marine currently believes DG Marine’s
lenders will agree to a waiver of the non-compliance and to an amendment to its
credit facility to adjust those ratios, the terms of which are still to be
determined, but which will result in DG Marine being in full compliance with the
terms of its credit agreement. DG Marine’s management does not
believe such non-compliance will materially and adversely affect its operations
or financial condition; however, until that joint venture complies with the
terms of its credit agreement, we will classify its outstanding debt as a
current liability on our balance sheet.
We are
monitoring the credit crisis, declining oil and petroleum products prices and a
weakening economic outlook to determine the extent of the impact on our business
environment. A weakening in demand in the United States for fuel may
impact refiners to whom we sell crude oil and may reduce the availability of
petroleum products for our marketing activities if refiners reduce
levels. Additionally reduced demand for copper, paper and pulp
products and leather could reduce demand by producers of these goods for the
NaHS used in their processes.
Uses
of Cash
Our cash
requirements include funding day-to-day operations, maintenance and expansion
capital projects, debt service, refinancings, and distributions on our common
units and other equity interests. We expect to use cash flows from
operating activities to fund cash distributions and maintenance capital
expenditures needed to sustain existing operations. Future expansion
capital – acquisitions or capital projects – may require additional funding
through various financing arrangements, as more particularly described under
“Liquidity and Capital Resources – Capital Resources/Sources of Cash”
above.
Operating. Our
operating cash flows are affected significantly by changes in items of working
capital. In the first nine months our cash flow provided by operating
activities was approximately $56.2 million, resulting from cash generated by our
recurring operations, an increase in inventory and the timing of payments from
customers and vendors.
Investing. We
utilized some of our cash flow for capital expenditures and other investing
activities. We paid $324.5 million for capital expenditures, the
inland marine transportation assets of Grifco and the CO2 pipeline
transactions and received $0.6 million from the sale of surplus
assets. We received distributions of $0.9 million from our T&P
Syngas joint venture that exceeded our share of the earnings of T&P Syngas
during the first nine months of 2008. We also invested an additional
$3.0 million in other investments.
Financing. Net
cash of $280.3 million was provided by financing activities. Our net
borrowings under our credit facility were $263.2 million, primarily as a result
of the $225 million borrowed to fund the drop-down transactions with Denbury and
$24.5 million borrowed for our investment in DG Marine and redemption of common
units from the Davison family. DG Marine’s net borrowings under its credit
facility were $48.2 million, which was used to fund the acquisition of the
Grifco assets, and to acquire new boats and barges and fund working
capital. Our partner in the DG Marine joint venture also contributed
$25.5 million to fund its equity investment in DG Marine. DG Marine
utilized cash to fund credit facility fees totaling $2.3 million. We
paid distributions totaling $36.8 million to our limited partners and our
general partner during the nine month period, redeemed $16.7 million of units
from the Davison family and utilized $0.9 million from other financing
activities.
Capital
Expenditures. A summary of our capital expenditures, in the
nine months ended September 30, 2008 and 2007 is as follows:
|
|
Nine
Months Ended September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
thousands)
|
|
Capital
expenditures for asset purchases:
|
|
|
|
|
|
|
DG
Marine acquisition
|
|
|
91,096 |
|
|
|
|
Free
State Pipeline acquisition
|
|
|
75,000 |
|
|
|
- |
|
Total
asset purchases
|
|
|
166,096 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
Capital
expenditures for property, plant and equipment:
|
|
|
|
|
|
|
|
|
Maintenance
capital expenditures:
|
|
|
|
|
|
|
|
|
Pipeline
transportation assets
|
|
|
463 |
|
|
|
2,177 |
|
Supply
and logistics assets
|
|
|
571 |
|
|
|
348 |
|
Refinery
services assets
|
|
|
856 |
|
|
|
269 |
|
Administrative
and other assets
|
|
|
1,077 |
|
|
|
48 |
|
Total
maintenance capital expenditures
|
|
|
2,967 |
|
|
|
2,842 |
|
|
|
|
|
|
|
|
|
|
Growth
capital expenditures:
|
|
|
|
|
|
|
|
|
Pipeline
transportation assets
|
|
|
5,463 |
|
|
|
188 |
|
Supply
and logistics assets
|
|
|
18,831 |
|
|
|
186 |
|
Refinery
services assets
|
|
|
