epdform10q.htm
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington, D.C.
20549
FORM
10-Q
þ QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE
SECURITIES EXCHANGE ACT OF 1934
For the
quarterly period ended September 30, 2009
OR
o TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE
SECURITIES EXCHANGE ACT OF 1934
For the
transition period from ___ to ___.
Commission
file number: 1-14323
ENTERPRISE
PRODUCTS PARTNERS L.P.
(Exact
name of Registrant as Specified in Its Charter)
Delaware
|
76-0568219
|
(State
or Other Jurisdiction of
|
(I.R.S.
Employer Identification No.)
|
Incorporation
or Organization)
|
|
|
|
|
|
1100
Louisiana, 10th Floor
|
|
|
Houston,
Texas 77002
|
|
|
(Address
of Principal Executive Offices, Including Zip Code)
|
|
|
|
|
|
(713)
381-6500
|
|
|
(Registrant’s
Telephone Number, Including Area Code)
|
|
Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days.
Yes þ No
o
Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding
12 months (or for such shorter period that the registrant was required to submit
and post such files).
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 definitions of “large accelerated filer,” “accelerated
filer” and “smaller reporting company” in Rule 12b-2 of the Exchange
Act.
Large
accelerated filer þ
|
Accelerated
filer o
|
Non-accelerated
filer o
(Do not check if a smaller reporting company)
|
Smaller
reporting company o
|
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).
Yes o No
þ
There
were 604,716,122 common units (including 2,797,822 restricted common units) and
4,520,431 Class B units (which generally vote together with the common units) of
Enterprise Products Partners L.P. outstanding at November 4,
2009. The common units trade on the New York Stock Exchange under the
ticker symbol “EPD.”
TABLE
OF CONTENTS
UNAUDITED
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars
in millions)
|
|
September
30,
|
|
|
December
31,
|
|
ASSETS
|
|
2009
|
|
|
2008
|
|
Current
assets:
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
73.8 |
|
|
$ |
35.4 |
|
Restricted
cash
|
|
|
102.8 |
|
|
|
203.8 |
|
Accounts
and notes receivable – trade, net of allowance for doubtful
accounts of
$14.4 at September 30, 2009 and $15.1 at December 31, 2008
|
|
|
1,471.4 |
|
|
|
1,185.5 |
|
Accounts
receivable – related parties
|
|
|
37.9 |
|
|
|
61.6 |
|
Inventories
(see Note 5)
|
|
|
1,147.5 |
|
|
|
362.8 |
|
Derivative
assets (see Note 4)
|
|
|
197.0 |
|
|
|
202.8 |
|
Prepaid
and other current assets
|
|
|
118.6 |
|
|
|
111.8 |
|
Total
current assets
|
|
|
3,149.0 |
|
|
|
2,163.7 |
|
Property,
plant and equipment, net
|
|
|
13,661.6 |
|
|
|
13,154.8 |
|
Investments
in unconsolidated affiliates
|
|
|
901.0 |
|
|
|
949.5 |
|
Intangible
assets, net of accumulated amortization of $492.5 at September
30, 2009 and $429.9 at December 31, 2008
|
|
|
793.0 |
|
|
|
855.4 |
|
Goodwill
|
|
|
706.9 |
|
|
|
706.9 |
|
Deferred
tax asset
|
|
|
1.1 |
|
|
|
0.4 |
|
Other
assets
|
|
|
144.9 |
|
|
|
126.8 |
|
Total
assets
|
|
$ |
19,357.5 |
|
|
$ |
17,957.5 |
|
|
|
|
|
|
|
|
|
|
LIABILITIES
AND EQUITY
|
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
|
Accounts
payable – trade
|
|
$ |
327.1 |
|
|
$ |
300.5 |
|
Accounts
payable – related parties
|
|
|
47.2 |
|
|
|
39.6 |
|
Accrued
product payables
|
|
|
1,675.6 |
|
|
|
1,142.4 |
|
Accrued
interest payable
|
|
|
117.4 |
|
|
|
151.9 |
|
Other
accrued expenses
|
|
|
46.1 |
|
|
|
48.8 |
|
Derivative
liabilities (see Note 4)
|
|
|
263.1 |
|
|
|
287.2 |
|
Other
current liabilities
|
|
|
220.9 |
|
|
|
252.7 |
|
Total
current liabilities
|
|
|
2,697.4 |
|
|
|
2,223.1 |
|
Long-term debt: (see
Note 9)
|
|
|
|
|
|
|
|
|
Senior
debt obligations – principal
|
|
|
7,912.3 |
|
|
|
7,813.4 |
|
Junior
subordinated notes – principal
|
|
|
1,232.7 |
|
|
|
1,232.7 |
|
Other
|
|
|
53.3 |
|
|
|
62.3 |
|
Total
long-term debt
|
|
|
9,198.3 |
|
|
|
9,108.4 |
|
Deferred
tax liabilities
|
|
|
69.6 |
|
|
|
66.1 |
|
Other
long-term liabilities
|
|
|
95.8 |
|
|
|
81.3 |
|
Commitments
and contingencies
|
|
|
|
|
|
|
|
|
Equity: (see Note
10)
|
|
|
|
|
|
|
|
|
Enterprise
Products Partners L.P. partners’ equity:
|
|
|
|
|
|
|
|
|
Limited
Partners:
|
|
|
|
|
|
|
|
|
Common
units (475,293,998 units outstanding at September 30, 2009 and
439,354,731 units outstanding at December 31, 2008)
|
|
|
6,670.8 |
|
|
|
6,036.9 |
|
Restricted
common units (2,658,850 units outstanding at September 30, 2009
and
2,080,600 units outstanding at December 31, 2008)
|
|
|
34.1 |
|
|
|
26.2 |
|
General
partner
|
|
|
136.6 |
|
|
|
123.6 |
|
Accumulated
other comprehensive loss
|
|
|
(67.1 |
) |
|
|
(97.2 |
) |
Total
Enterprise Products Partners L.P. partners’ equity
|
|
|
6,774.4 |
|
|
|
6,089.5 |
|
Noncontrolling
interest
|
|
|
522.0 |
|
|
|
389.1 |
|
Total
equity
|
|
|
7,296.4 |
|
|
|
6,478.6 |
|
Total
liabilities and equity
|
|
$ |
19,357.5 |
|
|
$ |
17,957.5 |
|
See Notes
to Unaudited Condensed Consolidated Financial Statements.
UNAUDITED
CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS
(Dollars
in millions, except per unit amounts)
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Third
parties
|
|
$ |
4,444.7 |
|
|
$ |
5,997.7 |
|
|
$ |
11,006.1 |
|
|
$ |
17,498.4 |
|
Related
parties
|
|
|
151.4 |
|
|
|
300.2 |
|
|
|
521.0 |
|
|
|
823.7 |
|
Total
revenues (see Note 11)
|
|
|
4,596.1 |
|
|
|
6,297.9 |
|
|
|
11,527.1 |
|
|
|
18,322.1 |
|
Costs
and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Third
parties
|
|
|
3,983.2 |
|
|
|
5,806.7 |
|
|
|
9,740.1 |
|
|
|
16,766.0 |
|
Related
parties
|
|
|
237.0 |
|
|
|
165.2 |
|
|
|
655.6 |
|
|
|
477.1 |
|
Total
operating costs and expenses
|
|
|
4,220.2 |
|
|
|
5,971.9 |
|
|
|
10,395.7 |
|
|
|
17,243.1 |
|
General
and administrative costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Third
parties
|
|
|
17.1 |
|
|
|
8.4 |
|
|
|
33.5 |
|
|
|
22.4 |
|
Related
parties
|
|
|
16.8 |
|
|
|
13.4 |
|
|
|
51.2 |
|
|
|
44.6 |
|
Total
general and administrative costs
|
|
|
33.9 |
|
|
|
21.8 |
|
|
|
84.7 |
|
|
|
67.0 |
|
Total
costs and expenses
|
|
|
4,254.1 |
|
|
|
5,993.7 |
|
|
|
10,480.4 |
|
|
|
17,310.1 |
|
Equity
in income of unconsolidated affiliates
|
|
|
22.5 |
|
|
|
14.9 |
|
|
|
18.3 |
|
|
|
48.1 |
|
Operating
income
|
|
|
364.5 |
|
|
|
319.1 |
|
|
|
1,065.0 |
|
|
|
1,060.1 |
|
Other
income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
|
(128.0 |
) |
|
|
(102.7 |
) |
|
|
(374.6 |
) |
|
|
(290.4 |
) |
Interest
income
|
|
|
0.2 |
|
|
|
2.1 |
|
|
|
1.4 |
|
|
|
4.7 |
|
Other,
net
|
|
|
(0.2 |
) |
|
|
(0.9 |
) |
|
|
(0.5 |
) |
|
|
(1.9 |
) |
Total
other expense, net
|
|
|
(128.0 |
) |
|
|
(101.5 |
) |
|
|
(373.7 |
) |
|
|
(287.6 |
) |
Income
before provision for income taxes
|
|
|
236.5 |
|
|
|
217.6 |
|
|
|
691.3 |
|
|
|
772.5 |
|
Provision
for income taxes
|
|
|
(6.6 |
) |
|
|
(6.6 |
) |
|
|
(24.0 |
) |
|
|
(17.2 |
) |
Net
income
|
|
|
229.9 |
|
|
|
211.0 |
|
|
|
667.3 |
|
|
|
755.3 |
|
Net
income attributable to noncontrolling interest
|
|
|
(17.0 |
) |
|
|
(7.9 |
) |
|
|
(42.5 |
) |
|
|
(29.3 |
) |
Net
income attributable to Enterprise Products Partners L.P.
|
|
$ |
212.9 |
|
|
$ |
203.1 |
|
|
$ |
624.8 |
|
|
$ |
726.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income allocated to:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited
partners
|
|
$ |
171.3 |
|
|
$ |
167.6 |
|
|
$ |
504.6 |
|
|
$ |
620.5 |
|
General
partner
|
|
$ |
41.6 |
|
|
$ |
35.5 |
|
|
$ |
120.2 |
|
|
$ |
105.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted earnings per
unit (see Note 13)
|
|
$ |
0.36 |
|
|
$ |
0.38 |
|
|
$ |
1.09 |
|
|
$ |
1.41 |
|
See Notes
to Unaudited Condensed Consolidated Financial Statements.
UNAUDITED
CONDENSED STATEMENTS OF CONSOLIDATED
COMPREHENSIVE
INCOME (LOSS)
(Dollars
in millions)
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
229.9 |
|
|
$ |
211.0 |
|
|
$ |
667.3 |
|
|
$ |
755.3 |
|
Other
comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivative instrument losses during period
|
|
|
(8.3 |
) |
|
|
(244.0 |
) |
|
|
(146.9 |
) |
|
|
(124.1 |
) |
Reclassification
adjustment for losses included in net income related
to commodity derivative instruments
|
|
|
77.8 |
|
|
|
28.5 |
|
|
|
176.3 |
|
|
|
15.8 |
|
Interest
rate derivative instrument gains (losses) during period
|
|
|
(8.0 |
) |
|
|
(1.1 |
) |
|
|
7.1 |
|
|
|
(22.9 |
) |
Reclassification
adjustment for (gains) losses included in net income related
to interest rate derivative instruments
|
|
|
1.3 |
|
|
|
-- |
|
|
|
3.3 |
|
|
|
(2.4 |
) |
Foreign
currency derivative gains (losses)
|
|
|
0.2 |
|
|
|
-- |
|
|
|
(10.3 |
) |
|
|
(1.3 |
) |
Total
cash flow hedges
|
|
|
63.0 |
|
|
|
(216.6 |
) |
|
|
29.5 |
|
|
|
(134.9 |
) |
Foreign
currency translation adjustment
|
|
|
1.1 |
|
|
|
0.4 |
|
|
|
1.7 |
|
|
|
0.5 |
|
Change
in funded status of pension and postretirement plans, net of
tax
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
(0.3 |
) |
Total
other comprehensive income (loss)
|
|
|
64.1 |
|
|
|
(216.2 |
) |
|
|
31.2 |
|
|
|
(134.7 |
) |
Comprehensive
income (loss)
|
|
|
294.0 |
|
|
|
(5.2 |
) |
|
|
698.5 |
|
|
|
620.6 |
|
Comprehensive
income attributable to noncontrolling interest
|
|
|
(17.3 |
) |
|
|
(7.6 |
) |
|
|
(43.6 |
) |
|
|
(28.7 |
) |
Comprehensive
income attributable to Enterprise Products Partners L.P.
|
|
$ |
276.7 |
|
|
$ |
(12.8 |
) |
|
$ |
654.9 |
|
|
$ |
591.9 |
|
See Notes
to Unaudited Condensed Consolidated Financial Statements.
UNAUDITED
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars
in millions)
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
Operating
activities:
|
|
|
|
|
|
|
Net
income
|
|
$ |
667.3 |
|
|
$ |
755.3 |
|
Adjustments
to reconcile net income to net cash flows
provided by operating activities:
|
|
|
|
|
|
|
|
|
Depreciation,
amortization and accretion
|
|
|
476.9 |
|
|
|
413.6 |
|
Equity
in income of unconsolidated affiliates
|
|
|
(18.3 |
) |
|
|
(48.1 |
) |
Distributions
received from unconsolidated affiliates
|
|
|
63.6 |
|
|
|
69.9 |
|
Operating
lease expense paid by EPCO, Inc.
|
|
|
0.5 |
|
|
|
1.5 |
|
Gain
from asset sales and related transactions
|
|
|
(0.4 |
) |
|
|
(1.7 |
) |
Non-cash
impairment charge
|
|
|
1.7 |
|
|
|
-- |
|
Deferred
income tax expense
|
|
|
2.5 |
|
|
|
5.6 |
|
Changes
in fair market value of derivative instruments
|
|
|
11.7 |
|
|
|
5.4 |
|
Effect
of pension settlement recognition
|
|
|
(0.1 |
) |
|
|
(0.1 |
) |
Net
effect of changes in operating accounts (see Note 16)
|
|
|
(590.0 |
) |
|
|
(228.4 |
) |
Net
cash flows provided by operating activities
|
|
|
615.4 |
|
|
|
973.0 |
|
Investing
activities:
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
(851.1 |
) |
|
|
(1,485.6 |
) |
Contributions
in aid of construction costs
|
|
|
12.8 |
|
|
|
21.2 |
|
Decrease
(increase) in restricted cash
|
|
|
100.8 |
|
|
|
(112.2 |
) |
Cash
used for business combinations
|
|
|
(24.5 |
) |
|
|
(57.1 |
) |
Acquisition
of intangible assets
|
|
|
-- |
|
|
|
(5.1 |
) |
Investments
in unconsolidated affiliates
|
|
|
(14.5 |
) |
|
|
(72.0 |
) |
Other
proceeds from investing activities
|
|
|
5.1 |
|
|
|
1.7 |
|
Cash
used in investing activities
|
|
|
(771.4 |
) |
|
|
(1,709.1 |
) |
Financing
activities:
|
|
|
|
|
|
|
|
|
Borrowings
under debt agreements
|
|
|
3,818.9 |
|
|
|
6,360.4 |
|
Repayments
of debt
|
|
|
(3,724.2 |
) |
|
|
(4,824.0 |
) |
Debt
issuance costs
|
|
|
(5.2 |
) |
|
|
(8.8 |
) |
Cash
distributions paid to partners
|
|
|
(860.6 |
) |
|
|
(770.9 |
) |
Cash
distributions paid to noncontrolling interest (see Note
10)
|
|
|
(47.9 |
) |
|
|
(39.2 |
) |
Net
cash proceeds from issuance of common units
|
|
|
878.2 |
|
|
|
57.2 |
|
Cash
contributions from noncontrolling interest (see Note 10)
|
|
|
137.4 |
|
|
|
-- |
|
Acquisition
of treasury units
|
|
|
(1.8 |
) |
|
|
(0.8 |
) |
Monetization
of interest rate derivative instruments
|
|
|
-- |
|
|
|
(22.1 |
) |
Cash
provided by financing activities
|
|
|
194.8 |
|
|
|
751.8 |
|
Effect
of exchange rate changes on cash
|
|
|
(0.4 |
) |
|
|
-- |
|
Net
change in cash and cash equivalents
|
|
|
38.8 |
|
|
|
15.7 |
|
Cash
and cash equivalents, January 1
|
|
|
35.4 |
|
|
|
39.7 |
|
Cash
and cash equivalents, September 30
|
|
$ |
73.8 |
|
|
$ |
55.4 |
|
See Notes
to Unaudited Condensed Consolidated Financial Statements.
UNAUDITED
CONDENSED STATEMENTS OF CONSOLIDATED EQUITY
(See
Note 10 for Unit History and Detail of Changes in Limited Partners’
Equity)
(Dollars
in millions)
|
|
Enterprise
Products Partners L.P.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Limited
|
|
|
General
|
|
|
Comprehensive
|
|
|
Noncontrolling
|
|
|
|
|
|
|
Partners
|
|
|
Partner
|
|
|
Loss
|
|
|
Interest
|
|
|
Total
|
|
Balance,
December 31, 2008
|
|
$ |
6,063.1 |
|
|
$ |
123.6 |
|
|
$ |
(97.2 |
) |
|
$ |
389.1 |
|
|
$ |
6,478.6 |
|
Net
income
|
|
|
504.6 |
|
|
|
120.2 |
|
|
|
-- |
|
|
|
42.5 |
|
|
|
667.3 |
|
Operating
leases paid by EPCO, Inc.
|
|
|
0.5 |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
0.5 |
|
Cash
distributions to partners
|
|
|
(735.2 |
) |
|
|
(124.9 |
) |
|
|
-- |
|
|
|
-- |
|
|
|
(860.1 |
) |
Unit
option reimbursements to EPCO, Inc.
|
|
|
(0.5 |
) |
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
(0.5 |
) |
Cash
distributions paid to noncontrolling interest (see Note
10)
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
(47.9 |
) |
|
|
(47.9 |
) |
Net
cash proceeds from issuance of common units
|
|
|
860.2 |
|
|
|
17.5 |
|
|
|
-- |
|
|
|
-- |
|
|
|
877.7 |
|
Cash
proceeds from exercise of unit options
|
|
|
0.5 |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
0.5 |
|
Cash
contributions from noncontrolling interest (see Note 10)
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
137.4 |
|
|
|
137.4 |
|
Amortization
of equity awards
|
|
|
13.5 |
|
|
|
0.2 |
|
|
|
-- |
|
|
|
-- |
|
|
|
13.7 |
|
Acquisition
of treasury units
|
|
|
(1.8 |
) |
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
(1.8 |
) |
Foreign
currency translation adjustment
|
|
|
-- |
|
|
|
-- |
|
|
|
1.7 |
|
|
|
-- |
|
|
|
1.7 |
|
Cash
flow hedges
|
|
|
-- |
|
|
|
-- |
|
|
|
28.4 |
|
|
|
1.1 |
|
|
|
29.5 |
|
Other
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
(0.2 |
) |
|
|
(0.2 |
) |
Balance,
September 30, 2009
|
|
$ |
6,704.9 |
|
|
$ |
136.6 |
|
|
$ |
(67.1 |
) |
|
$ |
522.0 |
|
|
$ |
7,296.4 |
|
|
|
Enterprise
Products Partners L.P.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Limited
|
|
|
General
|
|
|
Comprehensive
|
|
|
Noncontrolling
|
|
|
|
|
|
|
Partners
|
|
|
Partner
|
|
|
Income
(Loss)
|
|
|
Interest
|
|
|
Total
|
|
Balance,
December 31, 2007
|
|
$ |
5,992.9 |
|
|
$ |
122.3 |
|
|
$ |
19.1 |
|
|
$ |
427.8 |
|
|
$ |
6,562.1 |
|
Net
income
|
|
|
620.5 |
|
|
|
105.5 |
|
|
|
-- |
|
|
|
29.3 |
|
|
|
755.3 |
|
Operating
leases paid by EPCO, Inc.
|
|
|
1.5 |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
1.5 |
|
Cash
distributions to partners
|
|
|
(663.9 |
) |
|
|
(106.4 |
) |
|
|
-- |
|
|
|
-- |
|
|
|
(770.3 |
) |
Unit
option reimbursements to EPCO, Inc.
|
|
|
(0.6 |
) |
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
(0.6 |
) |
Cash
distributions paid to noncontrolling interest (see Note
10)
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
(39.2 |
) |
|
|
(39.2 |
) |
Net
cash proceeds from issuance of common units
|
|
|
55.4 |
|
|
|
1.1 |
|
|
|
-- |
|
|
|
-- |
|
|
|
56.5 |
|
Cash
proceeds from exercise of unit options
|
|
|
0.7 |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
0.7 |
|
Amortization
of equity awards
|
|
|
8.7 |
|
|
|
0.1 |
|
|
|
-- |
|
|
|
-- |
|
|
|
8.8 |
|
Interest
acquired from noncontrolling interest
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
(7.6 |
) |
|
|
(7.6 |
) |
Acquisition
of treasury units
|
|
|
(0.8 |
) |
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
(0.8 |
) |
Foreign
currency translation adjustment
|
|
|
-- |
|
|
|
-- |
|
|
|
0.5 |
|
|
|
-- |
|
|
|
0.5 |
|
Change
in funded status of pension and postretirement plans
|
|
|
-- |
|
|
|
-- |
|
|
|
(0.3 |
) |
|
|
-- |
|
|
|
(0.3 |
) |
Cash
flow hedges
|
|
|
-- |
|
|
|
-- |
|
|
|
(134.3 |
) |
|
|
(0.6 |
) |
|
|
(134.9 |
) |
Balance,
September 30, 2008
|
|
$ |
6,014.4 |
|
|
$ |
122.6 |
|
|
$ |
(115.0 |
) |
|
$ |
409.7 |
|
|
$ |
6,431.7 |
|
See Notes
to Unaudited Condensed Consolidated Financial Statements.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
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 millions of
dollars.