1,844 |
|
|
|
284 |
|
Total
growth capital expenditures
|
|
|
26,138 |
|
|
|
658 |
|
Total
|
|
|
29,105 |
|
|
|
3,500 |
|
|
|
|
|
|
|
|
|
|
Capital
expenditures attributable to unconsolidated affiliates:
|
|
|
|
|
|
|
|
|
Faustina
project
|
|
|
2,210 |
|
|
|
552 |
|
Total
|
|
|
2,210 |
|
|
|
552 |
|
Total
capital expenditures
|
|
$ |
197,411 |
|
|
$ |
4,052 |
|
During
the remainder of 2008, we expect to expend approximately $0.5 million for
maintenance capital projects in progress or planned. Those
expenditures are expected to include approximately $0.1 million of improvements
in our refinery services business, $0.2 million in our crude oil pipeline
operations, and the remainder on projects related to our truck transportation
and information technology areas. Most of our truck fleet is less
than three years old, so we do not anticipate making any significant
expenditures for vehicles in 2009; however, in future years we expect to spend
$4 million to $5 million per year on vehicle replacements. Based on
the information available to us at this time, we do not anticipate that future
capital expenditures for compliance with regulatory requirements will be
material.
In the
first quarter of 2009, we expect to complete construction of an expansion of our
existing Jay System that will extend the pipeline to producers operating in
southern Alabama. That expansion will consist of approximately 33
miles of pipeline and gathering connections to approximately 35 wells and will
include storage capacity of 20,000 barrels. We expect to spend a
total of approximately $10.3 million on this project, of which $1.3 million
remains to be spent at September 30, 2008. Our refinery services
segment has expended approximately $1.7 million on a project expected to be
completed in the fourth quarter of 2008 to expand its operations to an
additional refinery. We also increased our base level of crude oil
inventory by $4.3 million related to our Port Hudson facility, which is included
in fixed assets. This is the level of inventory needed to ensure
efficient and uninterrupted operations of the facility.
Our
capital expenditure budget for 2009 is not completed, however we expect it to
include the completion of the Jay System expansion and an expansion of our
refinery services segment operations to an additional refiner. These
two expenditures are expected to total approximately $25 million.
DG Marine
will complete the acquisition of four additional barges and two push boats in
the fourth quarter of 2008 and first quarter of 2009. Those
expenditures will be funded under DG Marine’s credit facility.
Expenditures
for capital assets to grow the partnership distribution will depend on our
access to debt and equity capital discussed above in “Capital Resources -- Sources of
Cash.” We will look for opportunities to acquire assets from
other parties that meet our criteria for stable cash flows.
Distributions
We are
required by our partnership agreement to distribute 100% of our available cash
(as defined therein) within 45 days after the end of each quarter to unitholders
of record and to our general partner. Available cash consists
generally of all of our cash receipts less cash disbursements adjusted for net
changes to reserves. We have increased our distribution for each of
the last six quarters, including the distribution to be paid for the second
quarter of 2008, as shown in the table below (in thousands, except per unit
amounts).
Distribution For
|
Date Paid
|
|
Per
Unit Amount
|
|
|
Limited
Partner Interests Amount
|
|
|
General
Partner Interest Amount
|
|
|
General
Partner Incentive Distribution Amount
|
|
|
Total
Amount
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second
quarter 2007
|
August
2007
|
|
$ |
0.2300 |
|
|
$ |
3,170 |
(1) |
|
$ |
65 |
|
|
$ |
- |
|
|
$ |
3,235 |
(1) |
Third
quarter 2007
|
November
2007
|
|
$ |
0.2700 |
|
|
$ |
7,646 |
|
|
$ |
156 |
|
|
$ |
90 |
|
|
$ |
7,892 |
|
Fourth
quarter 2007
|
February
2008
|
|
$ |
0.2850 |
|
|
$ |
10,903 |
|
|
$ |
222 |
|
|
$ |
245 |
|
|
$ |
11,370 |
|
First
quarter 2008
|
May
2008
|
|
$ |
0.3000 |
|
|
$ |
11,476 |
|
|
$ |
234 |
|
|
$ |
429 |
|
|
$ |
12,139 |
|
Second
quarter 2008
|
August
2008
|
|
$ |
0.3150 |
|
|
$ |
12,427 |
|
|
$ |
254 |
|
|
$ |
633 |
|
|
$ |
13,314 |
|
Third
quarter 2008
|
November
2008(2)
|
|
$ |
0.3225 |
|
|
$ |
12,723 |
|
|
$ |
260 |
|
|
$ |
728 |
|
|
$ |
13,711 |
|
(1) The
distribution paid on August 14, 2007 to holders of our common units is net of
the amounts payable with respect to the common units issued in connection with
the Davison transaction. The Davison unitholders and our general
partner waived their rights to receive such distributions, instead receiving
purchase price adjustments with us.
(2) This
distribution will be paid on November 14, 2008 to the general partner and
unitholders of record as of November 4, 2008.
See Notes
9 and 10 of the Notes to the Unaudited Consolidated Financial
Statements.
Commitments
and Off-Balance-Sheet Arrangements
Contractual
Obligations and Commercial Commitments
In
addition to the credit facility discussed above, we have contractual obligations
under operating leases as well as commitments to purchase crude
oil. The table below summarizes our obligations and commitments at
September 30, 2008 (in thousands).
|
|
Payments
Due by Period
|
|
Commercial
Cash Obligations and Commitments
|
|
Less
than one year
|
|
|
1 -
3 years
|
|
|
3 -
5 Years
|
|
|
More
than 5 years
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contractual
Obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt (1)
|
|
$ |
48,200 |
|
|
$ |
- |
|
|
$ |
343,200 |
|
|
$ |
- |
|
|
$ |
391,400 |
|
Estimated
interest payable on long-term debt (2)
|
|
|
21,164 |
|
|
|
42,475 |
|
|
|
2,327 |
|
|
|
- |
|
|
|
65,966 |
|
Operating
lease obligations
|
|
|
5,725 |
|
|
|
8,217 |
|
|
|
4,618 |
|
|
|
11,061 |
|
|
|
29,621 |
|
Capital
expansion projects (3)
|
|
|
17,727 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
17,727 |
|
Unconditional
purchase obligations (4)
|
|
|
137,421 |
|
|
|
32,800 |
|
|
|
2,571 |
|
|
|
- |
|
|
|
172,792 |
|
Remaining
purchase obligation to Grifco(5)
|
|
|
6,000 |
|
|
|
6,000 |
|
|
|
|
|
|
|
|
|
|
|
12,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Cash Commitments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset
retirement obligations (6)
|
|
|
100 |
|
|
|
|
|
|
|
|
|
|
|
3,656 |
|
|
|
3,756 |
|
FIN
48 tax liabilities (7)
|
|
|
1,680 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,680 |
|
Total
|
|
$ |
238,017 |
|
|
$ |
89,492 |
|
|
$ |
352,716 |
|
|
$ |
14,717 |
|
|
$ |
694,942 |
|
|
(1)
|
Our
credit facility allows us to repay and re-borrow funds at any time through
the maturity date in 2011. DG Marine’s credit facility is reflected in the
Less than one year column due to the covenant non-compliance discussed in
Note 9 to the Unaudited Consolidated Financial
Statements.
|
|
(2)
|
Interest
on portions of our long-term debt is at market-based rates. A portion of
the DG Marine debt has been hedged such that rates are fixed through July
2011. The amount shown for interest payments represents the
amount that would be paid if the debt outstanding at September 30, 2008
remained outstanding through the final maturity date of the credit
facility, and interest rates remained at the September 30, 2008 market
levels through November 15, 2011 for debt with floating
rates. Interest rates that have been fixed are applied to that
portion of the debt through the maturity of the interest rate
swaps.
|
|
(3)
|
We
have signed commitments to expand our Jay pipeline system and to construct
four new barges. See “Capital Expenditures”
above.
|
|
(4)
|
Unconditional
purchase obligations include agreements to purchase goods and services
that are enforceable and legally binding and specify all significant
terms. Contracts to purchase crude oil and petroleum products
are generally at market-based prices. For purposes of this
table, estimated volumes and market prices at September 30, 2008, were
used to value those obligations. The actual physical volumes
and settlement prices may vary from the assumptions used in the
table. Uncertainties involved in these estimates include levels
of production at the wellhead, changes in market prices and other
conditions beyond our control.