Partnership
Organization
Enterprise
Products Partners L.P. is a publicly traded Delaware limited partnership, the
common units of which are listed on the New York Stock Exchange (“NYSE”) under
the ticker symbol “EPD.” Unless the context requires otherwise,
references to “we,” “us,” “our” or “Enterprise Products Partners” are intended
to mean the business and operations of Enterprise Products Partners L.P. and its
consolidated subsidiaries.
We were
formed in April 1998 to own and operate certain natural gas liquids (“NGLs”)
related businesses of EPCO, Inc. (“EPCO”). We conduct substantially
all of our business through our wholly owned subsidiary, Enterprise Products
Operating LLC (“EPO”). We are owned 98% by our limited partners and
2% by Enterprise Products GP, LLC (our general partner, referred to as
“EPGP”). EPGP is owned 100% by Enterprise GP Holdings L.P.
(“Enterprise GP Holdings”), a publicly traded limited partnership, the units of
which are listed on the NYSE under the ticker symbol “EPE.” The
general partner of Enterprise GP Holdings is EPE Holdings, LLC (“EPE Holdings”),
a wholly owned subsidiary of Dan Duncan LLC, all of the membership interests of
which are owned by Dan L. Duncan. We, EPGP, Enterprise GP Holdings,
EPE Holdings and Dan Duncan LLC are affiliates and under the common control of
Dan L. Duncan, the Group Co-Chairman and controlling shareholder of
EPCO.
References
to “TEPPCO” and “TEPPCO GP” mean TEPPCO Partners, L.P. and Texas Eastern
Products Pipeline Company, LLC (which is the general partner of TEPPCO),
respectively, prior to their mergers with our subsidiaries. On
October 26, 2009, we completed the mergers with TEPPCO and TEPPCO GP (such
related mergers referred to herein individually and together as the “TEPPCO
Merger”). See Note 18 for additional information regarding the TEPPCO
Merger.
References
to “Energy Transfer Equity” mean the business and operations of Energy Transfer
Equity, L.P. and its consolidated subsidiaries. References to “LE GP”
mean LE GP, LLC, which is the general partner of Energy Transfer
Equity. Enterprise GP Holdings owns a noncontrolling interest in both
LE GP and Energy Transfer Equity. Enterprise GP Holdings accounts for
its investments in LE GP and Energy Transfer Equity using the equity method of
accounting.
References
to “Employee Partnerships” mean EPE Unit L.P., EPE Unit II, L.P., EPE Unit III,
L.P., Enterprise Unit L.P. and EPCO Unit L.P., collectively, all of
which are privately held affiliates of EPCO.
For
financial reporting purposes, we consolidate the financial statements of Duncan
Energy Partners L.P. (“Duncan Energy Partners”) with those of our own and
reflect its operations in our business segments. We control Duncan
Energy Partners through our ownership of its general partner, DEP Holdings, LLC
(“DEP GP”). Also, due to common control of the entities by Dan L.
Duncan, the initial consolidated balance sheet of Duncan Energy Partners
reflects our historical carrying basis in each of the subsidiaries contributed
to Duncan Energy Partners. Public ownership of Duncan Energy
Partners’ net assets and earnings are presented as a component of noncontrolling
interest in our consolidated financial statements. The borrowings of
Duncan Energy Partners are presented as part of our consolidated debt; however,
neither Enterprise Products Partners L.P. nor EPO have any obligation for the
payment of interest or repayment of borrowings incurred by Duncan Energy
Partners.
Basis
of Presentation
Effective
January 1, 2009, we adopted new accounting guidance that has been codified under
Accounting Standards Codification (“ASC”) 810, Consolidation, which established
accounting and
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
reporting
standards for noncontrolling interests that were previously identified as
minority interest in our financial statements. The new guidance
requires, among other things, that (i) noncontrolling interests be presented as
a component of equity on our consolidated balance sheet (i.e., elimination of
the “mezzanine” presentation previously used for minority interest); (ii)
elimination of minority interest amounts as a deduction in deriving net income
or loss and, as a result, that net income or loss be allocated between
controlling and noncontrolling interests; and (iii) comprehensive income or loss
be allocated between controlling and noncontrolling
interest. Earnings per unit amounts are not affected by these
changes. See Note 2 for additional information regarding the
establishment of the ASC by the Financial Accounting Standards Board
(“FASB”). See Note 10 for additional information regarding
noncontrolling interest.
The new presentation and disclosure
requirements pertaining to noncontrolling interests have been applied
retroactively to the consolidated financial statements and notes included in
this Quarterly Report. As a result, net income reported for the three
and nine months ended September 30, 2008 in these financial statements is higher
than that disclosed previously; however, the allocation of such net income
results in our unitholders, general partner and noncontrolling interests (i.e.,
the former minority interest) receiving the same amounts as they did
previously.
Our
results of operations for the three and nine months ended September 30, 2009 are
not necessarily indicative of results expected for the full year.
Essentially
all of our assets, liabilities, revenues and expenses are recorded at EPO’s
level in our consolidated financial statements. Enterprise Products
Partners L.P. acts as guarantor of certain of EPO’s debt
obligations. See Note 17 for condensed consolidated financial
information of EPO.
In our opinion, the accompanying
Unaudited Condensed Consolidated Financial Statements include all adjustments
consisting of normal recurring accruals necessary for fair
presentation. Although we believe the disclosures in these financial
statements are adequate to make the information presented not misleading,
certain information and footnote disclosures normally included in annual
financial statements prepared in accordance with U.S. generally accepted
accounting principles (“GAAP”) have been condensed or omitted pursuant to the
rules and regulations of the U.S. Securities and Exchange Commission
(“SEC”). These Unaudited Condensed Consolidated Financial Statements
and Notes thereto should be read in conjunction with the Audited Consolidated
Financial Statements and Notes thereto included in our Current Report on Form
8-K dated July 8, 2009 (the “Recast Form 8-K”), which retroactively adjusted
portions of our Annual Report on Form 10-K for the year ended December 31,
2008. The Recast Form 8-K reflects our adoption of the provisions
under ASC 810 related to noncontrolling interests, our adoption of the
provisions under ASC 260, Earnings Per Share, pertaining to the application of
the two-class method to master limited partnerships in computing basic and
diluted earnings per unit, and the resulting change in presentation and
disclosure requirements.
Estimates
Preparing
our financial statements in conformity with GAAP requires management to make
estimates and assumptions that affect amounts presented in the financial
statements (e.g. assets, liabilities, revenues and expenses) and disclosures
about contingent assets and liabilities. Our actual results could
differ from these estimates. On an ongoing basis, management reviews
its estimates based on currently available information. Changes in
facts and circumstances may result in revised estimates.
Fair
Value Information
Cash and
cash equivalents and restricted cash, accounts receivable, accounts payable
and accrued expenses, and other current liabilities are carried at amounts which
reasonably approximate their fair values due to their short-term
nature. The estimated fair values of our fixed rate debt are based on
quoted market prices for such debt or debt of similar terms and
maturities. The carrying amounts of our variable rate debt
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
obligations
reasonably approximate their fair values due to their variable interest
rates. See Note 4 for fair value information associated with our
derivative instruments. The following table presents the estimated
fair values of our financial instruments at the dates indicated:
|
|
September
30, 2009
|
|
|
December
31, 2008
|
|
|
|
Carrying
|
|
|
Fair
|
|
|
Carrying
|
|
|
Fair
|
|
Financial
Instruments
|
|
Value
|
|
|
Value
|
|
|
Value
|
|
|
Value
|
|
Financial
assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents and restricted cash
|
|
$ |
176.6 |
|
|
$ |
176.6 |
|
|
$ |
239.2 |
|
|
$ |
239.2 |
|
Accounts
receivable
|
|
|
1,509.3 |
|
|
|
1,509.3 |
|
|
|
1,247.1 |
|
|
|
1,247.1 |
|
Financial
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
payable and accrued expenses
|
|
|
2,213.4 |
|
|
|
2,213.4 |
|
|
|
1,683.2 |
|
|
|
1,683.2 |
|
Other
current liabilities
|
|
|
220.9 |
|
|
|
220.9 |
|
|
|
252.7 |
|
|
|
252.7 |
|
Fixed-rate
debt (principal amount)
|
|
|
7,986.7 |
|
|
|
8,324.5 |
|
|
|
7,704.3 |
|
|
|
6,639.0 |
|
Variable-rate
debt
|
|
|
1,158.3 |
|
|
|
1,158.3 |
|
|
|
1,341.8 |
|
|
|
1,341.8 |
|
Recent
Accounting Developments
The
following information summarizes recently issued accounting guidance that will
or may affect our future financial statements.
Generally
Accepted Accounting Principles. In June 2009,
the FASB published ASC 105, Generally Accepted Accounting Principles, as the
source of authoritative GAAP for U.S. companies. The ASC reorganized
GAAP into a topical format and significantly changes the way users research
accounting issues. For SEC registrants, the rules and interpretive
releases of the SEC under federal securities laws are also sources of
authoritative GAAP. References to specific GAAP in our consolidated
financial statements now refer exclusively to the ASC. We adopted the
new codification on September 30, 2009.
Fair
Value Measurements. In April 2009,
the FASB issued ASC 820, Fair Value Measurements and Disclosures, to clarify
fair value accounting rules. This new accounting guidance establishes a
process to determine whether a market is active and a transaction is consummated
under distress. Companies should look at several factors and use
professional judgment to ascertain if a formerly active market has become
inactive. When estimating fair value, companies are required to place more
weight on observable transactions in orderly markets. Our adoption of
this new guidance on June 30, 2009 did not have any impact on our consolidated
financial statements or related disclosures.
In August
2009, the FASB issued Accounting Standards Update 2009-05, Measuring Liabilities
at Fair Value, to clarify how an entity should estimate the fair value of
liabilities. If a quoted price in an active market for an identical
liability is not available, a company must measure the fair value of the
liability using one of several valuation techniques (e.g., quoted prices for
similar liabilities or present value of cash flows). Our adoption of
this new guidance on October 1, 2009 did not have any impact on our consolidated
financial statements or related disclosures.
Financial
Instruments. In April 2009,
the FASB issued ASC 825, Financial Instruments, which requires companies to
provide in each interim report both qualitative and quantitative information
regarding fair value estimates for financial instruments not recorded on the
balance sheet at fair value. Previously, this was only an annual
requirement. Apart from adding the required fair value disclosures
within this Note 2, our adoption of this new guidance on June 30, 2009 did not
have a material impact on our consolidated financial statements or related
disclosures.
Subsequent
Events. In
May 2009, the FASB issued ASC 855, Subsequent Events, which governs the
accounting for, and disclosure of, events that occur after the balance sheet
date but before financial statements are issued or are available to be
issued. The date through which an entity has evaluated subsequent
events is now a required disclosure. Our adoption of this guidance on
June 30, 2009 did not have any impact on our consolidated financial
statements.
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
Consolidation
of Variable Interest Entities. In June 2009,
the FASB amended consolidation guidance for variable interest entities (“VIEs”)
under ASC 810. VIEs are entities whose equity investors do not have
sufficient equity capital at risk such that the entity cannot finance its own
activities. When a business has a “controlling financial interest” in
a VIE, the assets, liabilities and profit or loss of that entity must be
consolidated. A business must also consolidate a VIE when that
business has a “variable interest” that (i) provides the business with the power
to direct the activities that most significantly impact the economic performance
of the VIE and (ii) funds most of the entity’s expected losses and/or receives
most of the entity’s anticipated residual returns. The amended
guidance:
§
|
eliminates
the scope exception for qualifying special-purpose
entities;
|
§
|
amends
certain guidance for determining whether an entity is a
VIE;
|
§
|
expands
the list of events that trigger reconsideration of whether an entity is a
VIE;
|
§
|
requires
a qualitative rather than a quantitative analysis to determine the primary
beneficiary of a VIE;
|
§
|
requires
continuous assessments of whether a company is the primary beneficiary of
a VIE; and
|
§
|
requires
enhanced disclosures about a company’s involvement with a
VIE.
|
The
amended guidance is effective for us on January 1, 2010. At September
30, 2009, we did not have any VIEs based on prior guidance. We are in
the process of evaluating the amended guidance; however, our adoption and
implementation of this guidance is not expected to have an impact on our
consolidated financial statements.
Restricted
Cash
Restricted
cash represents amounts held in connection with our commodity derivative
instruments portfolio and related physical natural gas and NGL
purchases. Additional cash may be restricted to maintain this
portfolio as commodity prices fluctuate or deposit requirements
change. At September 30, 2009 and December 31, 2008, our restricted
cash amounts were $102.8 million and $203.8 million,
respectively. See Note 4 for additional information regarding
derivative instruments and hedging activities.
Subsequent
Events
We have
evaluated subsequent events through November 9, 2009, which is the date our
Unaudited Condensed Consolidated Financial Statements and Notes are being
issued.
Certain
key employees of EPCO participate in long-term incentive compensation plans
managed by EPCO. The compensation expense we record related to equity
awards is based on an allocation of the total cost of such incentive plans to
EPCO. We record our pro rata share of such costs based on the
percentage of time each employee spends on our consolidated business
activities. Such awards were not material to our consolidated
financial position, results of operations or cash flows for the periods
presented. The amount of equity-based compensation allocable to our
businesses was $5.5 million and $4.3 million for the three months ended
September 30, 2009 and 2008, respectively. For the nine months ended
September 30, 2009 and 2008, the amount of equity-based compensation allocable
to our businesses was $13.7 million and $10.6 million,
respectively.
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
EPCO
1998 Long-Term Incentive Plan
The EPCO
1998 Long-Term Incentive Plan (“EPCO 1998 Plan”) provides for the issuance of up
to 7,000,000 of our common units. After giving effect to the issuance
or forfeiture of option awards and restricted unit awards through September 30,
2009, a total of 428,847 additional common units could be issued under the EPCO
1998 Plan.
Unit
option awards. The following table presents option activity
under the EPCO 1998 Plan for the periods indicated:
|
|
|
|
|
|
|
|
Weighted-
|
|
|
|
|
|
|
|
|
|
Weighted-
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Remaining
|
|
|
Aggregate
|
|
|
|
Number
of
|
|
|
Strike
Price
|
|
|
Contractual
|
|
|
Intrinsic
|
|
|
|
Units
|
|
|
(dollars/unit)
|
|
|
Term
(in years)
|
|
|
Value
(1)
|
|
Outstanding
at December 31, 2008
|
|
|
2,168,500 |
|
|
$ |
26.32 |
|
|
|
|
|
|
|
Granted
(2)
|
|
|
30,000 |
|
|
$ |
20.08 |
|
|
|
|
|
|
|
Exercised
|
|
|
(56,000 |
) |
|
$ |
15.66 |
|
|
|
|
|
|
|
Forfeited
|
|
|
(365,000 |
) |
|
$ |
26.38 |
|
|
|
|
|
|
|
Outstanding
at September 30, 2009
|
|
|
1,777,500 |
|
|
$ |
26.54 |
|
|
|
4.6 |
|
|
$ |
3.0 |
|
Options
exercisable at
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September
30, 2009
|
|
|
652,500 |
|
|
$ |
23.71 |
|
|
|
4.7 |
|
|
$ |
3.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Aggregate
intrinsic value reflects fully vested unit options at September 30,
2009.
(2)
Aggregate
grant date fair value of these unit options issued during 2009 was $0.2
million based on the following assumptions: (i) a grant date market price
of our common units of $20.08 per unit; (ii) expected life of options of
5.0 years; (iii) risk-free interest rate of 1.81%; (iv) expected
distribution yield on our common units of 10%; and (v) expected unit price
volatility on our common units of 72.76%.
|
|
The total
intrinsic value of option awards exercised during the three months ended
September 30, 2009 and 2008 was $0.3 million and $0.1 million,
respectively. For each of the nine months ended September 30, 2009
and 2008, the total intrinsic value of option awards exercised was $0.6
million. At September 30, 2009, the estimated total unrecognized
compensation cost related to nonvested unit option awards granted under the EPCO
1998 Plan was $1.1 million. We will recognize our share of these
costs in accordance with the EPCO administrative services agreement (the “ASA”)
(see Note 12) over a weighted-average period of 1.8 years.
During
the nine months ended September 30, 2009 and 2008, we received cash of $0.5
million and $0.7 million, respectively, from the exercise of option awards
granted under the EPCO 1998 Plan. Conversely, our option-related
reimbursements to EPCO during each of these periods were $0.5 million and $0.6
million, respectively.
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
Restricted
unit awards. The following table summarizes information
regarding our restricted unit awards under the EPCO 1998 Plan for the periods
indicated:
|
|
|
|
|
Weighted-
|
|
|
|
|
|
|
Average
Grant
|
|
|
|
Number
of
|
|
|
Date
Fair Value
|
|
|
|
Units
|
|
|
per Unit
(1)
|
|
Restricted
units at December 31, 2008
|
|
|
2,080,600 |
|
|
|
|
Granted
(2)
|
|
|
1,016,950 |
|
|
$ |
20.65 |
|
Vested
|
|
|
(244,300 |
) |
|
$ |
26.66 |
|
Forfeited
|
|
|
(194,400 |
) |
|
$ |
28.92 |
|
Restricted
units at September 30, 2009
|
|
|
2,658,850 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Determined
by dividing the aggregate grant date fair value of awards by the number of
awards issued. The weighted-average grant date fair value per unit
for forfeited and vested awards is determined before an allowance for
forfeitures.
(2)
Net
of forfeitures, aggregate grant date fair value of restricted unit awards
issued during 2009 was $21.0 million based on grant date market prices of
our common units ranging from $20.08 to $27.66 per unit. Estimated
forfeiture rates ranged between 4.6% and 17%.
|
|
The total
fair value of restricted unit awards that vested during the three and nine
months ended September 30, 2009 was $6.2 million and $6.5 million,
respectively. At September 30, 2009, the estimated total unrecognized
compensation cost related to nonvested restricted unit awards granted under the
EPCO 1998 Plan was $39.6 million. We expect to recognize our share of
this cost over a weighted-average period of 2.5 years in accordance with the
ASA.
Phantom
unit awards and distribution equivalent rights. No phantom
unit awards or distribution equivalent rights have been issued as of September
30, 2009 under the EPCO 1998 Plan.
Enterprise
Products 2008 Long-Term Incentive Plan
The Enterprise Products 2008 Long-Term
Incentive Plan (“EPD 2008 LTIP”) provides for the issuance of up to 10,000,000
of our common units. After giving effect to the issuance or
forfeiture of option awards through September 30, 2009, a total of 7,865,000
additional common units could be issued under the EPD 2008 LTIP.
Unit
option awards. The following table
presents unit option activity under the EPD 2008 LTIP for the periods
indicated:
|
|
|
|
|
|
|
|
Weighted-
|
|
|
|
|
|
|
Weighted-
|
|
|
Average
|
|
|
|
|
|
|
Average
|
|
|
Remaining
|
|
|
|
Number
of
|
|
|
Strike
Price
|
|
|
Contractual
|
|
|
|
Units
|
|
|
(dollars/unit)
|
|
|
Term
(in years)
|
|
Outstanding
at December 31, 2008
|
|
|
795,000 |
|
|
$ |
30.93 |
|
|
|
|
Granted
(1)
|
|
|
1,430,000 |
|
|
$ |
23.53 |
|
|
|
|
Forfeited
|
|
|
(90,000 |
) |
|
$ |
30.93 |
|
|
|
|
Outstanding at September 30,
2009 (2)
|
|
|
2,135,000 |
|
|
$ |
25.97 |
|
|
|
4.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Net
of forfeitures, aggregate grant date fair value of these unit options
issued during 2009 was $6.5 million based on the following assumptions:
(i) a weighted-average grant date market price of our common units of
$23.53 per unit; (ii) weighted-average expected life of options of 4.9
years; (iii) weighted-average risk-free interest rate of 2.14%; (iv)
expected weighted-average distribution yield on our common units of 9.37%;
(v) expected weighted-average unit price volatility on our common units of
57.11%. An estimated forfeiture rate of 17% was applied to awards
granted during 2009.
(2)
No
unit options were exercisable as of September 30, 2009.
|
|
At
September 30, 2009, the estimated total unrecognized compensation cost related
to nonvested unit option awards granted under the EPD 2008 LTIP was $6.6
million. We expect to recognize our share of this cost over a
weighted-average period of 3.4 years in accordance with the ASA.
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
Phantom
unit awards. There were a total of 10,600 phantom units
outstanding at September 30, 2009 under the EPD 2008 LTIP. These
awards cliff vest in 2011 and 2012. At September 30, 2009 and
December 31, 2008, we had accrued an immaterial liability for compensation
related to these phantom unit awards.
Employee
Partnerships
As of
September 30, 2009, the estimated total unrecognized compensation cost related
to the five Employee Partnerships was $37.7 million. We will
recognize our share of these costs in accordance with the ASA over a
weighted-average period of 4.2 years.
DEP
GP Unit Appreciation Rights
At
September 30, 2009 and December 31, 2008, we had a total of 90,000 outstanding
unit appreciation rights (“UARs”) granted to non-employee directors of DEP GP
that cliff vest in 2012. If a director resigns prior to vesting, his
UAR awards are forfeited. At September 30, 2009 and December 31,
2008, we had accrued an immaterial liability for compensation related to these
UARs.
In the
course of our normal business operations, we are exposed to certain risks,
including changes in interest rates, commodity prices and, to a limited extent,
foreign exchange rates. In order to manage risks associated with
certain identifiable and anticipated transactions, we use derivative
instruments. Derivatives are financial instruments whose fair value
is determined by changes in a specified benchmark such as interest rates,
commodity prices or currency values. Typical derivative instruments
include futures, forward contracts, swaps and other instruments with similar
characteristics. Substantially all of our derivatives are used for
non-trading activities.
We are required to recognize derivative
instruments at fair value as either assets or liabilities on the balance
sheet. While all derivatives are required to be reported at fair
value on the balance sheet, changes in fair value of the derivative instruments
will be reported in different ways depending on the nature and effectiveness of
the hedging activities to which they are related. After meeting
specified conditions, a qualified derivative may be specifically designated as a
total or partial hedge of:
§
|
Changes
in the fair value of a recognized asset or liability, or an unrecognized
firm commitment - In a fair value hedge, all gains and losses (of both the
derivative instrument and the hedged item) are recognized in income during
the period of change.
|
§
|
Variable
cash flows of a forecasted transaction - In a cash flow hedge, the
effective portion of the hedge is reported in other comprehensive income
(“OCI”) and is reclassified into earnings when the forecasted transaction
affects earnings.
|
§
|
Foreign
currency exposure, such as through an unrecognized firm
commitment.
|
An effective hedge is one in which the
change in fair value of a derivative instrument can be expected to offset 80% to
125% of changes in the fair value of a hedged item at inception and throughout
the life of the hedging relationship. The effective portion of a
hedge is the amount by which the derivative instrument exactly offsets the
change in fair value of the hedged item during the reporting
period. Conversely, ineffectiveness represents the change in the fair
value of the derivative instrument that does not exactly offset the change in
the fair value of the hedged item. Any ineffectiveness associated
with a hedge is recognized in earnings immediately. Ineffectiveness
can be caused by, among other things, changes in the timing of forecasted
transactions or a mismatch of terms between the derivative instrument and the
hedged item.
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
Interest
Rate Derivative Instruments
We utilize interest rate swaps,
treasury locks and similar derivative instruments to manage our exposure to
changes in the interest rates of certain consolidated debt
agreements. This strategy is a component in controlling our cost of
capital associated with such borrowings.
The following table summarizes our
interest rate derivative instruments outstanding at September 30, 2009, all of
which were designated as hedging instruments under ASC 815-20, Hedging -
General:
|
Number
and Type of
|
Notional
|
Period
of
|
Rate
|
Accounting
|
Hedged
Transaction
|
Derivative
Employed
|
Amount
|
Hedge
|
Swap
|
Treatment
|
Enterprise
Products Partners:
|
|
|
|
|
|
Senior
Notes C
|
1
fixed-to-floating swap
|
$100.0
|
1/04
to 2/13
|
6.4%
to 2.8%
|
Fair
value hedge
|
Senior
Notes G
|
3
fixed-to-floating swaps
|
$300.0
|
10/04
to 10/14
|
5.6%
to 2.6%
|
Fair
value hedge
|
Senior
Notes P
|
7
fixed-to-floating swaps
|
$400.0
|
6/09
to 8/12
|
4.6%
to 2.7%
|
Fair
value hedge
|
Duncan
Energy Partners:
|
|
|
|
|
|
Variable-interest
rate borrowings
|
3
floating-to-fixed swaps
|
$175.0
|
9/07
to 9/10
|
0.3%
to 4.6%
|
Cash
flow hedge
|
The
changes in fair value of the fair value interest rate swaps and the related
hedged items were recorded on the balance sheet with the offset recorded as
interest expense. This resulted in an increase of interest expense of $2.5
million and $3.1 million, respectively, for the three and nine months ended
September 30, 2009.
At times,
we may use treasury lock derivative instruments to hedge the underlying U.S.
treasury rates related to forecasted issuances of debt. As cash flow
hedges, gains or losses on these instruments are recorded in OCI and amortized
to earnings using the effective interest method over the forecasted term of the
underlying fixed-rate debt. In March 2008, we terminated treasury
locks having a combined notional amount of $350.0 million. On April
1, 2008, we terminated additional treasury locks having a notional amount of
$250.0 million. We recognized an aggregate loss of $20.7 million in
OCI during the first quarter of 2008 related to these
terminations. We recognized no losses in OCI during the second
quarter of 2008 in connection with such terminations.
During the nine months ended September
30, 2009, we entered into three forward starting interest rate swaps to hedge
the underlying benchmark interest payments related to the forecasted issuances
of debt.
|
Number
and Type of
|
Notional
|
Period
of
|
Average
Rate
|
Accounting
|
Hedged
Transaction
|
Derivative
Employed
|
Amount
|
Hedge
|
Locked
|
Treatment
|
Enterprise
Products Partners:
|
|
|
|
|
|
Future
debt offering
|
1
forward starting swap
|
$50.0
|
6/10
to 6/20
|
3.3%
|
Cash
flow hedge
|
Future
debt offering
|
2
forward starting swaps
|
$200.0
|
2/11
to 2/21
|
3.6%
|
Cash
flow hedge
|
The fair market value of the forward
starting swaps was $8.1 million at September 30, 2009. We entered
into one additional forward starting swap for a notional amount of $50.0 million
in October 2009 to hedge an anticipated 10-year note offering until February
2011.
For
information regarding consolidated fair value amounts and gains and losses on
interest rate derivative instruments and related hedged items, see “Tabular
Presentation of Fair Value Amounts, and Gains and Losses on Derivative
Instruments and Related Hedged Items” within this Note 4.
Commodity
Derivative Instruments
The prices of natural gas, NGLs and
certain petrochemical products are subject to fluctuations in response to
changes in supply, demand, general market uncertainty and a variety of
additional factors that are beyond our control. In order to manage the
price risk associated with such products, we enter into
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
commodity
derivative instruments such as forwards, basis swaps and futures
contracts. The following table summarizes our commodity derivative
instruments outstanding at September 30, 2009:
|
Volume
(1)
|
Accounting
|
Derivative
Purpose
|
Current
|
Long-Term
(2)
|
Treatment
|
Derivatives
designated as hedging instruments:
|
|
|
|
Enterprise
Products Partners:
|
|
|
|
Natural
gas processing:
|
|
|
|
Forecasted
natural gas purchases for plant thermal reduction (“PTR”)
(3)
|
16.6
Bcf
|
n/a
|
Cash
flow hedge
|
Forecasted
NGL sales
|
1.0
MMBbls
|
n/a
|
Cash
flow hedge
|
Octane
enhancement:
|
|
|
|
Forecasted
purchases of NGLs
|
0.1
MMBbls
|
n/a
|
Cash
flow hedge
|
Forecasted
sales of NGLs
|
n/a
|
0.1
MMBbls
|
Cash
flow hedge
|
Forecasted
sales of octane enhancement products
|
1.0
MMBbls
|
n/a
|
Cash
flow hedge
|
Natural
gas marketing:
|
|
|
|
Natural
gas storage inventory management activities
|
7.2
Bcf
|
n/a
|
Fair
value hedge
|
Forecasted
purchases of natural gas
|
n/a
|
3.0
Bcf
|
Cash
flow hedge
|
Forecasted
sales of natural gas
|
4.2
Bcf
|
0.9
Bcf
|
Cash
flow hedge
|
NGL
marketing:
|
|
|
|
Forecasted
purchases of NGLs and related hydrocarbon products
|
2.7
MMBbls
|
0.1
MMBbls
|
Cash
flow hedge
|
Forecasted
sales of NGLs and related hydrocarbon products
|
7.0
MMBbls
|
0.4
MMBbls
|
Cash
flow hedge
|
|
|
|
|
Derivatives
not designated as hedging instruments:
|
|
|
|
Enterprise
Products Partners:
|
|
|
|
Natural
gas risk management activities (4) (5)
|
313.3
Bcf
|
34.4
Bcf
|
Mark-to-market
|
Duncan
Energy Partners:
|
|
|
|
Natural
gas risk management activities (5)
|
1.7
Bcf
|
n/a
|
Mark-to-market
|
(1)
Volume
for derivatives designated as hedging instruments reflects the total
amount of volumes hedged whereas volume for derivatives not designated as
hedging instruments reflects the absolute value of derivative notional
volumes.
(2)
The
maximum term for derivatives included in the long-term column is December
2012.
(3)
PTR
represents the British thermal unit equivalent of the NGLs extracted from
natural gas by a processing plant, and includes the natural gas used as
plant fuel to extract those liquids, plant flare and other
shortages. See the discussion below for the primary objective
of this strategy.
(4)
Volume
includes approximately 61.8 billion cubic feet (“Bcf”) of physical
derivative instruments that are predominantly priced as an index plus a
premium or minus a discount.
(5)
Reflects
the use of derivative instruments to manage risks associated with natural
gas transportation, processing and storage
assets.
|
The table above does not include
additional hedges of forecasted NGL sales executed under contracts that have
been designated as normal purchase and sale agreements. At
September 30, 2009, the volume hedged under these contracts was 4.6 million
barrels (“MMBbls”).
Certain of our derivative instruments
do not meet hedge accounting requirements; therefore, they are accounted for as
economic hedges using mark-to-market accounting.
Our three
predominant hedging strategies are hedging natural gas processing margins,
hedging anticipated future sales margins on NGLs associated with physical
volumes held in inventory and hedging the fair value of natural gas held in
inventory.
The
objective of our natural gas processing strategy is to hedge a level of gross
margins associated with the NGL forward sales contracts (i.e., NGL sales
revenues less actual costs for PTR and the gain or loss on the PTR hedge) by
locking in the cost of natural gas used for PTR through the use of commodity
derivative instruments. This program consists of:
§
|
the
forward sale of a portion of our expected equity NGL production at fixed
prices through December 2009, and
|
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
§
|
the
purchase, using commodity derivative instruments, of the amount of natural
gas expected to be consumed as PTR in the production of such equity NGL
production.
|
At September 30, 2009, this program had
hedged future estimated gross margins (before plant operating expenses) of
$131.0 million on 5.0 MMBbls of forecasted NGL forward sales transactions
extending through December 2009.
The
objective of our NGL sales hedging program is to hedge future sales margins on
physical NGL inventory by locking in the sales price through the use of
commodity derivative instruments.
The objective of our natural gas
inventory hedging program is to hedge the fair value of natural gas currently
held in inventory by locking in the sales price of the inventory through the use
of commodity derivative instruments.
For
information regarding consolidated fair value amounts and gains and losses on
commodity derivative instruments and related hedged items, see “Tabular
Presentation of Fair Value Amounts, and Gains and Losses on Derivative
Instruments and Related Hedged Items” within this Note 4.
Foreign
Currency Derivative Instruments
We are exposed to foreign currency
exchange risk in connection with our NGL and natural gas marketing activities in
Canada. As a result, we could be adversely affected by fluctuations
in currency rates between the U.S. dollar and Canadian dollar. In
order to manage this risk, we may enter into foreign exchange purchase contracts
to lock in the exchange rate. Prior to 2009, these derivative
instruments were accounted for using mark-to-market
accounting. Beginning with the first quarter of 2009, the long-term
transactions (more than two months) are accounted for as cash flow
hedges. Shorter term transactions are accounted for using
mark-to-market accounting.
In addition, we were exposed to foreign
currency exchange risk in connection with a term loan denominated in Japanese
yen (see Note 9). We entered into this loan agreement in November
2008 and the loan matured in March 2009. The derivative instrument
used to hedge this risk was accounted for as a cash flow hedge and settled upon
repayment of the loan.
At
September 30, 2009, we had foreign currency derivative instruments outstanding
with a notional amount of $5.5 million Canadian. The fair market
value of these instruments was an asset of $0.3 million at September 30,
2009.
For
information regarding consolidated fair value amounts and gains and losses on
foreign currency derivative instruments and related hedged items, see “Tabular
Presentation of Fair Value Amounts, and Gains and Losses on Derivative
Instruments and Related Hedged Items” within this Note 4.
Credit-Risk
Related Contingent Features in Derivative Instruments
A limited
number of our commodity derivative instruments include provisions related to
credit ratings and/or adequate assurance clauses. A credit rating
provision provides for a counterparty to demand immediate full or partial
payment to cover a net liability position upon the loss of a stipulated credit
rating. An adequate assurance clause provides for a counterparty to demand
immediate full or partial payment to cover a net liability position should
reasonable grounds for insecurity arise with respect to contractual performance
by either party. At September 30, 2009, the aggregate fair value of
our over-the-counter derivative instruments in a net liability position was $5.7
million, the total of which was subject to a credit rating contingent
feature. If our credit ratings were downgraded to Ba2/BB,
approximately $5.0 million would be payable as a margin deposit to the
counterparties, and if our credit ratings were downgraded to Ba3/BB- or below,
approximately $5.7 million would be payable as a margin deposit to the
counterparties. Currently, no margin is required to be
deposited. The potential for derivatives with contingent features to
enter a net liability position may change in the future as positions and prices
fluctuate.
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
Tabular
Presentation of Fair Value Amounts, and Gains and Losses on
Derivative
Instruments and Related Hedged Items
The
following table provides a balance sheet overview of our derivative assets and
liabilities at the dates indicated:
|
Asset
Derivatives
|
|
Liability
Derivatives
|
|
September
30, 2009
|
|
December
31, 2008
|
|
September
30, 2009
|
|
December
31, 2008
|
|
Balance
Sheet
|
Fair
|
|
Balance
Sheet
|
Fair
|
|
Balance
Sheet
|
Fair
|
|
Balance
Sheet
|
Fair
|
|
Location
|
Value
|
|
Location
|
Value
|
|
Location
|
Value
|
|
Location
|
Value
|
Derivatives
designated as hedging instruments:
|
Interest
rate derivatives
|
Derivative
assets
|
$ |
23.2 |
|
Derivative
assets
|
$ |
7.8 |
|
Derivative
liabilities
|
$ |
6.0 |
|
Derivative
liabilities
|
$ |
5.9 |
Interest
rate derivatives
|
Other
assets
|
|
33.4 |
|
Other
assets
|
|
39.0 |
|
Other
liabilities
|
|
2.0 |
|
Other
liabilities
|
|
3.9 |
Total
interest rate derivatives
|
|
|
56.6 |
|
|
|
46.8 |
|
|
|
8.0 |
|
|
|
9.8 |
Commodity
derivatives
|
Derivative
assets
|
|
51.9 |
|
Derivative
assets
|
|
150.5 |
|
Derivative
liabilities
|
|
133.2 |
|
Derivative
liabilities
|
|
253.5 |
Commodity
derivatives
|
Other
assets
|
|
0.2 |
|
Other
assets
|
|
-- |
|
Other
liabilities
|
|
2.1 |
|
Other
liabilities
|
|
0.2 |
Total
commodity derivatives (1)
|
|
|
52.1 |
|
|
|
150.5 |
|
|
|
135.3 |
|
|
|
253.7 |
Foreign
currency derivatives (2)
|
Derivative
assets
|
|
0.3 |
|
Derivative
assets
|
|
9.3 |
|
Derivative
liabilities
|
|
-- |
|
Derivative
liabilities
|
|
-- |
Total
derivatives designated as hedging instruments
|
|
$ |
109.0 |
|
|
$ |
206.6 |
|
|
$ |
143.3 |
|
|
$ |
263.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives
not designated as hedging instruments:
|
Commodity
derivatives
|
Derivative
assets
|
$ |
121.6 |
|
Derivative
assets
|
$ |
35.2 |
|
Derivative
liabilities
|
$ |
123.9 |
|
Derivative
liabilities
|
$ |
27.7 |
Commodity
derivatives
|
Other
assets
|
|
1.1 |
|
Other
assets
|
|
-- |
|
Other
liabilities
|
|
2.4 |
|
Other
liabilities
|
|
-- |
Total
commodity derivatives
|
|
|
122.7 |
|
|
|
35.2 |
|
|
|
126.3 |
|
|
|
27.7 |
Foreign
currency derivatives
|
Derivative
assets
|
|
-- |
|
Derivative
assets
|
|
-- |
|
Derivative
liabilities
|
|
-- |
|
Derivative
liabilities
|
|
0.1 |
Total
derivatives not designated as hedging instruments
|
|
$ |
122.7 |
|
|
$ |
35.2 |
|
|
$ |
126.3 |
|
|
$ |
27.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Represent
commodity derivative instrument transactions that either have not settled
or have settled and not been invoiced. Settled and invoiced
transactions are reflected in either accounts receivable or accounts
payable depending on the outcome of the transaction.