|
|
(5)
|
DG
Marine will pay Grifco $12 million after delivery of new barges and
boats. See Note 3 to the Unaudited Consolidated Financial
Statements.
|
|
(6)
|
Represents
the estimated future asset retirement obligations on an undiscounted
basis. The present discounted asset retirement obligation is
$1.2 million, as determined under FIN 47 and SFAS
143.
|
|
(7)
|
The
estimated FIN 48 tax liabilities will be settled as a result of expiring
statutes or audit activity. The timing of any particular
settlement will depend on the length of the tax audit and related appeals
process, if any, or an expiration of statute. If a liability is
settled due to a stature expiring or a favorable audit result, the
settlement of the FIN 48 tax liability would not result in a cash
payment.
|
In
addition to the contractual cash obligations included above, we also have a
contingent obligation related to our acquisition of a 50% interest in Sandhill,
which could require us to pay an additional $2 million for our
interest.
We have
guaranteed 50% of the $3.3 million debt obligation to a bank of Sandhill;
however, we believe we are not likely to be required to perform under this
guarantee as Sandhill is expected to make all required payments under the debt
obligation.
Off-Balance
Sheet Arrangements
We have
no off-balance sheet arrangements, special purpose entities, or financing
partnerships, other than as disclosed under “Contractual Obligations and
Commercial Commitments” above, nor do we have any debt or equity triggers based
upon our unit or commodity prices.
New
and Proposed Accounting Pronouncements
See
discussion of new accounting pronouncements in Note 2, “Recent Accounting
Developments” in the accompanying unaudited consolidated financial
statements.
Forward
Looking Statements
The
statements in this Quarterly Report on Form 10-Q that are not historical
information may be “forward looking statements” within the meaning of the
various provisions of the Securities Act of 1933 and the Securities Exchange Act
of 1934. All statements, other than historical facts, included in
this document that address activities, events or developments that we expect or
anticipate will or may occur in the future, including things such as plans for
growth of the business, future capital expenditures, competitive strengths,
goals, references to future goals or intentions, and other such references are
forward-looking statements. These forward-looking statements are
identified as any statement that does not relate strictly to historical or
current facts. They use words such as “anticipate,” “believe,”
“continue,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,”
“position,” “projection,” “strategy” or “will,” or the negative of those terms
or other variations of them or by comparable terminology. In
particular, statements, expressed or implied, concerning future actions,
conditions or events or future operating results or the ability to generate
sales, income or cash flow are forward-looking
statements. Forward-looking statements are not guarantees of
performance. They involve risks, uncertainties and
assumptions. Future actions, conditions or events and future
results of operations may differ materially from those expressed in these
forward-looking statements. Many of the factors that will determine
these results are beyond our ability or the ability of our affiliates to control
or predict. Specific factors that could cause actual results to
differ from those in the forward-looking statements include:
|
·
|
demand for, the supply of,
changes in forecast data for, and price trends related to crude oil,
liquid petroleum, natural gas and natural gas liquids or “NGLs,” sodium
hydrosulfide and caustic soda in the United States, all of which may be
affected by economic activity, capital expenditures by energy producers,
weather, alternative energy sources, international events, conservation
and technological advances;
|
|
·
|
throughput levels and
rates;
|
|
·
|
changes in, or challenges to,
our tariff rates;
|
|
·
|
our ability to successfully
identify and consummate strategic acquisitions, make cost saving changes
in operations and integrate acquired assets or businesses into our
existing operations;
|
|
·
|
service interruptions in our
liquids transportation systems, natural gas transportation systems or
natural gas gathering and processing
operations;
|
|
·
|
shutdowns or cutbacks at
refineries, petrochemical plants, utilities or other businesses for which
we transport crude oil, natural gas, or other products or to whom we sell
such products;
|
|
·
|
changes in laws or regulations
to which we are subject;
|
|
·
|
our inability to borrow or
otherwise access funds needed for operations, expansions, or capital
expenditures as a result of existing debt agreements that contain
restrictive financial
covenants;
|
|
·
|
the effects of competition, in
particular, by other pipeline
systems;
|
|
·
|
hazards and operating risks
that may not be covered fully by
insurance;
|
|
·
|
risks and changes in the barge
transportation industry;
|
|
·
|
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 1A of our Annual Report on Form 10-K for
the year ended December 31, 2007. Except as required by applicable
securities laws, we do not intend to update these forward-looking statements and
information.