(2)
Relates
to the hedging of our exposure to fluctuations in the foreign currency
exchange rate related to our Canadian NGL marketing
subsidiary.
|
The
following tables present the effect of our derivative instruments designated as
fair value hedges on our Unaudited Condensed Statements of Consolidated
Operations for the periods indicated:
Derivatives
in
|
|
|
|
|
Fair
Value
|
|
|
Gain/(Loss)
Recognized in
|
|
Hedging
Relationships
|
Location
|
|
Income
on Derivative
|
|
|
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Interest
rate derivatives
|
Interest
expense
|
|
$ |
12.0 |
|
|
$ |
4.2 |
|
|
$ |
(4.2 |
) |
|
$ |
(1.7 |
) |
Commodity
derivatives
|
Revenue
|
|
|
0.6 |
|
|
|
-- |
|
|
|
(0.1 |
) |
|
|
-- |
|
Total
|
|
|
$ |
12.6 |
|
|
$ |
4.2 |
|
|
$ |
(4.3 |
) |
|
$ |
(1.7 |
) |
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
Derivatives
in
|
|
|
|
|
Fair
Value
|
|
|
Gain/(Loss)
Recognized in
|
|
Hedging
Relationships
|
Location
|
|
Income
on Hedged Item
|
|
|
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Interest
rate derivatives
|
Interest
expense
|
|
$ |
(14.5 |
) |
|
$ |
(4.2 |
) |
|
$ |
1.1 |
|
|
$ |
1.7 |
|
Commodity
derivatives
|
Revenue
|
|
|
(0.5 |
) |
|
|
-- |
|
|
|
0.6 |
|
|
|
-- |
|
Total
|
|
|
$ |
(15.0 |
) |
|
$ |
(4.2 |
) |
|
$ |
1.7 |
|
|
$ |
1.7 |
|
The
following tables present the effect of our derivative instruments designated as
cash flow hedges on our Unaudited Condensed Statements of Consolidated
Operations for the periods indicated:
Derivatives
in
|
|
Change
in Value
|
|
Cash
Flow
|
|
Recognized
in OCI on
|
|
Hedging
Relationships
|
|
Derivative
(Effective Portion)
|
|
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Interest
rate derivatives
|
|
$ |
(8.0 |
) |
|
$ |
(1.1 |
) |
|
$ |
7.1 |
|
|
$ |
(22.9 |
) |
Commodity
derivatives – Revenue
|
|
|
(21.3 |
) |
|
|
(25.3 |
) |
|
|
44.5 |
|
|
|
(30.2 |
) |
Commodity
derivatives – Operating costs and expenses
|
|
|
13.0 |
|
|
|
(218.7 |
) |
|
|
(191.4 |
) |
|
|
(93.9 |
) |
Foreign
currency derivatives
|
|
|
0.2 |
|
|
|
-- |
|
|
|
(10.3 |
) |
|
|
(1.3 |
) |
Total
|
|
$ |
(16.1 |
) |
|
$ |
(245.1 |
) |
|
$ |
(150.1 |
) |
|
$ |
(148.3 |
) |
Derivatives
in
|
Location
of Gain/(Loss)
|
|
Amount
of Gain/(Loss)
|
|
Cash
Flow
|
Reclassified
from AOCI
|
|
Reclassified
from AOCI
|
|
Hedging
Relationships
|
into
Income (Effective Portion)
|
|
to
Income (Effective Portion)
|
|
|
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Interest
rate derivatives
|
Interest
expense
|
|
$ |
(1.3 |
) |
|
$ |
-- |
|
|
$ |
(3.3 |
) |
|
$ |
2.4 |
|
Commodity
derivatives
|
Revenue
|
|
|
(12.5 |
) |
|
|
(17.2 |
) |
|
|
7.2 |
|
|
|
(23.3 |
) |
Commodity
derivatives
|
Operating
costs and expenses
|
|
|
(65.3 |
) |
|
|
(11.3 |
) |
|
|
(183.5 |
) |
|
|
7.5 |
|
Total
|
|
|
$ |
(79.1 |
) |
|
$ |
(28.5 |
) |
|
$ |
(179.6 |
) |
|
$ |
(13.4 |
) |
|
Location
of Gain/(Loss)
|
|
Amount
of Gain/(Loss)
|
|
Derivatives
in
|
Recognized
in Income
|
|
Recognized
in Income on
|
|
Cash
Flow
|
on
Ineffective Portion
|
|
Ineffective
Portion of
|
|
Hedging
Relationships
|
of
Derivative
|
|
Derivative
|
|
|
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Commodity
derivatives
|
Revenue
|
|
$ |
0.8 |
|
|
$ |
-- |
|
|
$ |
0.1 |
|
|
$ |
-- |
|
Commodity
derivatives
|
Operating
costs and expenses
|
|
|
(1.0 |
) |
|
|
(5.7 |
) |
|
|
(2.3 |
) |
|
|
(2.9 |
) |
Total
|
|
|
$ |
(0.2 |
) |
|
$ |
(5.7 |
) |
|
$ |
(2.2 |
) |
|
$ |
(2.9 |
) |
Over the
next twelve months, we expect to reclassify $5.3 million of accumulated other
comprehensive loss (“AOCI”) attributable to interest rate derivative instruments
to earnings as an increase to interest expense. Likewise, we expect to
reclassify $81.3 million of AOCI attributable to commodity derivative
instruments to earnings, $32.1 million as an increase in operating costs and
expenses and $49.2 million as a reduction in revenues.
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
The
following table presents the effect of our derivative instruments not designated
as hedging instruments on our Unaudited Condensed Statements of Consolidated
Operations for the periods indicated:
Derivatives
Not Designated
|
|
|
Gain/(Loss)
Recognized in
|
|
as Hedging
Instruments
|
Location
|
|
Income
on Derivative
|
|
|
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Commodity
derivatives (1)
|
Revenue
|
|
$ |
(6.1 |
) |
|
$ |
38.1 |
|
|
$ |
25.4 |
|
|
$ |
35.2 |
|
Commodity
derivatives
|
Operating
costs and expenses
|
|
|
-- |
|
|
|
1.9 |
|
|
|
-- |
|
|
|
(7.1 |
) |
Foreign
currency derivatives
|
Other
income
|
|
|
-- |
|
|
|
-- |
|
|
|
(0.1 |
) |
|
|
-- |
|
Total
|
|
|
$ |
(6.1 |
) |
|
$ |
40.0 |
|
|
$ |
25.3 |
|
|
$ |
28.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Amounts
for the three and nine months ended September 30, 2009 include $0.9
million and $3.8 million of gains on derivatives excluded from the
assessment of hedge effectiveness under fair value hedging relationships,
respectively.
|
|
Fair
Value Measurements
Fair
value is defined as the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at a
specified measurement date. Our fair value estimates are based on
either (i) actual market data or (ii) assumptions that other market participants
would use in pricing an asset or liability, including estimates of risk.
Recognized valuation techniques employ inputs such as product prices, operating
costs, discount factors and business growth rates. These inputs may
be either readily observable, corroborated by market data or generally
unobservable. In developing our estimates of fair value, we endeavor
to utilize the best information available and apply market-based data to the
extent possible. Accordingly, we utilize valuation techniques (such
as the market approach) that maximize the use of observable inputs and minimize
the use of unobservable inputs.
A
three-tier hierarchy has been established that classifies fair value amounts
recognized or disclosed in the financial statements based on the observability
of inputs used to estimate such fair values. The hierarchy considers
fair value amounts based on observable inputs (Levels 1 and 2) to be more
reliable and predictable than those based primarily on unobservable inputs
(Level 3). At each balance sheet reporting date, we categorize our
financial assets and liabilities using this hierarchy. The
characteristics of fair value amounts classified within each level of the
hierarchy are described as follows:
§
|
Level
1 fair values are based on quoted prices, which are available in active
markets for identical assets or liabilities as of the measurement
date. Active markets are defined as those in which transactions
for identical assets or liabilities occur with sufficient frequency so as
to provide pricing information on an ongoing basis (e.g., the New York
Mercantile Exchange). Our Level 1 fair values primarily consist
of financial assets and liabilities such as exchange-traded commodity
financial instruments.
|
§
|
Level
2 fair values are based on pricing inputs other than quoted prices in
active markets (as reflected in Level 1 fair values) and are either
directly or indirectly observable as of the measurement
date. Level 2 fair values include instruments that are valued
using financial models or other appropriate valuation
methodologies. Such financial models are primarily
industry-standard models that consider various assumptions, including
quoted forward prices for commodities, the time value of money, volatility
factors, current market and contractual prices for the underlying
instruments and other relevant economic measures. Substantially
all of these assumptions are (i) observable in the marketplace throughout
the full term of the instrument, (ii) can be derived from observable data
or (iii) are validated by inputs other than quoted prices (e.g., interest
rate and yield curves at commonly quoted intervals). Our Level
2 fair values primarily consist of commodity financial instruments such as
forwards, swaps and other instruments transacted on an exchange or over
the counter. The fair values of these derivatives are based on
observable price quotes for similar products and locations. The
value of our interest rate
|
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
derivatives are valued by using appropriate
financial models with the implied forward London Interbank Offered Rate
yield curve for the same period as the future interest swap settlements.
§
|
Level
3 fair values are based on unobservable inputs. Unobservable
inputs are used to measure fair value to the extent that observable inputs
are not available, thereby allowing for situations in which there is
little, if any, market activity for the asset or liability at the
measurement date. Unobservable inputs reflect the reporting
entity’s own ideas about the assumptions that market participants would
use in pricing an asset or liability (including assumptions about
risk). Unobservable inputs are based on the best information
available in the circumstances, which might include the reporting entity’s
internally developed data. The reporting entity must not ignore
information about market participant assumptions that is reasonably
available without undue cost and effort. Level 3 inputs are
typically used in connection with internally developed valuation
methodologies where management makes its best estimate of an instrument’s
fair value. Our Level 3 fair values largely consist of ethane
and normal butane-based contracts with a range of two to twelve months in
term. We rely on broker quotes for these
products.
|
The
following table sets forth, by level within the fair value hierarchy, our
financial assets and liabilities measured on a recurring basis at September 30,
2009. These financial assets and liabilities are classified in their
entirety based on the lowest level of input that is significant to the fair
value measurement. Our assessment of the significance of a particular
input to the fair value measurement requires judgment, and may affect the
valuation of the fair value assets and liabilities and their placement within
the fair value hierarchy levels.
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
3
|
|
|
Total
|
|
Financial
assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
rate derivative instruments
|
|
$ |
-- |
|
|
$ |
56.6 |
|
|
$ |
-- |
|
|
$ |
56.6 |
|
Commodity
derivative instruments
|
|
|
10.9 |
|
|
|
151.8 |
|
|
|
12.1 |
|
|
|
174.8 |
|
Foreign
currency derivative instruments
|
|
|
-- |
|
|
|
0.3 |
|
|
|
-- |
|
|
|
0.3 |
|
Total
|
|
$ |
10.9 |
|
|
$ |
208.7 |
|
|
$ |
12.1 |
|
|
$ |
231.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
rate derivative instruments
|
|
$ |
-- |
|
|
$ |
8.0 |
|
|
$ |
-- |
|
|
$ |
8.0 |
|
Commodity
derivative instruments
|
|
|
36.7 |
|
|
|
211.1 |
|
|
|
13.8 |
|
|
|
261.6 |
|
Total
|
|
$ |
36.7 |
|
|
$ |
219.1 |
|
|
$ |
13.8 |
|
|
$ |
269.6 |
|
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
The
following table sets forth a reconciliation of changes in the fair value of our
Level 3 financial assets and liabilities for the periods presented:
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
Balance,
January 1
|
|
$ |
32.6 |
|
|
$ |
(4.6 |
) |
Total
gains (losses) included in:
|
|
|
|
|
|
|
|
|
Net
income (1)
|
|
|
12.5 |
|
|
|
(2.3 |
) |
Other
comprehensive income (loss)
|
|
|
1.5 |
|
|
|
2.4 |
|
Purchases,
issuances, settlements
|
|
|
(12.5 |
) |
|
|
1.9 |
|
Balance,
March 31
|
|
|
34.1 |
|
|
|
(2.6 |
) |
Total
gains (losses) included in:
|
|
|
|
|
|
|
|
|
Net
income (1)
|
|
|
7.7 |
|
|
|
0.3 |
|
Other
comprehensive income (loss)
|
|
|
(23.1 |
) |
|
|
(2.4 |
) |
Purchases,
issuances, settlements
|
|
|
(7.7 |
) |
|
|
0.1 |
|
Transfers
out of Level 3
|
|
|
(0.2 |
) |
|
|
-- |
|
Balance,
June 30
|
|
|
10.8 |
|
|
|
(4.6 |
) |
Total
gains (losses) included in:
|
|
|
|
|
|
|
|
|
Net
income (1)
|
|
|
6.5 |
|
|
|
(2.2 |
) |
Other
comprehensive income (loss)
|
|
|
(10.2 |
) |
|
|
23.1 |
|
Purchases,
issuances, settlements
|
|
|
(6.5 |
) |
|
|
2.2 |
|
Transfers
out of Level 3
|
|
|
(2.3 |
) |
|
|
-- |
|
Balance,
September 30
|
|
$ |
(1.7 |
) |
|
$ |
18.5 |
|
|
|
|
|
|
|
|
|
|
(1)
There
were $4.8 million and $5.0 million of unrealized losses included in these
amounts for the three and nine months ended September 30, 2009,
respectively. For the three and nine months ended September 30, 2008,
there were no unrealized gains or losses included in these
amounts.
|
|
Nonfinancial
Assets and Liabilities
Certain
nonfinancial assets and liabilities are measured at fair value on a nonrecurring
basis and are subject to fair value adjustments in certain circumstances (for
example, when there is evidence of impairment). There were no
material fair value adjustments for such assets or liabilities reflected in our
consolidated financial statements for the three and nine months ended September
30, 2009.
Our inventory amounts were as follows
at the dates indicated:
|
|
September
30,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
Working
inventory (1)
|
|
$ |
508.1 |
|
|
$ |
200.4 |
|
Forward
sales inventory (2)
|
|
|
639.4 |
|
|
|
162.4 |
|
Total
inventory
|
|
$ |
1,147.5 |
|
|
$ |
362.8 |
|
|
|
|
|
|
|
|
|
|
(1)
Working
inventory is comprised of inventories of natural gas, NGLs and certain
petrochemical products that are either available-for-sale or used in
providing services.
(2)
Forward
sales inventory consists of identified NGL and natural gas volumes
dedicated to the fulfillment of forward sales contracts. As a result
of energy market conditions, we significantly increased our physical
inventory purchases and related forward physical sales commitments during
2009. In general, the significant increase in volumes dedicated to
forward physical sales contracts improves the overall utilization and
profitability of our fee-based assets.
|
|
Our
inventory values reflect payments for product purchases, freight charges
associated with such purchase volumes, terminal and storage fees, vessel
inspection costs, demurrage charges and other related
costs. Inventories are valued at the lower of average cost or
market.
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
Operating
costs and expenses, as presented on our Unaudited Condensed Statements of
Consolidated Operations, include cost of sales amounts related to the sale of
inventories. Our costs of sales amounts were $3.72 billion and $5.47
billion for the three months ended September 30, 2009 and 2008,
respectively. For the nine months ended September 30, 2009 and 2008,
our costs of sales amounts were $9.05 billion and $15.88 billion,
respectively. The decrease in cost of sales period-to-period is
primarily due to lower energy commodity prices associated with our marketing
activities.
Due to
fluctuating commodity prices, we recognize lower of average cost or market
(“LCM”) adjustments when the carrying value of our available-for-sale
inventories exceed their net realizable value. These non-cash charges
are a component of cost of sales in the period they are recognized, and
reflected in operating costs and expenses as presented on our Unaudited
Condensed Statements of Consolidated Operations. LCM adjustments may
be mitigated or offset through the use of commodity hedging instruments to the
extent such instruments affect net realizable value. See Note 4 for a
description of our commodity hedging activities. For the three months
ended September 30, 2009 and 2008, we recognized LCM adjustments of $0.4 million
and $36.5 million, respectively. We recognized LCM adjustments of
$6.4 million and $41.3 million for the nine months ended September 30, 2009 and
2008, respectively.
Our
property, plant and equipment values and accumulated depreciation balances were
as follows at the dates indicated:
|
|
Estimated
|
|
|
|
|
|
|
|
|
|
Useful
Life
|
|
|
September
30,
|
|
|
December
31,
|
|
|
|
in
Years
|
|
|
2009
|
|
|
2008
|
|
Plants
and pipelines (1)
|
|
|
3-45
(5) |
|
|
$ |
13,927.2 |
|
|
$ |
12,296.3 |
|
Underground
and other storage facilities (2)
|
|
|
5-35
(6) |
|
|
|
944.2 |
|
|
|
900.7 |
|
Platforms
and facilities (3)
|
|
|
20-31 |
|
|
|
637.6 |
|
|
|
634.8 |
|
Transportation
equipment (4)
|
|
|
3-10 |
|
|
|
41.5 |
|
|
|
38.7 |
|
Land
|
|
|
|
|
|
|
59.4 |
|
|
|
54.6 |
|
Construction
in progress
|
|
|
|
|
|
|
802.8 |
|
|
|
1,604.7 |
|
Total
|
|
|
|
|
|
|
16,412.7 |
|
|
|
15,529.8 |
|
Less
accumulated depreciation
|
|
|
|
|
|
|
2,751.1 |
|
|
|
2,375.0 |
|
Property,
plant and equipment, net
|
|
|
|
|
|
$ |
13,661.6 |
|
|
$ |
13,154.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Plants
and pipelines include processing plants; NGL, petrochemical, crude oil and
natural gas pipelines; terminal loading and unloading facilities; office
furniture and equipment; buildings; laboratory and shop equipment; and
related assets.
(2)
Underground
and other storage facilities include underground product storage caverns;
storage tanks; water wells; and related assets.
(3)
Platforms
and facilities include offshore platforms and related facilities and other
associated assets.
(4)
Transportation
equipment includes vehicles and similar assets used in our
operations.
(5)
In
general, the estimated useful lives of major components of this category
are as follows: processing plants, 20-35 years; pipelines, 18-45
years (with some equipment at 5 years); terminal facilities, 10-35 years;
office furniture and equipment, 3-20 years; buildings, 20-35 years; and
laboratory and shop equipment, 5-35 years.
(6)
In
general, the estimated useful lives of major components of this category
are as follows: underground storage facilities, 20-35 years (with
some components at 5 years); storage tanks, 10-35 years; and water wells,
25-35 years (with some components at 5 years).
|
|
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
The
following table summarizes our depreciation expense and capitalized interest
amounts for the periods indicated:
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Depreciation
expense (1)
|
|
$ |
138.0 |
|
|
$ |
115.5 |
|
|
$ |
393.5 |
|
|
$ |
339.3 |
|
Capitalized
interest (2)
|
|
|
6.6 |
|
|
|
17.3 |
|
|
|
24.3 |
|
|
|
53.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Depreciation
expense is a component of costs and expenses as presented in our Unaudited
Condensed Statements of Consolidated Operations.
(2) Capitalized
interest increases the carrying value of the associated asset and reduces
interest expense during the period it is recorded.
|
|
In May
2009, we acquired certain rail and truck terminal facilities located in Mont
Belvieu, Texas from Martin Midstream Partners L.P. (“Martin”). Cash
consideration paid for this business combination was $23.7 million, all of which
was recorded as additions to property, plant and equipment.
On a pro
forma consolidated basis, our revenues, costs and expenses, operating income,
net income and earnings per unit amounts would not have differed materially from
those we actually reported for the three and nine months ended September 30,
2009 and 2008 due to the immaterial nature of our 2009 business combination
transaction.
Asset
Retirement Obligations
Asset
retirement obligations (“AROs”) are legal obligations associated with the
retirement of certain tangible long-lived assets that result from acquisitions,
construction, development and/or normal operations. The following
table presents information regarding our AROs since December 31,
2008.
ARO
liability balance, December 31, 2008
|
|
$ |
37.7 |
|
Liabilities
incurred
|
|
|
0.4 |
|
Liabilities
settled
|
|
|
(13.6 |
) |
Revisions
in estimated cash flows
|
|
|
23.6 |
|
Accretion
expense
|
|
|
2.0 |
|
ARO
liability balance, September 30, 2009
|
|
$ |
50.1 |
|
The
increase in our ARO liability balance during 2009 primarily reflects revised
estimates of the cost to comply with regulatory abandonment obligations
associated with our facilities offshore in the Gulf of Mexico. We
incurred $13.6 million of costs through September 30, 2009 as a result of ARO
settlement activities associated with certain pipeline laterals and a platform
located in the Gulf of Mexico.
Property,
plant and equipment at September 30, 2009 and December 31, 2008 includes $25.7
million and $9.9 million, respectively, of asset retirement costs capitalized as
an increase in the associated long-lived asset. Based on information
currently available, we estimate that accretion expense will approximate $0.9
million for the fourth quarter of 2009, $3.5 million for 2010, $3.4 million for
2011, $3.7 million for 2012 and $4.0 million for 2013.
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
We own
interests in a number of related businesses that are accounted for using the
equity method of accounting. Our investments in unconsolidated
affiliates are grouped according to the business segment to which they
relate. See Note 11 for a general discussion of our business
segments. The following table shows our investments in unconsolidated
affiliates at the dates indicated:
|
|
Ownership
|
|
|
|
|
|
|
Percentage
at
|
|
|
|
|
|
|
September
30,
|
|
|
September
30,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2009
|
|
|
2008
|
|
NGL
Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
Venice
Energy Service Company, L.L.C.
|
|
|
13.1% |
|
|
$ |
33.1 |
|
|
$ |
37.7 |
|
K/D/S
Promix, L.L.C. (“Promix”)
|
|
|
50% |
|
|
|
47.8 |
|
|
|
46.4 |
|
Baton
Rouge Fractionators LLC
|
|
|
32.2% |
|
|
|
23.6 |
|
|
|
24.1 |
|
Skelly-Belvieu
Pipeline Company, L.L.C. (“Skelly-Belvieu”)
|
|
|
49% |
|
|
|
37.4 |
|
|
|
36.0 |
|
Onshore
Natural Gas Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
Jonah
Gas Gathering Company (“Jonah”)
|
|
|
19.4% |
|
|
|
250.1 |
|
|
|
258.1 |
|
Evangeline
(1)
|
|
|
49.5% |
|
|
|
5.4 |
|
|
|
4.5 |
|
White
River Hub, LLC
|
|
|
50% |
|
|
|
27.0 |
|
|
|
21.4 |
|
Offshore
Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
Poseidon
Oil Pipeline, L.L.C. (“Poseidon”)
|
|
|
36% |
|
|
|
61.3 |
|
|
|
60.2 |
|
Cameron
Highway Oil Pipeline Company (“Cameron Highway”)
|
|
|
50% |
|
|
|
243.2 |
|
|
|
250.8 |
|
Deepwater
Gateway, L.L.C.
|
|
|
50% |
|
|
|
102.8 |
|
|
|
104.8 |
|
Neptune
Pipeline Company, L.L.C. (“Neptune”)
|
|
|
25.7% |
|
|
|
54.4 |
|
|
|
52.7 |
|
Nemo
Gathering Company, LLC
|
|
|
33.9% |
|
|
|
-- |
|
|
|
0.4 |
|
Texas
Offshore Port System (“TOPS”) (2)
|
|
|
-- |
|
|
|
-- |
|
|
|
35.9 |
|
Petrochemical
Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
Baton
Rouge Propylene Concentrator, LLC
|
|
|
30% |
|
|
|
11.4 |
|
|
|
12.6 |
|
La
Porte (3)
|
|
|
50% |
|
|
|
3.5 |
|
|
|
3.9 |
|
Total
|
|
|
|
|
|
$ |
901.0 |
|
|
$ |
949.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Refers
to our ownership interests in Evangeline Gas Pipeline Company, L.P. and
Evangeline Gas Corp., collectively.
(2) In
April 2009, we elected to dissociate from this partnership and forfeit our
investment (see discussion below).
(3) Refers
to our ownership interests in La Porte Pipeline Company, L.P. and La Porte
GP, LLC, collectively.
|
|
Our
investments in Promix, La Porte, Neptune, Poseidon, Cameron Highway, Jonah and
Skelly-Belvieu include excess cost amounts totaling $54.8 million and $56.6
million at September 30, 2009 and December 31, 2008, respectively, all of which
are attributable to the fair value of the underlying tangible assets of these
entities exceeding their book carrying values at the time of our acquisition of
interests in these entities. To the extent that we attribute all or a
portion of an excess cost amount to higher fair values, we amortize such excess
cost as a reduction in equity earnings in a manner similar to
depreciation. To the extent we attribute an excess cost amount to
goodwill, we do not amortize this amount, but it is subject to evaluation for
impairment. Amortization of excess cost amounts was $0.6 million and
$0.5 million for the three months ended September 30, 2009 and 2008,
respectively. For the nine months ended September 30, 2009 and 2008,
amortization of such amounts was $1.8 million and $1.5 million,
respectively.
The
following table presents our equity in income (loss) of unconsolidated
affiliates by business segment for the periods indicated:
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
NGL
Pipelines & Services
|
|
$ |
4.0 |
|
|
$ |
3.0 |
|
|
$ |
7.5 |
|
|
$ |
2.3 |
|
Onshore
Natural Gas Pipelines & Services
|
|
|
7.4 |
|
|
|
5.6 |
|
|
|
21.7 |
|
|
|
16.9 |
|
Offshore
Pipelines & Services
|
|
|
10.6 |
|
|
|
6.0 |
|
|
|
(12.1 |
) |
|
|
27.9 |
|
Petrochemical
Services
|
|
|
0.5 |
|
|
|
0.3 |
|
|
|
1.2 |
|
|
|
1.0 |
|
Total
|
|
$ |
22.5 |
|
|
$ |
14.9 |
|
|
$ |
18.3 |
|
|
$ |
48.1 |
|
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
Exit
from TOPS Partnership
In August
2008, a wholly owned subsidiary of ours, together with a subsidiary of TEPPCO
and Oiltanking Holding Americas, Inc. (“Oiltanking”), formed the TOPS
partnership. Effective April 16, 2009, our wholly owned subsidiary
dissociated from TOPS. As a result, equity earnings for the nine
months ended September 30, 2009 reflects a non-cash charge of $34.2
million. This loss, which is classified within our Offshore Pipelines
& Services business segment, represents our cumulative investment in TOPS
through the date of dissociation and reflects our capital contributions to TOPS
for construction in progress amounts. The wholly owned subsidiary of
TEPPCO that was a partner in TOPS also dissociated from the partnership
effective April 16, 2009 and recorded a $34.2 million non-cash
charge. See Note 14 for litigation matters associated with
TOPS.
Summarized
Financial Information of Unconsolidated Affiliates
The following tables present unaudited
income statement data for our current unconsolidated affiliates, aggregated by
business segment, for the periods indicated (on a 100% basis):
|
|
Summarized
Income Statement Information for the Three Months Ended
|
|
|
|
September
30, 2009
|
|
|
September
30, 2008
|
|
|
|
|
|
|
Operating
|
|
|
Net
|
|
|
|
|
|
Operating
|
|
|
Net
|
|
|
|
Revenues
|
|
|
Income
|
|
|
Income
|
|
|
Revenues
|
|
|
Income
|
|
|
Income
|
|
NGL
Pipelines & Services
|
|
$ |
60.0 |
|
|
$ |
10.9 |
|
|
$ |
11.2 |
|
|
$ |
75.1 |
|
|
$ |
9.7 |
|
|
$ |
6.7 |
|
Onshore
Natural Gas Pipelines & Services
|
|
|
108.6 |
|
|
|
34.2 |
|
|
|
34.3 |
|
|
|
188.9 |
|
|
|
29.0 |
|
|
|
27.9 |
|
Offshore
Pipelines & Services
|
|
|
43.2 |
|
|
|
24.7 |
|
|
|
24.0 |
|
|
|
31.9 |
|
|
|
12.9 |
|
|
|
12.0 |
|
Petrochemical
Services
|
|
|
5.1 |
|
|
|
2.0 |
|
|
|
2.0 |
|
|
|
5.6 |
|
|
|
1.1 |
|
|
|
1.1 |
|
|
|
Summarized
Income Statement Information for the Nine Months Ended
|
|
|
|
September
30, 2009
|
|
|
September
30, 2008
|
|
|
|
|
|
|
Operating
|
|
|
Net
|
|
|
|
|
|
Operating
|
|
|
Net
|
|
|
|
Revenues
|
|
|
Income
|
|
|
Income
|
|
|
Revenues
|
|
|
Income
|
|
|
Income
|
|
NGL
Pipelines & Services
|
|
$ |
161.7 |
|
|
$ |
23.7 |
|
|
$ |
24.2 |
|
|
$ |
217.8 |
|
|
$ |
17.7 |
|
|
$ |
15.0 |
|
Onshore
Natural Gas Pipelines & Services
|
|
|
311.8 |
|
|
|
100.7 |
|
|
|
100.8 |
|
|
|
492.5 |
|
|
|
88.7 |
|
|
|
85.3 |
|
Offshore
Pipelines & Services
|
|
|
106.4 |
|
|
|
39.2 |
|
|
|
37.7 |
|
|
|
115.0 |
|
|
|
62.4 |
|
|
|
57.2 |
|
Petrochemical
Services
|
|
|
14.9 |
|
|
|
5.1 |
|
|
|
5.1 |
|
|
|
16.6 |
|
|
|
3.9 |
|
|
|
3.9 |
|
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
Identifiable
Intangible Assets
The
following table summarizes our intangible assets by segment at the dates
indicated:
|
|
September
30, 2009
|
|
|
December
31, 2008
|
|
|
|
Gross
|
|
|
Accum.
|
|
|
Carrying
|
|
|
Gross
|
|
|
Accum.
|
|
|
Carrying
|
|
|
|
Value
|
|
|
Amort.
|
|
|
Value
|
|
|
Value
|
|
|
Amort.
|
|
|
Value
|
|
NGL
Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer
relationship intangibles
|
|
$ |
237.4 |
|
|
$ |
(82.2 |
) |
|
$ |
155.2 |
|
|
$ |
237.4 |
|
|
$ |
(68.7 |
) |
|
$ |
168.7 |
|
Contract-based
intangibles
|
|
|
299.9 |
|
|
|
(131.6 |
) |
|
|
168.3 |
|
|
|
299.7 |
|
|
|
(117.4 |
) |
|
|
182.3 |
|
Subtotal
|
|
|
537.3 |
|
|
|
(213.8 |
) |
|
|
323.5 |
|
|
|
537.1 |
|
|
|
(186.1 |
) |
|
|
351.0 |
|
Onshore
Natural Gas Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer
relationship intangibles
|
|
|
372.0 |
|
|
|
(119.1 |
) |
|
|
252.9 |
|
|
|
372.0 |
|
|
|
(103.2 |
) |
|
|
268.8 |
|
Contract-based
intangibles
|
|
|
101.3 |
|
|
|
(43.1 |
) |
|
|
58.2 |
|
|
|
101.3 |
|
|
|
(36.6 |
) |
|
|
64.7 |
|
Subtotal
|
|
|
473.3 |
|
|
|
(162.2 |
) |
|
|
311.1 |
|
|
|
473.3 |
|
|
|
(139.8 |
) |
|
|
333.5 |
|
Offshore
Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer
relationship intangibles
|
|
|
205.8 |
|
|
|
(101.8 |
) |
|
|
104.0 |
|
|
|
205.8 |
|
|
|
(90.7 |
) |
|
|
115.1 |
|
Contract-based
intangibles
|
|
|
1.2 |
|
|
|
(0.2 |
) |
|
|
1.0 |
|
|
|
1.2 |
|
|
|
(0.1 |
) |
|
|
1.1 |
|
Subtotal
|
|
|
207.0 |
|
|
|
(102.0 |
) |
|
|
105.0 |
|
|
|
207.0 |
|
|
|
(90.8 |
) |
|
|
116.2 |
|
Petrochemical
Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer
relationship intangibles
|
|
|
53.0 |
|
|
|
(11.6 |
) |
|
|
41.4 |
|
|
|
53.0 |
|
|
|
(10.5 |
) |
|
|
42.5 |
|
Contract-based
intangibles
|
|
|
14.9 |
|
|
|
(2.9 |
) |
|
|
12.0 |
|
|
|
14.9 |
|
|
|
(2.7 |
) |
|
|
12.2 |
|
Subtotal
|
|
|
67.9 |
|
|
|
(14.5 |
) |
|
|
53.4 |
|
|
|
67.9 |
|
|
|
(13.2 |
) |
|
|
54.7 |
|
Total
|
|
$ |
1,285.5 |
|
|
$ |
(492.5 |
) |
|
$ |
793.0 |
|
|
$ |
1,285.3 |
|
|
$ |
(429.9 |
) |
|
$ |
855.4 |
|
The
following table presents the amortization expense of our intangible assets by
business segment for the periods indicated:
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
NGL
Pipelines & Services
|
|
$ |
9.1 |
|
|
$ |
9.7 |
|
|
$ |
27.7 |
|
|
$ |
29.6 |
|
Onshore
Natural Gas Pipelines & Services
|
|
|
7.4 |
|
|
|
7.5 |
|
|
|
22.4 |
|
|
|
22.9 |
|
Offshore
Pipelines & Services
|
|
|
3.6 |
|
|
|
4.1 |
|
|
|
11.2 |
|
|
|
12.8 |
|
Petrochemical
Services
|
|
|
0.4 |
|
|
|
0.5 |
|
|
|
1.3 |
|
|
|
1.5 |
|
Total
|
|
$ |
20.5 |
|
|
$ |
21.8 |
|
|
$ |
62.6 |
|
|
$ |
66.8 |
|
Based on
information currently available, we estimate that amortization expense will
approximate $20.2 million for the fourth quarter of 2009, $77.8 million for
2010, $72.0 million for 2011, $62.3 million for 2012 and $56.4 million for
2013.
Goodwill
The
following table summarizes our goodwill amounts by business segment at the dates
indicated:
|
|
September
30,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
|
|
NGL
Pipelines & Services
|
|
$ |
269.0 |
|
|
$ |
269.0 |
|
Onshore
Natural Gas Pipelines & Services
|
|
|
282.1 |
|
|
|
282.1 |
|
Offshore
Pipelines & Services
|
|
|
82.1 |
|
|
|
82.1 |
|
Petrochemical
Services
|
|
|
73.7 |
|
|
|
73.7 |
|
Total
|
|
$ |
706.9 |
|
|
$ |
706.9 |
|
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
Our
consolidated debt obligations consisted of the following at the dates
indicated:
|
|
September
30,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
EPO
senior debt obligations:
|
|
|
|
|
|
|
Multi-Year
Revolving Credit Facility, variable rate, due November
2012
|
|
$ |
638.0 |
|
|
$ |
800.0 |
|
Pascagoula
MBFC Loan, 8.70% fixed-rate, due March 2010 (1)
|
|
|
54.0 |
|
|
|
54.0 |
|
Petal
GO Zone Bonds, variable rate, due August 2037
|
|
|
57.5 |
|
|
|
57.5 |
|
Yen
Term Loan, 4.93% fixed-rate, due March 2009 (2)
|
|
|
-- |
|
|
|
217.6 |
|
Senior
Notes B, 7.50% fixed-rate, due February 2011
|
|
|
450.0 |
|
|
|
450.0 |
|
Senior
Notes C, 6.375% fixed-rate, due February 2013
|
|
|
350.0 |
|
|
|
350.0 |
|
Senior
Notes D, 6.875% fixed-rate, due March 2033
|
|
|
500.0 |
|
|
|
500.0 |
|
Senior
Notes F, 4.625% fixed-rate, due October 2009 (1)
|
|
|
500.0 |
|
|
|
500.0 |
|
Senior
Notes G, 5.60% fixed-rate, due October 2014
|
|
|
650.0 |
|
|
|
650.0 |
|
Senior
Notes H, 6.65% fixed-rate, due October 2034
|
|
|
350.0 |
|
|
|
350.0 |
|
Senior
Notes I, 5.00% fixed-rate, due March 2015
|
|
|
250.0 |
|
|
|
250.0 |
|
Senior
Notes J, 5.75% fixed-rate, due March 2035
|
|
|
250.0 |
|
|
|
250.0 |
|
Senior
Notes K, 4.950% fixed-rate, due June 2010 (1)
|
|
|
500.0 |
|
|
|
500.0 |
|
Senior
Notes L, 6.30% fixed-rate, due September 2017
|
|
|
800.0 |
|
|
|
800.0 |
|
Senior
Notes M, 5.65% fixed-rate, due April 2013
|
|
|
400.0 |
|
|
|
400.0 |
|
Senior
Notes N, 6.50% fixed-rate, due January 2019
|
|
|
700.0 |
|
|
|
700.0 |
|
Senior
Notes O, 9.75% fixed-rate, due January 2014
|
|
|
500.0 |
|
|
|
500.0 |
|
Senior
Notes P, 4.60% fixed-rate, due August 2012
|
|
|
500.0 |
|
|
|
-- |
|
Duncan
Energy Partners’ debt obligations:
|
|
|
|
|
|
|
|
|
DEP
Revolving Credit Facility, variable rate, due February
2011
|
|
|
180.5 |
|
|
|
202.0 |
|
DEP
Term Loan, variable rate, due December 2011
|
|
|
282.3 |
|
|
|
282.3 |
|
Total
principal amount of senior debt obligations
|
|
|
7,912.3 |
|
|
|
7,813.4 |
|
EPO
Junior Subordinated Notes A, fixed/variable rate, due August
2066
|
|
|
550.0 |
|
|
|
550.0 |
|
EPO
Junior Subordinated Notes B, fixed/variable rate, due January
2068
|
|
|
682.7 |
|
|
|
682.7 |
|
Total
principal amount of senior and junior debt obligations
|
|
|
9,145.0 |
|
|
|
9,046.1 |
|
Other,
non-principal amounts:
|
|
|
|
|
|
|
|
|
Change
in fair value of debt-related derivative instruments
|
|
|
47.6 |
|
|
|
51.9 |
|
Unamortized
discounts, net of premiums
|
|
|
(7.3 |
) |
|
|
(7.3 |
) |
Unamortized
deferred net gains related to terminated interest rate
swaps
|
|
|
13.0 |
|
|
|
17.7 |
|
Total
other, non-principal amounts
|
|
|
53.3 |
|
|
|
62.3 |
|
Total
long-term debt
|
|
$ |
9,198.3 |
|
|
$ |
9,108.4 |
|
|
|
|
|
|
|
|
|
|
Letters
of credit outstanding
|
|
$ |
109.3 |
|
|
$ |
1.0 |
|
|
|
|
|
|
|
|
|
|
(1)
In
accordance with ASC 470, Debt, long-term and current maturities of debt
reflect the classification of such obligations at September 30, 2009 after
taking into consideration EPO’s (i) $1.1 billion issuance of Senior Notes
in October 2009 and (ii) ability to use available borrowing capacity under
its Multi-Year Revolving Credit Facility.