Item 3. Quantitative and Qualitative Disclosures about
Market Risk
We are
exposed to various market risks, primarily related to volatility in crude oil
and petroleum products prices, NaHS and NaOH prices, and interest rates. Our
policy is to purchase only commodity products for which we have a market, and to
structure our sales contracts so that price fluctuations for those products do
not materially affect the segment margin we receive. We do not
acquire and hold futures contracts or other derivative products for the purpose
of speculating on price changes, as these activities could expose us to
significant losses.
Our
primary price risk relates to the effect of crude oil and petroleum products
price fluctuations on our inventories and the fluctuations each month in grade
and location differentials and their effect on future contractual
commitments. Our risk management policies are designed to monitor our
physical volumes, grades, and delivery schedules to ensure our hedging
activities address the market risks that are inherent in our gathering and
marketing activities.
We
utilize NYMEX commodity based futures contracts and option contracts to hedge
our exposure to these market price fluctuations as needed. All of our
open commodity price risk derivatives at September 30, 2008 were categorized as
non-trading. On September 30, 2008, we had entered into NYMEX future contracts
that settled during October 2008 and NYMEX options contracts that settled during
October and November 2008. Although the intent of our commodity
risk-management activities is to hedge our margin, none of our derivative
positions at September 30, 2008 qualified for hedge accounting.
The table
below presents information about our open commodity derivative contracts at
September 30, 2008. Notional amounts in barrels, the weighted average
contract price, total contract amount, and total fair value amount in U.S.
dollars of our open positions are presented below. Fair values were
determined by using the notional amount in barrels multiplied by the September
30, 2008 quoted market prices on the NYMEX. All of the hedge
positions offset physical exposures to the cash market; none of these offsetting
physical exposures are included in the table below.
This
accounting treatment is discussed further under Note 2 “Summary of
Significant Accounting Policies” of our Consolidated Financial Statements in our
2007 Annual Report on Form 10-K. Also see Notes 15 and 18 to the
Unaudited Consolidated Financial Statements for additional information on our
derivative transactions and fair value measurements of those
derivatives.
|
|
Sell (Short)
Contracts
|
|
|
Buy (Long)
Contracts
|
|
|
|
|
|
|
|
|
Futures
Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
Oil:
|
|
|
|
|
|
|
Contract
volumes (1,000 bbls)
|
|
|
140 |
|
|
|
40 |
|
Weighted
average price per bbl
|
|
$ |
103.89 |
|
|
$ |
102.06 |
|
|
|
|
|
|
|
|
|
|
Contract
value (in thousands)
|
|
$ |
14,545 |
|
|
|
4,083 |
|
Mark-to-market
change (in thousands)
|
|
|
(455 |
) |
|
|
(57 |
) |
Market
settlement value (in thousands)
|
|
$ |
14,090 |
|
|
$ |
4,026 |
|
|
|
|
|
|
|
|
|
|
Heating
Oil:
|
|
|
|
|
|
|
|
|
Contract
volumes (1,000 bbls)
|
|
|
20 |
|
|
|
- |
|
Weighted
average price per gal
|
|
$ |
3.01 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
Contract
value (in thousands)
|
|
$ |
2,531 |
|
|
|
- |
|
Mark-to-market
change (in thousands)
|
|
|
(99 |
) |
|
|
- |
|
Market
settlement value (in thousands)
|
|
$ |
2,432 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
Natural
Gas:
|
|
|
|
|
|
|
|
|
Contract
volumes (10,000 mmBtus)
|
|
|
|
|
|
|
5 |
|
Weighted
average price per mmBtu
|
|
$ |
- |
|
|
$ |
7.86 |
|
|
|
|
|
|
|
|
|
|
Contract
value (in thousands)
|
|
$ |
- |
|
|
|
393 |
|
Mark-to-market
change (in thousands)
|
|
|
- |
|
|
|
(21 |
) |
Market
settlement value (in thousands)
|
|
$ |
- |
|
|
$ |
372 |
|
|
|
|
|
|
|
|
|
|
NYMEX
Option Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
Oil- Written Calls
|
|
|
|
|
|
|
|
|
Contract
volumes (1,000 bbls)
|
|
|
10 |
|
|
|
|
|
Weighted
average premium received
|
|
$ |
2.72 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract
value (in thousands)
|
|
$ |
27 |
|
|
|
|
|
Mark-to-market
change (in thousands)
|
|
|
(7 |
) |
|
|
|
|
Market
settlement value (in thousands)
|
|
$ |
20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heating
Oil-Written Calls
|
|
|
|
|
|
|
|
|
Contract
volumes (1,000 bbls)
|
|
|
50 |
|
|
|
|
|
Weighted
average premium received
|
|
$ |
10.14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract
value (in thousands)
|
|
$ |
213 |
|
|
|
|
|
Mark-to-market
change (in thousands)
|
|
|
(37 |
) |
|
|
|
|
Market
settlement value (in thousands)
|
|
$ |
176 |
|
|
|
|
|
We manage
our risks of volatility in NaOH prices by indexing prices for the sale of NaHS
to the market price for NaOH in most of our contracts.
We are
also exposed to market risks due to the floating interest rates on our credit
facility and the DG Marine credit facility. Our debt bears interest
at the LIBOR Rate or Prime Rate, at our option, plus the applicable
margin. We have not, historically hedged our interest
rates. We hedged a portion of the debt of DG Marine through July
2011. On September 30, 2008, we had $343.2 million of debt
outstanding under our credit facility and $48.2 million outstanding under the DG
Marine credit facility.
Item 4. Controls and Procedures
We
maintain disclosure controls and procedures and internal controls designed to
ensure that information required to be disclosed in our filings under the
Securities Exchange Act of 1934 is recorded, processed, summarized, and reported
within the time periods specified in the Securities and Exchange Commission’s
rules and forms. Our chief executive officer and chief financial
officer, with the participation of our management, have evaluated our disclosure
controls and procedures as of the end of the period covered by this Quarterly
Report on Form 10-Q and have determined that such disclosure controls and
procedures are effective in ensuring that material information required to be
disclosed in this quarterly report is accumulated and communicated to them and
our management to allow timely decisions regarding required
disclosures.
There
were no changes during our last fiscal quarter that materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting.
Davison
Acquisition
On
July 25, 2007, we completed the Davison Acquisition, which met the criteria
of being a significant acquisition for us. For additional information regarding
the acquisition, please read Note 3 to the Unaudited Consolidated
Financial Statements included in Item 1 in this Quarterly Report on Form
10-Q.
On June
22, 2004, the Office of the Chief Accountant of the SEC issued guidance
regarding the reporting of internal control over financial reporting in
connection with a major acquisition. On October 6, 2004, the SEC
revised its guidance to include expectations of quarterly reporting updates of
new internal control and the status of the control regarding any exempted
businesses. This guidance was reiterated in September 2007 to
affirm that management may omit an assessment of an acquired business’ internal
control over financial reporting from management’s assessment of internal
control over financial reporting for a period not to exceed one
year.
We
excluded the operations acquired in the Davison Acquisition from the scope of
our Sarbanes-Oxley Section 404 report on internal control over financial
reporting for the year ended December 31, 2007. A summary of the
reasons for this exclusion is under Item 9A of our 2007 Annual Report on Form
10-K. The operations acquired in the Davison Acquisition will be
included in our evaluation and report on internal controls over financial
reporting as of December 31, 2008.
PART
II. OTHER INFORMATION
Item 1. Legal Proceedings.
See Part
I. Item 1. See Note 16 of the Notes to the Unaudited
Consolidated Financial Statements entitled “Contingencies,” which is
incorporated herein by reference.
For
additional information about our risk factors, see Item 1A of our Annual Report
on Form 10-K for the year ended December 31, 2007. In addition, we believe that
the following additional risk factor is relevant for our investment in DG
Marine, which acquired the inland marine transportation business of Grifco
Transportation, Ltd. in July 2008.
Our
investment in DG Marine Transportation, LLC (DG Marine) exposes us to certain
risks that are inherent to the barge transportation industry as well certain
risks applicable to our other operations.