(2)
The
Yen Term Loan matured on March 30, 2009.
|
|
Parent-Subsidiary
Guarantor Relationships
Enterprise
Products Partners L.P. acts as guarantor of the consolidated debt obligations of
EPO with the exception of the DEP Revolving Credit Facility and the DEP Term
Loan. If EPO were to default on any of its guaranteed debt,
Enterprise Products Partners L.P. would be responsible for full repayment of
that obligation.
Letters
of Credit
At
September 30, 2009, EPO had outstanding a $50.0 million letter of credit
relating to its commodity derivative instruments and a $58.3 million letter of
credit related to its Petal GO Zone Bonds. These letter of credit
facilities do not reduce the amount available for borrowing under EPO’s credit
facilities. In addition, at September 30, 2009, Duncan Energy
Partners had an outstanding letter of credit in the amount of $1.0 million which
reduces the amount available for borrowing under its credit
facility.
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
EPO’s
Debt Obligations
Apart
from that discussed below, there have been no significant changes in the terms
of our debt obligations since those reported in our Recast Form
8-K.
$200.0
Million Term Loan. In April 2009,
EPO entered into a $200.0 Million Term Loan, which was subsequently repaid and
terminated in June 2009 using funds from the issuance of Senior Notes P (see
below).
Senior
Notes P. In June 2009,
EPO issued $500.0 million in principal amount of 3-year senior unsecured notes
(“Senior Notes P”). Senior Notes P were issued at 99.95% of their
principal amount, have a fixed interest rate of 4.60% and mature on August 1,
2012. Net proceeds from the issuance of Senior Notes P were used (i)
to repay amounts borrowed under the $200 Million Term Loan, (ii) to temporarily
reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility
and (iii) for general partnership purposes.
Senior
Notes P rank equal with EPO’s existing and future unsecured and unsubordinated
indebtedness. They are senior to any existing and future subordinated
indebtedness of EPO. Senior Notes P are subject to make-whole
redemption rights and were issued under indentures containing certain covenants,
which generally restrict EPO’s ability, with certain exceptions, to incur debt
secured by liens and engage in sale and leaseback transactions.
364-Day
Revolving Credit Facility. In November 2008, EPO executed
a standby 364-Day Revolving Credit Agreement (the “364-Day Facility”) that had a
borrowing capacity of $375.0 million. The 364-Day Facility was
terminated in June 2009 under its terms as a result of the issuance of Senior
Notes P. No amounts were borrowed under this standby facility through
its termination date.
Exchange
Offers for TEPPCO Notes. In September
2009, EPO commenced offers to exchange all outstanding notes issued by TEPPCO
for a corresponding series of new notes to be issued by EPO and guaranteed by
Enterprise Products Partners L.P. The aggregate principal amount of
the TEPPCO notes subject to the exchange was $2 billion. The exchange
offer was completed on October 27, 2009, resulting in the exchange of
approximately $1.95 billion of new EPO notes for existing TEPPCO
notes. See Note 18 for additional information regarding this exchange
offer.
Senior
Notes Q and R. In October 2009,
EPO issued $500.0 million in principal amount of 10-year senior unsecured notes
(“Senior Notes Q”) and $600.0 million in principal amount of 30-year senior
unsecured notes (“Senior Notes R”). EPO used a portion of the net
proceeds it received from the issuance of Senior Notes Q and R to repay its
$500.0 million in principal amount unsecured notes (“Senior Notes F”) that
matured in October 2009. See Note 18 for additional information
regarding these debt issuances.
Dixie
Revolving Credit Facility
The Dixie Revolving Credit Facility was
terminated in January 2009. As of December 31, 2008, there were no
debt obligations outstanding under this facility.
Covenants
We were
in compliance with the covenants of our consolidated debt agreements at
September 30, 2009.
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
Information
Regarding Variable Interest Rates Paid
The
following table shows the weighted-average interest rate paid on our
consolidated variable-rate debt obligations during the nine months ended
September 30, 2009.
|
Weighted-Average
|
|
Interest
Rate
|
|
Paid
|
EPO’s
Multi-Year Revolving Credit Facility
|
0.97%
|
DEP
Revolving Credit Facility
|
1.64%
|
DEP
Term Loan
|
1.20%
|
Petal
GO Zone Bonds
|
0.76%
|
Consolidated
Debt Maturity Table
The
following table presents the scheduled contractual maturities of principal
amounts of our debt obligations for the next five years and in total
thereafter.
2009
(1)
|
|
$ |
500.0 |
|
2010
(1)
|
|
|
554.0 |
|
2011
|
|
|
912.8 |
|
2012
|
|
|
1,138.0 |
|
2013
|
|
|
750.0 |
|
Thereafter
|
|
|
5,290.2 |
|
Total
scheduled principal payments
|
|
$ |
9,145.0 |
|
|
|
|
|
|
(1)
Long-term and current maturities of debt reflect the classification
of such obligations on our Unaudited Condensed Consolidated Balance Sheet
at September 30, 2009 after taking into consideration EPO’s (i) $1.1
billion issuance of Senior Notes in October 2009 and (ii) ability to use
available borrowing capacity under its Multi-Year Revolving Credit
Facility.
|
|
Debt
Obligations of Unconsolidated Affiliates
We have
two unconsolidated affiliates with long-term debt obligations. The
following table shows (i) our ownership interest in each entity at September 30,
2009, (ii) total debt of each unconsolidated affiliate at September 30, 2009 (on
a 100% basis to the affiliate) and (iii) the corresponding scheduled maturities
of such debt.
|
|
Our
|
|
|
|
|
|
Scheduled
Maturities of Debt
|
|
|
|
Ownership
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
|
Total
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
Poseidon
|
|
|
36% |
|
|
$ |
92.0 |
|
|
$ |
-- |
|
|
$ |
-- |
|
|
$ |
92.0 |
|
Evangeline
|
|
|
49.5% |
|
|
|
15.7 |
|
|
|
5.0 |
|
|
|
3.2 |
|
|
|
7.5 |
|
Total
|
|
|
|
|
|
$ |
107.7 |
|
|
$ |
5.0 |
|
|
$ |
3.2 |
|
|
$ |
99.5 |
|
The
credit agreements of our unconsolidated affiliates contain various affirmative
and negative covenants, including financial covenants. These
businesses were in compliance with such covenants at September 30,
2009. The credit agreements of our unconsolidated affiliates also
restrict their ability to pay cash dividends if a default or an event of default
(as defined in each credit agreement) has occurred and is continuing at the time
such dividend is scheduled to be paid.
There
have been no significant changes in the terms of the debt obligations of our
unconsolidated affiliates since those reported in our Recast Form
8-K.
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
Our
common units represent limited partner interests, which give the holders thereof
the right to participate in distributions and to exercise the other rights or
privileges available to them under our Fifth Amended and
Restated Agreement of Limited Partnership (together with all amendments thereto,
the “Partnership Agreement”). We are managed by our general partner,
EPGP.
Equity
Offerings and Registration Statements
We have a
universal shelf registration statement on file with the SEC that allows us to
issue an unlimited amount of debt and equity securities for general partnership
purposes. In January 2009, we issued 10,590,000 common units
(including an over-allotment of 990,000 common units) to the public at an
offering price of $22.20 per unit under this registration
statement. We used the net proceeds of $225.6 million from the
January 2009 equity offering to temporarily reduce borrowings outstanding under
EPO’s Multi-Year Revolving Credit Facility and for general partnership
purposes. In June 2009, EPO issued $500.0 million in principal amount
of Senior Notes P under this registration statement. Net proceeds
from this senior note offering were used to repay the $200.0 Million Term Loan,
to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving
Credit Facility and for general partnership purposes.
In
September 2009, we issued 8,337,500 common units (including an over-allotment of
1,087,500 common units) to the public at an offering price of $28.00 per unit
under this registration statement. We used the net proceeds of $226.4
million from the September 2009 equity offering to temporarily reduce borrowings
outstanding under EPO’s Multi-Year Revolving Credit Facility and for general
partnership purposes. In October 2009, EPO issued $1.1 billion in
principal amount of Senior Notes Q and R under this registration
statement. Net proceeds from this senior note offering were used to
repay $500.0 million in aggregate principal amount of Senior Notes F that
matured in October 2009, to temporarily reduce borrowings outstanding under
EPO’s Multi-Year Revolving Credit Facility and for general partnership
purposes.
We also
have a registration statement on file with the SEC authorizing the issuance of
up to 40,000,000 common units in connection with our distribution reinvestment
plan (“DRIP”). A total of 32,202,131 common units have been issued
under this registration statement through September 30, 2009.
In
addition, we have a registration statement on file related to our employee unit
purchase plan (“EUPP”), under which we can issue up to 1,200,000 common
units. A total of 792,809 common units have been issued to employees
under this plan through September 30, 2009.
On
September 4, 2009, we agreed to issue 5,940,594 common units in a private
placement to EPCO Holdings, Inc., a privately held affiliate controlled by Dan
L. Duncan, for $150.0 million, or $25.25 per unit. In accordance with
the terms of the private placement, as approved by the Audit, Conflicts and
Governance (“ACG”) Committee of EPGP’s Board of Directors on September 1, 2009,
the per unit purchase price of $25.25 was calculated based on a five percent
discount to the five-day volume weighted average price (“5-Day VWAP”) of our
common units, as reported by the NYSE at the close of business on September 4,
2009. The 5-Day VWAP was based on (i) the closing price for the
common units on the NYSE for each of the trading days in such five-day period
and (ii) the total trading volume for the common units reported by the NYSE for
each such trading day. The common units were issued on September 8,
2009.
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
The
following table reflects the number of common units issued and the net proceeds
received from underwritten and other common unit offerings completed during the
nine months ended September 30, 2009:
|
|
Net
Proceeds from Sale of Common Units
|
|
|
|
Number
of
|
|
|
Contributed
|
|
|
Contributed
by
|
|
|
Total
|
|
|
|
Common
Units
|
|
|
by
Limited
|
|
|
General
|
|
|
Net
|
|
|
|
Issued
|
|
|
Partners
|
|
|
Partner
|
|
|
Proceeds
|
|
January
underwritten offering
|
|
|
10,590,000 |
|
|
$ |
225.6 |
|
|
$ |
4.6 |
|
|
$ |
230.2 |
|
February
DRIP and EUPP
|
|
|
3,679,163 |
|
|
|
78.9 |
|
|
|
1.6 |
|
|
|
80.5 |
|
May
DRIP and EUPP
|
|
|
3,671,679 |
|
|
|
86.1 |
|
|
|
1.8 |
|
|
|
87.9 |
|
August
DRIP and EUPP
|
|
|
3,521,754 |
|
|
|
93.2 |
|
|
|
1.8 |
|
|
|
95.0 |
|
September
private placement
|
|
|
5,940,594 |
|
|
|
150.0 |
|
|
|
3.1 |
|
|
|
153.1 |
|
September
underwritten offering
|
|
|
8,337,500 |
|
|
|
226.4 |
|
|
|
4.6 |
|
|
|
231.0 |
|
Total
2009
|
|
|
35,740,690 |
|
|
$ |
860.2 |
|
|
$ |
17.5 |
|
|
$ |
877.7 |
|
Net
proceeds from the issuance of common units during 2009 have been used to
temporarily reduce borrowings under EPO’s Multi-Year Revolving Credit Facility
and for general partnership purposes.
Summary
of Changes in Outstanding Units
The
following table summarizes changes in our outstanding units since December 31,
2008:
|
|
|
|
|
Restricted
|
|
|
|
|
|
|
Common
|
|
|
Common
|
|
|
Treasury
|
|
|
|
Units
|
|
|
Units
|
|
|
Units
|
|
Balance,
December 31, 2008
|
|
|
439,354,731 |
|
|
|
2,080,600 |
|
|
|
-- |
|
Common
units issued in connection with underwritten offerings
|
|
|
18,927,500 |
|
|
|
-- |
|
|
|
-- |
|
Common
units issued in connection with private placement
|
|
|
5,940,594 |
|
|
|
-- |
|
|
|
-- |
|
Common
units issued in connection with DRIP and EUPP
|
|
|
10,872,596 |
|
|
|
-- |
|
|
|
-- |
|
Common
units issued in connection with equity awards
|
|
|
18,500 |
|
|
|
-- |
|
|
|
-- |
|
Restricted
units issued
|
|
|
-- |
|
|
|
1,016,950 |
|
|
|
-- |
|
Forfeiture
of restricted units
|
|
|
-- |
|
|
|
(194,400 |
) |
|
|
-- |
|
Conversion
of restricted units to common units
|
|
|
244,300 |
|
|
|
(244,300 |
) |
|
|
-- |
|
Acquisition
of treasury units
|
|
|
(64,223 |
) |
|
|
-- |
|
|
|
64,223 |
|
Cancellation
of treasury units
|
|
|
-- |
|
|
|
-- |
|
|
|
(64,223 |
) |
Balance,
September 30, 2009
|
|
|
475,293,998 |
|
|
|
2,658,850 |
|
|
|
-- |
|
Summary
of Changes in Limited Partners’ Equity
The
following table details the changes in limited partners’ equity since December
31, 2008:
|
|
|
|
|
Restricted
|
|
|
|
|
|
|
Common
|
|
|
Common
|
|
|
|
|
|
|
Units
|
|
|
Units
|
|
|
Total
|
|
Balance,
December 31, 2008
|
|
$ |
6,036.9 |
|
|
$ |
26.2 |
|
|
$ |
6,063.1 |
|
Net
income
|
|
|
501.9 |
|
|
|
2.7 |
|
|
|
504.6 |
|
Operating
leases paid by EPCO
|
|
|
0.5 |
|
|
|
-- |
|
|
|
0.5 |
|
Cash
distributions to partners
|
|
|
(731.5 |
) |
|
|
(3.7 |
) |
|
|
(735.2 |
) |
Unit
option reimbursements to EPCO
|
|
|
(0.5 |
) |
|
|
-- |
|
|
|
(0.5 |
) |
Net
proceeds from issuance of common units
|
|
|
860.2 |
|
|
|
-- |
|
|
|
860.2 |
|
Proceeds
from exercise of unit options
|
|
|
0.5 |
|
|
|
-- |
|
|
|
0.5 |
|
Acquisition
of treasury units
|
|
|
-- |
|
|
|
(1.8 |
) |
|
|
(1.8 |
) |
Amortization
of equity awards
|
|
|
2.8 |
|
|
|
10.7 |
|
|
|
13.5 |
|
Balance,
September 30, 2009
|
|
$ |
6,670.8 |
|
|
$ |
34.1 |
|
|
$ |
6,704.9 |
|
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
Distributions
to Partners
We paid
EPGP incentive distributions of $38.1 million and $32.0 million during the three
months ended September 30, 2009 and 2008, respectively. During the
nine months ended September 30, 2009 and 2008, we paid incentive distributions
of $109.9 million and $92.8 million, respectively, to EPGP.
We paid
aggregate distributions to our unitholders and our general partner of $860.1
million during the nine months ended September 30, 2009. These
distributions pertained to the nine month period ended June 30, 2009 (i.e., the
fourth quarter of 2008, and first and second quarters of 2009). On
November 5, 2009, we paid a quarterly cash distribution of $0.5525 per unit with
respect to the third quarter of 2009, to unitholders of record at the close of
business on October 30, 2009.
Accumulated
Other Comprehensive Loss
The
following table presents the components of AOCI at the dates
indicated:
|
|
September
30,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
Commodity
derivative instruments (1)
|
|
$ |
(84.7 |
) |
|
$ |
(114.1 |
) |
Interest
rate derivative instruments (1)
|
|
|
14.2 |
|
|
|
3.8 |
|
Foreign
currency derivative instruments (1) (2)
|
|
|
0.3 |
|
|
|
10.6 |
|
Foreign
currency translation adjustment (2)
|
|
|
0.4 |
|
|
|
(1.3 |
) |
Pension
and postretirement benefit plans
|
|
|
(0.7 |
) |
|
|
(0.7 |
) |
Subtotal
|
|
|
(70.5 |
) |
|
|
(101.7 |
) |
Amount
attributable to noncontrolling interest
|
|
|
3.4 |
|
|
|
4.5 |
|
Total
accumulated other comprehensive loss in partners’ equity
|
|
$ |
(67.1 |
) |
|
$ |
(97.2 |
) |
|
|
|
|
|
|
|
|
|
(1) See
Note 4 for additional information regarding these components of
accumulated other comprehensive loss.
(2) Relates
to transactions of our Canadian NGL marketing subsidiary.
|
|
Noncontrolling
Interest
The
following table presents the components of noncontrolling interest as presented
on our Unaudited Condensed Consolidated Balance Sheets at the dates
indicated:
|
|
September
30,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
Limited
partners of Duncan Energy Partners (1)
|
|
$ |
416.9 |
|
|
$ |
281.1 |
|
Joint
venture partners (2)
|
|
|
108.5 |
|
|
|
112.5 |
|
AOCI
attributable to noncontrolling interest
|
|
|
(3.4 |
) |
|
|
(4.5 |
) |
Total
noncontrolling interest on consolidated balance sheets
|
|
$ |
522.0 |
|
|
$ |
389.1 |
|
|
|
|
|
|
|
|
|
|
(1)
Consists
of non-affiliate public unitholders of Duncan Energy Partners. The
increase in noncontrolling interest between periods is attributable to
Duncan Energy Partners’ equity offering in June 2009 (see Note
12).
(2)
Represents
third-party ownership interests in joint ventures that we consolidate,
including Seminole Pipeline Company, Tri-States Pipeline L.L.C.,
Independence Hub LLC and Wilprise Pipeline Company LLC.
|
|
The
following table presents the components of net income attributable to
noncontrolling interest as presented on our Unaudited Condensed Statements of
Consolidated Operations for the periods indicated:
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Limited
partners of Duncan Energy Partners
|
|
$ |
10.1 |
|
|
$ |
2.7 |
|
|
$ |
21.8 |
|
|
$ |
11.8 |
|
Joint
venture partners
|
|
|
6.9 |
|
|
|
5.2 |
|
|
|
20.7 |
|
|
|
17.5 |
|
Total
|
|
$ |
17.0 |
|
|
$ |
7.9 |
|
|
$ |
42.5 |
|
|
$ |
29.3 |
|
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
The
following table presents cash distributions paid to, and cash contributions
from, noncontrolling interest as presented on our Unaudited Condensed Statements
of Consolidated Cash Flows and Unaudited Condensed Statements of Consolidated
Equity for the periods indicated:
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
Cash
distributions paid to noncontrolling interest:
|
|
|
|
|
|
|
Limited
partners of Duncan Energy Partners
|
|
$ |
23.2 |
|
|
$ |
18.5 |
|
Joint
venture partners
|
|
|
24.7 |
|
|
|
20.7 |
|
Total
cash distributions paid to noncontrolling interest
|
|
$ |
47.9 |
|
|
$ |
39.2 |
|
Cash
contributions from noncontrolling interest:
|
|
|
|
|
|
|
|
|
Limited
partners of Duncan Energy Partners
|
|
$ |
137.4 |
|
|
$ |
-- |
|
Duncan
Energy Partners issued an aggregate 8,943,400 of its common units in June and
July 2009, which generated net proceeds of approximately $137.4
million. Duncan Energy Partners used the net proceeds from its
issuance of these units to repurchase and cancel an equal number of its common
units beneficially owned by EPO.
We have
four reportable business segments: NGL Pipelines & Services, Onshore Natural
Gas Pipelines & Services, Offshore Pipelines & Services and
Petrochemical Services. Our business segments are generally organized
and managed according to the type of services rendered (or technologies
employed) and products produced and/or sold.
The
following table shows our measurement of total segment gross operating margin
for the periods indicated:
|
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Revenues
|
|
$ |
4,596.1 |
|
|
$ |
6,297.9 |
|
|
$ |
11,527.1 |
|
|
$ |
18,322.1 |
|
Less:
|
Operating
costs and expenses
|
|
|
(4,220.2 |
) |
|
|
(5,971.9 |
) |
|
|
(10,395.7 |
) |
|
|
(17,243.1 |
) |
Add:
|
Equity
in income of unconsolidated affiliates
|
|
|
22.5 |
|
|
|
14.9 |
|
|
|
18.3 |
|
|
|
48.1 |
|
|
Depreciation,
amortization and accretion in operating costs and expenses
|
|
|
160.6 |
|
|
|
138.4 |
|
|
|
467.3 |
|
|
|
408.6 |
|
|
Non-cash
impairment charge included in operating costs and expenses
|
|
|
1.7 |
|
|
|
-- |
|
|
|
1.7 |
|
|
|
-- |
|
|
Operating
lease expense paid by EPCO
|
|
|
0.2 |
|
|
|
0.5 |
|
|
|
0.5 |
|
|
|
1.5 |
|
|
Gain
from asset sales and related transactions in operating costs
and expenses
|
|
|
-- |
|
|
|
(0.9 |
) |
|
|
(0.4 |
) |
|
|
(1.7 |
) |
Total
segment gross operating margin
|
|
$ |
560.9 |
|
|
$ |
478.9 |
|
|
$ |
1,618.8 |
|
|
$ |
1,535.5 |
|
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
A
reconciliation of our total segment gross operating margin to operating income
and income before provision for income taxes follows:
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Total
segment gross operating margin
|
|
$ |
560.9 |
|
|
$ |
478.9 |
|
|
$ |
1,618.8 |
|
|
$ |
1,535.5 |
|
Adjustments
to reconcile total segment gross operating margin to
operating income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
amortization and accretion in operating costs and expenses
|
|
|
(160.6 |
) |
|
|
(138.4 |
) |
|
|
(467.3 |
) |
|
|
(408.6 |
) |
Non-cash
impairment charge included in operating costs and expenses
|
|
|
(1.7 |
) |
|
|
-- |
|
|
|
(1.7 |
) |
|
|
-- |
|
Operating
lease expense paid by EPCO
|
|
|
(0.2 |
) |
|
|
(0.5 |
) |
|
|
(0.5 |
) |
|
|
(1.5 |
) |
Gain
from asset sales and related transactions in operating costs
and expenses
|
|
|
-- |
|
|
|
0.9 |
|
|
|
0.4 |
|
|
|
1.7 |
|
General
and administrative costs
|
|
|
(33.9 |
) |
|
|
(21.8 |
) |
|
|
(84.7 |
) |
|
|
(67.0 |
) |
Operating
income
|
|
|
364.5 |
|
|
|
319.1 |
|
|
|
1,065.0 |
|
|
|
1,060.1 |
|
Other
expense, net
|
|
|
(128.0 |
) |
|
|
(101.5 |
) |
|
|
(373.7 |
) |
|
|
(287.6 |
) |
Income
before provision for income taxes
|
|
$ |
236.5 |
|
|
$ |
217.6 |
|
|
$ |
691.3 |
|
|
$ |
772.5 |
|
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
Information
by segment, together with reconciliations to our consolidated totals, is
presented in the following table:
|
|
Reportable
Segments
|
|
|
|
|
|
|
|
|
|
|
|
|
Onshore
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL
|
|
|
Natural
Gas
|
|
|
Offshore
|
|
|
|
|
|
Adjustments
|
|
|
|
|
|
|
Pipelines
|
|
|
Pipelines
|
|
|
Pipelines
|
|
|
Petrochemical
|
|
|
and
|
|
|
Consolidated
|
|
|
|
&
Services
|
|
|
&
Services
|
|
|
&
Services
|
|
|
Services
|
|
|
Eliminations
|
|
|
Totals
|
|
Revenues
from third parties:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
months ended September 30, 2009
|
|
$ |
3,127.7 |
|
|
$ |
638.8 |
|
|
$ |
98.7 |
|
|
$ |
579.5 |
|
|
$ |
-- |
|
|
$ |
4,444.7 |
|
Three
months ended September 30, 2008
|
|
|
4,288.2 |
|
|
|
823.2 |
|
|
|
60.2 |
|
|
|
826.1 |
|
|
|
-- |
|
|
|
5,997.7 |
|
Nine
months ended September 30, 2009
|
|
|
7,728.9 |
|
|
|
1,798.8 |
|
|
|
243.7 |
|
|
|
1,234.7 |
|
|
|
-- |
|
|
|
11,006.1 |
|
Nine
months ended September 30, 2008
|
|
|
12,544.2 |
|
|
|
2,456.3 |
|
|
|
197.3 |
|
|
|
2,300.6 |
|
|
|
-- |
|
|
|
17,498.4 |
|
Revenues
from related parties:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
months ended September 30, 2009
|
|
|
88.2 |
|
|
|
60.2 |
|
|
|
3.0 |
|
|
|
-- |
|
|
|
-- |
|
|
|
151.4 |
|
Three
months ended September 30, 2008
|
|
|
140.8 |
|
|
|
154.7 |
|
|
|
4.7 |
|
|
|
-- |
|
|
|
-- |
|
|
|
300.2 |
|
Nine
months ended September 30, 2009
|
|
|
344.1 |
|
|
|
173.1 |
|
|
|
3.8 |
|
|
|
-- |
|
|
|
-- |
|
|
|
521.0 |
|
Nine
months ended September 30, 2008
|
|
|
501.2 |
|
|
|
314.7 |
|
|
|
7.8 |
|
|
|
-- |
|
|
|
-- |
|
|
|
823.7 |
|
Intersegment
and intrasegment revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
months ended September 30, 2009
|
|
|
1,592.3 |
|
|
|
121.9 |
|
|
|
0.4 |
|
|
|
135.1 |
|
|
|
(1,849.7 |
) |
|
|
-- |
|
Three
months ended September 30, 2008
|
|
|
2,313.7 |
|
|
|
293.2 |
|
|
|
0.3 |
|
|
|
216.6 |
|
|
|
(2,823.8 |
) |
|
|
-- |
|
Nine
months ended September 30, 2009
|
|
|
4,416.9 |
|
|
|
379.9 |
|
|
|
1.0 |
|
|
|
342.7 |
|
|
|
(5,140.5 |
) |
|
|
-- |
|
Nine
months ended September 30, 2008
|
|
|
6,431.5 |
|
|
|
636.0 |
|
|
|
1.1 |
|
|
|
529.8 |
|
|
|
(7,598.4 |
) |
|
|
-- |
|
Total
revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
months ended September 30, 2009
|
|
|
4,808.2 |
|
|
|
820.9 |
|
|
|
102.1 |
|
|
|
714.6 |
|
|
|
(1,849.7 |
) |
|
|
4,596.1 |
|
Three
months ended September 30, 2008
|
|
|
6,742.7 |
|
|
|
1,271.1 |
|
|
|
65.2 |
|
|
|
1,042.7 |
|
|
|
(2,823.8 |
) |
|
|
6,297.9 |
|
Nine
months ended September 30, 2009
|
|
|
12,489.9 |
|
|
|
2,351.8 |
|
|
|
248.5 |
|
|
|
1,577.4 |
|
|
|
(5,140.5 |
) |
|
|
11,527.1 |
|
Nine
months ended September 30, 2008
|
|
|
19,476.9 |
|
|
|
3,407.0 |
|
|
|
206.2 |
|
|
|
2,830.4 |
|
|
|
(7,598.4 |
) |
|
|
18,322.1 |
|
Equity
in income (loss) of unconsolidated
affiliates:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
months ended September 30, 2009
|
|
|
4.0 |
|
|
|
7.4 |
|
|
|
10.6 |
|
|
|
0.5 |
|
|
|
-- |
|
|
|
22.5 |
|
Three
months ended September 30, 2008
|
|
|
3.0 |
|
|
|
5.6 |
|
|
|
6.0 |
|
|
|
0.3 |
|
|
|
-- |
|
|
|
14.9 |
|
Nine
months ended September 30, 2009
|
|
|
7.5 |
|
|
|
21.7 |
|
|
|
(12.1 |
) |
|
|
1.2 |
|
|
|
-- |
|
|
|
18.3 |
|
Nine
months ended September 30, 2008
|
|
|
2.3 |
|
|
|
16.9 |
|
|
|
27.9 |
|
|
|
1.0 |
|
|
|
-- |
|
|
|
48.1 |
|
Gross
operating margin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
months ended September 30, 2009
|
|
|
392.0 |
|
|
|
62.3 |
|
|
|
56.3 |
|
|
|
50.3 |
|
|
|
-- |
|
|
|
560.9 |
|
Three
months ended September 30, 2008
|
|
|
336.1 |
|
|
|
88.1 |
|
|
|
17.5 |
|
|
|
37.2 |
|
|
|
-- |
|
|
|
478.9 |
|
Nine
months ended September 30, 2009
|
|
|
1,088.8 |
|
|
|
252.6 |
|
|
|
150.7 |
|
|
|
126.7 |
|
|
|
-- |
|
|
|
1,618.8 |
|
Nine
months ended September 30, 2008
|
|
|
943.5 |
|
|
|
321.2 |
|
|
|
134.4 |
|
|
|
136.4 |
|
|
|
-- |
|
|
|
1,535.5 |
|
Segment
assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At
September 30, 2009
|
|
|
6,083.4 |
|
|
|
4,570.4 |
|
|
|
1,488.4 |
|
|
|
716.6 |
|
|
|
802.8 |
|
|
|
13,661.6 |
|
At
December 31, 2008
|
|
|
5,424.1 |
|
|
|
4,033.3 |
|
|
|
1,394.5 |
|
|
|
698.2 |
|
|
|
1,604.7 |
|
|
|
13,154.8 |
|
Investments
in unconsolidated affiliates: (see Note
7)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At
September 30, 2009
|
|
|
141.9 |
|
|
|
282.5 |
|
|
|
461.7 |
|
|
|
14.9 |
|
|
|
-- |
|
|
|
901.0 |
|
At
December 31, 2008
|
|
|
144.2 |
|
|
|
284.0 |
|
|
|
504.8 |
|
|
|
16.5 |
|
|
|
-- |
|
|
|
949.5 |
|
Intangible assets, net:
(see Note 8)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At
September 30, 2009
|
|
|
323.5 |
|
|
|
311.1 |
|
|
|
105.0 |
|
|
|
53.4 |
|
|
|
-- |
|
|
|
793.0 |
|
At
December 31, 2008
|
|
|
351.0 |
|
|
|
333.5 |
|
|
|
116.2 |
|
|
|
54.7 |
|
|
|
-- |
|
|
|
855.4 |
|
Goodwill: (see Note
8)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At
September 30, 2009
|
|
|
269.0 |
|
|
|
282.1 |
|
|
|
82.1 |
|
|
|
73.7 |
|
|
|
-- |
|
|
|
706.9 |
|
At
December 31, 2008
|
|
|
269.0 |
|
|
|
282.1 |
|
|
|
82.1 |
|
|
|
73.7 |
|
|
|
-- |
|
|
|
706.9 |
|
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
The
following table provides additional information regarding our consolidated
revenues (net of adjustments and eliminations) and expenses for the periods
indicated:
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
NGL
Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
of NGLs
|
|
$ |
3,054.9 |
|
|
$ |
4,257.8 |
|
|
$ |
7,623.0 |
|
|
$ |
12,514.6 |
|
Sales
of other petroleum and related products
|
|
|
0.6 |
|
|
|
0.5 |
|
|
|
1.5 |
|
|
|
1.9 |
|
Midstream
services
|
|
|
160.4 |
|
|
|
170.7 |
|
|
|
448.5 |
|
|
|
528.9 |
|
Total
|
|
|
3,215.9 |
|
|
|
4,429.0 |
|
|
|
8,073.0 |
|
|
|
13,045.4 |
|
Onshore
Natural Gas Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
of natural gas
|
|
|
585.7 |
|
|
|
859.2 |
|
|
|
1,645.3 |
|
|
|
2,400.4 |
|
Midstream
services
|
|
|
113.3 |
|
|
|
118.6 |
|
|
|
326.6 |
|
|
|
370.5 |
|
Total
|
|
|
699.0 |
|
|
|
977.8 |
|
|
|
1,971.9 |
|
|
|
2,770.9 |
|
Offshore
Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
of natural gas
|
|
|
0.3 |
|
|
|
0.9 |
|
|
|
0.9 |
|
|
|
2.5 |
|
Sales
of other petroleum and related products
|
|
|
2.0 |
|
|
|
3.7 |
|
|
|
3.1 |
|
|
|
10.8 |
|
Midstream
services
|
|
|
99.4 |
|
|
|
60.4 |
|
|
|
243.5 |
|
|
|
191.9 |
|
Total
|
|
|
101.7 |
|
|
|
65.0 |
|
|
|
247.5 |
|
|
|
205.2 |
|
Petrochemical
Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
of other petroleum and related products
|
|
|
558.8 |
|
|
|
803.4 |
|
|
|
1,165.3 |
|
|
|
2,233.7 |
|
Midstream
services
|
|
|
20.7 |
|
|
|
22.7 |
|
|
|
69.4 |
|
|
|
66.9 |
|
Total
|
|
|
579.5 |
|
|
|
826.1 |
|
|
|
1,234.7 |
|
|
|
2,300.6 |
|
Total
consolidated revenues
|
|
$ |
4,596.1 |
|
|
$ |
6,297.9 |
|
|
$ |
11,527.1 |
|
|
$ |
18,322.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated
cost and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost
of sales for our marketing activities
|
|
$ |
3,078.1 |
|
|
$ |
4,537.1 |
|
|
$ |
7,462.8 |
|
|
$ |
13,244.7 |
|
Depreciation,
amortization and accretion
|
|
|
160.6 |
|
|
|
138.4 |
|
|
|
467.3 |
|
|
|
408.6 |
|
Gain
on sale of assets and related transactions
|
|
|
-- |
|
|
|
(0.9 |
) |
|
|
(0.4 |
) |
|
|
(1.7 |
) |
Non-cash
impairment charge
|
|
|
1.7 |
|
|
|
-- |
|
|
|
1.7 |
|
|
|
-- |
|
Other
operating costs and expenses
|
|
|
979.8 |
|
|
|
1,297.3 |
|
|
|
2,464.3 |
|
|
|
3,591.5 |
|
General
and administrative costs
|
|
|
33.9 |
|
|
|
21.8 |
|
|
|
84.7 |
|
|
|
67.0 |
|
Total
consolidated costs and expenses
|
|
$ |
4,254.1 |
|
|
$ |
5,993.7 |
|
|
$ |
10,480.4 |
|
|
$ |
17,310.1 |
|
Changes in our revenues and operating
costs and expenses period-to-period are explained in part by changes in energy
commodity prices. In general, lower energy commodity prices result in
a decrease in our revenues attributable to the sale of natural gas and NGLs;
however, these lower commodity prices also decrease the associated cost of sales
as purchase prices decline.