DG
Marine’s inland barge transportation business has exposure to certain risks
which are significant to our other operations and certain risks inherent to the
barge transportation industry. For example, unlike our other
operations, DG Marine operates barges that transport products to and from
numerous marine locations, which exposes us to new risks,
including:
|
-
|
being
subject to the Jones Act and other federal laws that restrict U.S.
maritime transportation to vessels built and registered in the U.S. and
owned and manned by U.S. citizens, with any failure to comply with such
laws potentially resulting in severe penalties, including permanent loss
of U.S. coastwise trading rights, fines or forfeiture of
vessels;
|
|
-
|
relying
on a limited number of customers;
|
|
-
|
having
primarily short-term charters which DG Marine may be unable to renew as
they expire; and
|
|
-
|
competing
against businesses with greater financial resources and larger operating
crews than DG Marine.
|
In
addition, like our other operations, DG Marine’s refined products transportation
business is an integral part of the energy industry infrastructure, which
increases our exposure to declines in demand for refined petroleum products or
decreases in U.S. refining activity.
Due to
recent disruptions in credit markets and concerns about economic growth, we also
believe that the following risk factor is relevant for our operations and
liquidity.
Economic
developments in the United States and worldwide in credit markets and concerns
about economic growth could impact our operations and materially reduce our
profitability and cash flows.
Recent
disruptions in the credit markets and concerns about local and global economic
growth have had a significant adverse impact on global financial markets and
commodity prices, both of which have contributed to a decline in our unit price
and corresponding market capitalization. Further unit price or
commodity price decreases in the fourth quarter could affect the fair value of
our long-lived assets and result in impairment charges. At September
30, 2008, we had $325 million of goodwill recorded in conjunction with the
Davison and Port Hudson acquisitions.
Likewise,
the capital and credit markets have become increasingly volatile as a result of
adverse conditions. If the credit markets continue to experience
volatility and the availability of funds remains limited, we may experience
difficulties in accessing capital for significant growth projects or
acquisitions which could adversely affect our strategic
plans. Additionally many of our customers are impacted by the
weakening economic outlook and declining commodity prices in a manner that could
influence the need for our products and services.
Item 2. Unregistered Sales of Equity Securities
and Use of Proceeds.
On June
4, 2008, we issued 1,199,041 of our common units to Denbury
Onshore. The units were issued at a value of $20.85 per unit,
for a total value of $25 million as a portion of the consideration for the
acquisition of the Free State Pipeline in Mississippi. As a result of
that purchase, our general partner and its affiliates will hold 10.2% of our
outstanding common units. This issuance of common units by us was
completed on June 4, 2008 and was exempt from registration under the Securities
Act of 1933 by reason of Section 4(2) thereof and Rule 506 of Regulation D
promulgated thereunder.
See Note
3, 10 and 12 of the Notes to the Unaudited Consolidated Financial
Statements.
On July
18, 2008, we redeemed 837,690 of our common units owned by members of the
Davison family. Those units had been issued as a portion of the
consideration for the acquisition of the energy-related business of the Davison
family in July 2007. The redemption was at a value of $19.896 per
unit, for a total value of $16.7 million.
Additionally,
on July 18, 2008, we issued 837,690 of our common units to
Grifco. Those units were issued at a value of $19.896 per unit,
for a total value of $16.7 million as a portion of the consideration for our
investment in DG Marine, which acquired the inland marine transportation
business of Grifco. That issuance of common units by us was completed
on July 18, 2008 and was exempt from registration under the Securities Act of
1933 by reason of Section 4(2) thereof and Rule 506 of Regulation D promulgated
thereunder. After giving effect to the issuance and redemption
described above, we did not experience a change in the number of common units
outstanding.
See Note
3 and 14 of the Notes to the Unaudited Consolidated Financial
Statements.
Item 3. Defaults Upon Senior
Securities.
None.
Item 4. Submission of Matters to a Vote of
Security Holders.
None.
Item 5. Other Information.
None.
3.1
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Certificate
of Limited Partnership of Genesis Energy, L.P. (“Genesis”) (incorporated
by reference to Exhibit 3.1 to Registration Statement, File No.
333-11545)
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3.2
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Fourth
Amended and Restated Agreement of Limited Partnership of Genesis
(incorporated by reference to Exhibit 4.1 to Form 8-K dated June 15,
2005)
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3.3
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Amendment
No. 1 to Fourth Amended and Restated Agreement of Limited Partnership of
Genesis (incorporated by reference to Exhibit 3.3 to Form 10-K for the
year ended December 31, 2007.)
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3.4
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Certificate
of Limited Partnership of Genesis Crude Oil, L.P. (“the Operating
Partnership”) (incorporated by reference to Exhibit 3.3 to Form 10-K for
the year ended December 31, 1996)
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3.5
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Fourth
Amended and Restated Agreement of Limited Partnership of the Operating
Partnership (incorporated by reference to Exhibit 4.2 to Form 8-K dated
June 15, 2005)
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3.6
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Certificate
of Incorporation of Genesis Energy, Inc. (incorporated by reference to
Exhibit 3.6 to Form 10-K for the year ended December 31,
2007.)
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3.7
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Certificate
of Amendment of Certificate of Incorporation of Genesis Energy, Inc.
(incorporated by reference to Exhibit 3.7 to Form 10-K for the year ended
December 31, 2007.)
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3.8
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Bylaws
of Genesis Energy, Inc. (incorporated by reference to Exhibit 3.8 to Form
10-K for the year ended December 31, 2007.)
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4.1
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Form
of Unit Certificate of Genesis Energy, L.P. (incorporated by reference to
Exhibit 4.1 to Form 10-K for the year ended December 31,
2007.)
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10.1
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Pipeline
Financing Lease Agreement by and between Genesis NEJD Pipeline, LLC, as
Lessor and Denbury Onshore, LLC, as Lessee for the North East Jackson Dome
Pipeline dated May 30, 2008 (incorporated by reference to Exhibit 10.1 to
Form 8-K dated June 5, 2008.)
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10.2
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Purchase
and Sale Agreement between Denbury Onshore, LLC and Genesis Free State
Pipeline, LLC dated May 30, 2008 (incorporated by reference to Exhibit
10.2 to Form 8-K dated June 5, 2008.)
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10.3
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Transportation
Services Agreement between Genesis Free State Pipeline, LLC and Denbury
Onshore, LLC dated May 30, 2008 (incorporated by reference to Exhibit 10.3
to Form 8-K dated June 5, 2008.)
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10.4
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First
Amended and Restated Credit Agreement dated as of May 30, 2008 among
Genesis Crude Oil, L.P., Genesis Energy, L.P., the Lenders Party Hereto,
Fortis Capital Corp., and Deutsche Bank Securities Inc. (incorporated by
reference to Exhibit 10.4 to Form 8-K dated June 5,
2008.)
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10.5
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Contribution
and Sale Agreement by and Among Grifco Transportation, Ltd., Grifco
Transportation Two, Ltd., and Shore Thing, Ltd. and Genesis Marine
Investments, LLC and Genesis Energy, L.P. and TD Marine, LLC (incorporated
by reference to Exhibit 10.1 to Form 8-K dated July 22,
2008)
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10.6
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Omnibus
Agreement dated as of June 11, 2008 by and among TD Marine, LLC, James E.
Davison, Steven K. Davison, Todd A Davison and Genesis Energy, L.P.
(incorporated by reference to Exhibit 10.2 to Form 8-K dated July 22,
2008)
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10.7
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First
Amendment to First Amended and Restated Credit Agreement dated as of July
18, 2008, among Genesis Crude Oil, L.P., Genesis Energy, L.P. and the
lenders party thereto, Fortis Capital Corp. and Deutsche Bank Securities
Inc. (incorporated by reference to Exhibit 10.3 to Form 8-K dated July 22,
2008)
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*
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Certification
by Chief Executive Officer Pursuant to Rule 13a-14(a) of the Securities
Exchange Act of 1934.
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*
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Certification
by Chief Financial Officer Pursuant to Rule 13a-14(a) of the Securities
Exchange Act of 1934.
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*
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Certification
by Chief Executive Officer and Chief Financial Officer Pursuant to Rule
13a-14(b) of the Securities Exchange Act of
1934.
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*Filed
herewith
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.
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GENESIS
ENERGY, L.P.
(A
Delaware Limited Partnership)
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By:
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GENESIS
ENERGY, INC., as General Partner
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Date: November
10 2008
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By:
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/s/ Robert V.
Deere
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Robert V. Deere
Chief Financial
Officer
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