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
The
following table summarizes our related party transactions for the periods
indicated:
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Revenues
from consolidated operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
EPCO
and affiliates
|
|
$ |
41.1 |
|
|
$ |
47.2 |
|
|
$ |
98.9 |
|
|
$ |
91.9 |
|
Energy
Transfer Equity and subsidiaries
|
|
|
54.5 |
|
|
|
99.6 |
|
|
|
266.5 |
|
|
|
413.0 |
|
Unconsolidated
affiliates
|
|
|
55.8 |
|
|
|
153.4 |
|
|
|
155.6 |
|
|
|
318.8 |
|
Total
|
|
$ |
151.4 |
|
|
$ |
300.2 |
|
|
$ |
521.0 |
|
|
$ |
823.7 |
|
Cost
of sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EPCO
and affiliates
|
|
$ |
32.1 |
|
|
$ |
10.9 |
|
|
$ |
75.7 |
|
|
$ |
36.5 |
|
Energy
Transfer Equity and subsidiaries
|
|
|
100.6 |
|
|
|
50.6 |
|
|
|
286.5 |
|
|
|
119.4 |
|
Unconsolidated
affiliates
|
|
|
13.0 |
|
|
|
23.7 |
|
|
|
37.5 |
|
|
|
75.9 |
|
Total
|
|
$ |
145.7 |
|
|
$ |
85.2 |
|
|
$ |
399.7 |
|
|
$ |
231.8 |
|
Operating
costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EPCO
and affiliates
|
|
$ |
91.8 |
|
|
$ |
77.1 |
|
|
$ |
258.3 |
|
|
$ |
238.0 |
|
Energy
Transfer Equity and subsidiaries
|
|
|
2.0 |
|
|
|
5.9 |
|
|
|
5.3 |
|
|
|
15.0 |
|
Unconsolidated
affiliates
|
|
|
(2.5 |
) |
|
|
(3.0 |
) |
|
|
(7.7 |
) |
|
|
(7.7 |
) |
Total
|
|
$ |
91.3 |
|
|
$ |
80.0 |
|
|
$ |
255.9 |
|
|
$ |
245.3 |
|
General
and administrative expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EPCO
and affiliates
|
|
$ |
16.8 |
|
|
$ |
13.4 |
|
|
$ |
51.2 |
|
|
$ |
44.6 |
|
Other
expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EPCO
and affiliates
|
|
$ |
0.1 |
|
|
$ |
-- |
|
|
$ |
0.1 |
|
|
$ |
(0.3 |
) |
The
following table summarizes our related party receivable and payable amounts at
the dates indicated:
|
|
September
30,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
Accounts
receivable - related parties:
|
|
|
|
|
|
|
EPCO
and affiliates
|
|
$ |
27.9 |
|
|
$ |
26.6 |
|
Energy
Transfer Equity and subsidiaries
|
|
|
6.4 |
|
|
|
35.0 |
|
Unconsolidated
affiliates
|
|
|
3.6 |
|
|
|
-- |
|
Total
|
|
$ |
37.9 |
|
|
$ |
61.6 |
|
|
|
|
|
|
|
|
|
|
Accounts
payable - related parties:
|
|
|
|
|
|
|
|
|
EPCO
and affiliates
|
|
$ |
16.9 |
|
|
$ |
39.4 |
|
Energy
Transfer Equity and subsidiaries
|
|
|
27.2 |
|
|
|
0.2 |
|
Unconsolidated
affiliates
|
|
|
3.1 |
|
|
|
-- |
|
Total
|
|
$ |
47.2 |
|
|
$ |
39.6 |
|
We believe that the terms and
provisions of our related party agreements are fair to us; however, such
agreements and transactions may not be as favorable to us as we could have
obtained from unaffiliated third parties.
Significant
Relationships and Agreements with EPCO and affiliates
We have an extensive and ongoing
relationship with EPCO and its affiliates, which include the following
significant entities that are not a part of our consolidated group of
companies:
§
|
EPCO
and its privately held affiliates;
|
§
|
EPGP,
our general partner;
|
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
§
|
Enterprise
GP Holdings, which owns and controls our general
partner;
|
§
|
TEPPCO
and its general partner, which are our wholly owned subsidiaries;
and
|
§
|
the
Employee Partnerships.
|
We also
have an ongoing relationship with Duncan Energy Partners, the financial
statements of which are consolidated with our own financial
statements. Our transactions with Duncan Energy Partners are
eliminated in consolidation. A description of our relationship with
Duncan Energy Partners is presented within this Note 12.
EPCO is a
privately held company controlled by Dan L. Duncan, who is also a director and
Chairman of EPGP, our general partner. At September 30, 2009, EPCO
and its affiliates beneficially owned 168,005,206 (or 35.2%) of our outstanding
common units, which includes 13,952,402 of our common units owned by Enterprise
GP Holdings. In addition, at September 30, 2009, EPCO and its
affiliates beneficially owned 77.8% of the limited partner interests of
Enterprise GP Holdings and 100% of its general partner, EPE
Holdings. Enterprise GP Holdings owns all of the membership interests
of EPGP. The principal business activity of EPGP is to act as our
managing partner. The executive officers and certain of the directors
of EPGP and EPE Holdings are employees of EPCO.
As our
general partner, EPGP received cash distributions of $124.9 million and $106.4
million from us during the nine months ended September 30, 2009 and 2008,
respectively. These amounts include incentive distributions of $109.9
million and $92.8 million for the nine months ended September 30, 2009 and 2008,
respectively.
See Note
10 for information regarding the private placement of 5,940,594 common units
with a privately held affiliate of EPCO in September
2009.
We and
EPGP are both separate legal entities apart from each other and apart from EPCO,
Enterprise GP Holdings and their respective other affiliates, with assets and
liabilities that are separate from those of EPCO, Enterprise GP Holdings and
their respective other affiliates. EPCO and its privately held
subsidiaries depend on the cash distributions they receive from us, Enterprise
GP Holdings and other investments to fund their other operations and to meet
their debt obligations. EPCO and its privately held affiliates
received from us and Enterprise GP Holdings $354.9 million and $300.2 million in
cash distributions during the nine months ended September 30, 2009 and 2008,
respectively.
EPCO
ASA. We have no
employees. Substantially all of our operating functions and general
and administrative support services are provided by employees of EPCO pursuant
to the ASA. We, Duncan Energy Partners, Enterprise GP Holdings,
TEPPCO and our respective general partners are among the parties to the
ASA. Our operating costs and expenses include reimbursement payments
to EPCO for the costs it incurs to operate our facilities, including
compensation of EPCO’s employees to the extent that such employees spend time on
our businesses. We reimbursed EPCO $94.1 million for operating costs
and expenses and $16.8 million for general and administrative costs for the
three months ended September 30, 2009. For the nine months ended
September 30, 2009, we reimbursed EPCO $267.9 million for operating costs and
expenses and $51.2 million for general and administrative costs.
Relationship
with TEPPCO
TEPPCO
became a related party to us in February 2005 when its general partner was
acquired by privately held affiliates of EPCO. Our relationship was
further reinforced by the acquisition of TEPPCO’s general partner by Enterprise
GP Holdings in May 2007. Enterprise GP Holdings also owns our general
partner. On October 26, 2009, we completed the TEPPCO Merger
and TEPPCO and TEPPCO GP became our wholly owned subsidiaries. See
Note 18 for additional information regarding the TEPPCO Merger.
We
received $41.1 million and $47.2 million from TEPPCO for the three months ended
September 30, 2009 and 2008, respectively, from the sale of hydrocarbon
products. For the nine months
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
ended
September 30, 2009 and 2008, we received $98.9 million and $91.9 million from
TEPPCO, respectively, from the sale of hydrocarbon products. We paid
TEPPCO $29.6 million and $6.2 million for NGL pipeline transportation and
storage services during the three months ended September 30, 2009 and
2008,
respectively. During the nine months ended September 30, 2009 and
2008, we paid TEPPCO $65.6 million and $22.1 million, respectively, for NGL
pipeline transportation and storage services.
In August 2006, we became joint venture
partners with TEPPCO in Jonah. We own an approximate 19.4% interest
in Jonah and TEPPCO owns the remaining 80.6% interest. Our investment
in Jonah at September 30, 2009 was $250.1 million.
In August 2008, we, together with
TEPPCO and Oiltanking, announced the formation of TOPS. On April 16,
2009, we, along with TEPPCO, dissociated ourselves from TOPS (see Notes 7 and
14).
In August
2009, EPO entered into a Loan Agreement (the “Loan Agreement”) with TEPPCO under
which EPO agreed to make an unsecured revolving loan to TEPPCO in an aggregate
maximum outstanding principal amount not to exceed $100.0
million. This agreement terminated on October 26, 2009 with the
closing of the TEPPCO Merger (see Note 18). TEPPCO did not execute
any borrowings under this facility.
Relationship
with Energy Transfer Equity
In May
2007, Enterprise GP Holdings acquired equity method investments in Energy
Transfer Equity and its general partner. As a result of common
control of us and Enterprise GP Holdings, Energy Transfer Equity and its
consolidated subsidiaries are related parties to our consolidated
businesses.
We
recorded $54.5 million and $99.6 million, respectively, of revenues from Energy
Transfer Partners, L.P. (“ETP”), primarily from NGL marketing activities for the
three months ended September 30, 2009 and 2008. For the nine months
ended September 30, 2009 and 2008, we recorded $266.5 million and $413.0
million, respectively, of revenues from ETP, primarily from NGL marketing
activities. We incurred $102.6 million and $56.5 million for the
three months ended September 30, 2009 and 2008, respectively, in costs of sales
and operating costs and expenses. For the nine months ended September
30, 2009 and 2008, we incurred $291.8 million and $134.4 million, respectively,
in costs of sales and operating costs and expenses. We have a
long-term revenue generating contract with Titan Energy Partners, L.P.
(“Titan”), a consolidated subsidiary of ETP. Titan purchases
substantially all of its propane requirements from us. The contract
continues until March 31, 2010 and contains renewal and extension
options. We and Energy Transfer Company (“ETC OLP”) transport natural
gas on each other’s systems and share operating expenses on certain
pipelines. ETC OLP also sells natural gas to us.
Relationship
with Duncan Energy Partners
Duncan
Energy Partners was formed in September 2006 and did not acquire any assets
prior to February 5, 2007, which was the date it completed its initial public
offering and acquired controlling interests in five midstream energy businesses
from EPO in a dropdown transaction (the “DEP I Midstream
Businesses”). On December 8, 2008, through a second dropdown
transaction, Duncan Energy Partners acquired controlling interests in three
additional midstream energy businesses from EPO (the “DEP II Midstream
Businesses”). The business purpose of Duncan Energy Partners is to
acquire, own and operate a diversified portfolio of midstream energy assets and
to support the growth objectives of EPO and other affiliates under common
control. Duncan Energy Partners is engaged in the business of
transporting and storing NGLs and petrochemical products and gathering,
transporting, storing and marketing of natural gas.
At September 30, 2009, Duncan Energy
Partners was owned 99.3% by its limited partners and 0.7% by its general
partner, DEP GP, which is a wholly owned subsidiary of EPO. DEP GP is
responsible for managing the business and operations of Duncan Energy
Partners. DEP Operating Partnership, L.P., a wholly owned subsidiary
of Duncan Energy Partners, conducts substantially all of Duncan Energy Partners’
business. At September 30, 2009, EPO beneficially owned approximately
58% of Duncan Energy Partners’ limited partner interests and 100% of its general
partner.
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
Enterprise Products Partners has
continued involvement with all of the subsidiaries of Duncan Energy Partners,
including the following types of transactions: (i) it utilizes Duncan
Energy Partners’ storage
services to support its Mont Belvieu fractionation and other businesses; (ii) it
buys from, and sells to, Duncan Energy Partners natural gas in connection with
its normal business activities; and (iii) it is currently the sole shipper on an
NGL pipeline system located in South Texas that is owned by Duncan Energy
Partners.
Duncan Energy Partners issued an
aggregate 8,943,400 of its common units in June and July 2009, which generated
net proceeds of approximately $137.4 million. Duncan Energy Partners
used the net proceeds from its issuance of these units to repurchase and cancel
an equal number of its common units beneficially owned by EPO. The
repurchase of Duncan Energy Partners’ common units beneficially owned by EPO was
reviewed and approved by the ACG Committees of EPGP and DEP GP.
Omnibus
Agreement. Under the
Omnibus Agreement, EPO agreed to make additional contributions to Duncan Energy
Partners as reimbursement for Duncan Energy Partners’ 66% share of any excess
construction costs above the (i) $28.6 million of estimated capital expenditures
to complete Phase II expansions of the DEP South Texas NGL Pipeline System and
(ii) $14.1 million of estimated construction costs for additional brine
production capacity and above-ground storage reservoir projects at Mont Belvieu,
Texas. Both projects were underway at the time of Duncan Energy
Partners’ initial public offering. EPO made cash contributions to
Duncan Energy Partners of $1.4 million and $32.5 million in connection with the
Omnibus Agreement during the nine months ended September 30, 2009 and 2008,
respectively. The majority of these contributions related to funding
the Phase II expansion costs of the DEP South Texas NGL Pipeline
System. EPO will not receive an increased allocation of earnings or
cash flows as a result of these contributions to South Texas NGL and Mont
Belvieu Caverns.
Mont
Belvieu Caverns’ LLC Agreement. EPO made cash
contributions of $14.1 million and $86.4 million under the Mont Belvieu Caverns
limited liability company agreement during the nine months ended September 30,
2009 and 2008, respectively, to fund 100% of certain storage-related projects
for the benefit of EPO’s NGL marketing activities. At present, Mont
Belvieu Caverns is not expected to generate any identifiable incremental cash
flows in connection with these projects; thus, the sharing ratio for Mont
Belvieu Caverns is not expected to change from the current sharing ratio of 66%
for Duncan Energy Partners and 34% for EPO. EPO expects to make
additional contributions of approximately $9.1 million to fund such projects
during the fourth quarter of 2009. The constructed assets will be the
property of Mont Belvieu Caverns.
Company
and Limited Partnership Agreements – DEP II Midstream Businesses. Enterprise
Holdings III, LLC (“Enterprise III”) has not yet participated in expansion
project spending with respect to the DEP II Midstream Businesses, although it
may elect to invest in existing or future expansion projects at a later
date. As a result, Enterprise GTM Holdings L.P. has funded 100% of
such growth capital spending and its Distribution Base has increased from $473.4
million at December 31, 2008 to $745.7 million at September 30,
2009. The Enterprise III Distribution Base was unchanged at $730.0
million at September 30, 2009.
Relationships
with Unconsolidated Affiliates
Our
significant related party revenue and expense transactions with unconsolidated
affiliates consist of the sale of natural gas to Evangeline and
Promix. In addition, we purchase NGL storage, transportation and
fractionation services from Promix and natural gas from Jonah. For
additional information regarding our unconsolidated affiliates, see Note
7.
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
The following table presents the net
income available to EPGP for the periods indicated:
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income attributable to Enterprise Products Partners L.P.
|
|
$ |
212.9 |
|
|
$ |
203.1 |
|
|
$ |
624.8 |
|
|
$ |
726.0 |
|
Less
incentive earnings allocations to EPGP
|
|
|
(38.1 |
) |
|
|
(32.0 |
) |
|
|
(109.9 |
) |
|
|
(92.8 |
) |
Net
income available after incentive earnings allocation
|
|
|
174.8 |
|
|
|
171.1 |
|
|
|
514.9 |
|
|
|
633.2 |
|
Multiplied
by EPGP ownership interest
|
|
|
2.0 |
% |
|
|
2.0 |
% |
|
|
2.0 |
% |
|
|
2.0 |
% |
Standard
earnings allocation to EPGP
|
|
$ |
3.5 |
|
|
$ |
3.4 |
|
|
$ |
10.3 |
|
|
$ |
12.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incentive
earnings allocation to EPGP
|
|
$ |
38.1 |
|
|
$ |
32.0 |
|
|
$ |
109.9 |
|
|
$ |
92.8 |
|
Standard
earnings allocation to EPGP
|
|
|
3.5 |
|
|
|
3.4 |
|
|
|
10.3 |
|
|
|
12.7 |
|
Net
income available to EPGP
|
|
|
41.6 |
|
|
|
35.4 |
|
|
|
120.2 |
|
|
|
105.5 |
|
Adjustment
for ASC 260 (1)
|
|
|
2.5 |
|
|
|
1.1 |
|
|
|
5.3 |
|
|
|
3.2 |
|
Net
income available to EPGP for EPU purposes
|
|
$ |
44.1 |
|
|
$ |
36.5 |
|
|
$ |
125.5 |
|
|
$ |
108.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) For
purposes of computing basic and diluted earnings per unit ("EPU"), the
master limited partnerships subsections of ASC 260 have been
applied.
|
|
The
following table presents our calculation of basic and diluted earnings per unit
for the periods indicated:
|
|
For
the Three Month
|
|
|
For
the Nine Month
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
BASIC
EARNINGS PER UNIT
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income attributable to Enterprise Products Partners L.P.
|
|
$ |
212.9 |
|
|
$ |
203.1 |
|
|
$ |
624.8 |
|
|
$ |
726.0 |
|
Net
income available to EPGP for EPU purposes
|
|
|
(44.1 |
) |
|
|
(36.5 |
) |
|
|
(125.5 |
) |
|
|
(108.7 |
) |
Net
income available to limited partners
|
|
$ |
168.8 |
|
|
$ |
166.6 |
|
|
$ |
499.3 |
|
|
$ |
617.3 |
|
Denominator
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
– average common units
|
|
|
461.5 |
|
|
|
435.3 |
|
|
|
456.0 |
|
|
|
434.6 |
|
Weighted
– average time-vested restricted units
|
|
|
2.8 |
|
|
|
2.3 |
|
|
|
2.4 |
|
|
|
2.0 |
|
Total
|
|
|
464.3 |
|
|
|
437.6 |
|
|
|
458.4 |
|
|
|
436.6 |
|
Basic
earnings per unit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income per unit before EPGP earnings allocation
|
|
$ |
0.45 |
|
|
$ |
0.46 |
|
|
$ |
1.36 |
|
|
$ |
1.66 |
|
Net
income available to EPGP
|
|
|
(0.09 |
) |
|
|
(0.08 |
) |
|
|
(0.27 |
) |
|
|
(0.25 |
) |
Net
income available to limited partners
|
|
$ |
0.36 |
|
|
$ |
0.38 |
|
|
$ |
1.09 |
|
|
$ |
1.41 |
|
DILUTED
EARNINGS PER UNIT
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income attributable to Enterprise Products Partners L.P.
|
|
$ |
212.9 |
|
|
$ |
203.1 |
|
|
$ |
624.8 |
|
|
$ |
726.0 |
|
Net
income available to EPGP for EPU purposes
|
|
|
(44.1 |
) |
|
|
(36.5 |
) |
|
|
(125.5 |
) |
|
|
(108.7 |
) |
Net
income available to limited partners
|
|
$ |
168.8 |
|
|
$ |
166.6 |
|
|
$ |
499.3 |
|
|
$ |
617.3 |
|
Denominator
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
– average common units
|
|
|
461.5 |
|
|
|
435.3 |
|
|
|
456.0 |
|
|
|
434.6 |
|
Weighted
– average time-vested restricted units
|
|
|
2.8 |
|
|
|
2.3 |
|
|
|
2.4 |
|
|
|
2.0 |
|
Incremental
option units
|
|
|
0.1 |
|
|
|
0.2 |
|
|
|
0.1 |
|
|
|
0.3 |
|
Total
|
|
|
464.4 |
|
|
|
437.8 |
|
|
|
458.5 |
|
|
|
436.9 |
|
Diluted
earnings per unit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income per unit before EPGP earnings allocation
|
|
$ |
0.45 |
|
|
$ |
0.46 |
|
|
$ |
1.36 |
|
|
$ |
1.66 |
|
Net
income available to EPGP
|
|
|
(0.09 |
) |
|
|
(0.08 |
) |
|
|
(0.27 |
) |
|
|
(0.25 |
) |
Net
income available to limited partners
|
|
$ |
0.36 |
|
|
$ |
0.38 |
|
|
$ |
1.09 |
|
|
$ |
1.41 |
|
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
Litigation
On
occasion, we or our unconsolidated affiliates are named as a defendant in
litigation and legal proceedings, including regulatory and environmental
matters. Although we are insured against various risks to the extent
we believe it is prudent, there is no assurance that the nature and amount of
such insurance will be adequate, in every case, to indemnify us against
liabilities arising from future legal proceedings. We are unaware of
any litigation, pending or threatened, that we believe is reasonably likely to
have a significant adverse effect on our financial position, results of
operations or cash flows.
We
evaluate our ongoing litigation based upon a combination of litigation and
settlement alternatives. These reviews are updated as the facts and
combinations of the cases develop or change. Assessing and predicting
the outcome of these matters involves substantial uncertainties. In
the event that the assumptions we used to evaluate these matters change in
future periods or new information becomes available, we may be required to
record a liability for an adverse outcome. In an effort to mitigate
potential adverse consequences of litigation, we could also seek to settle legal
proceedings brought against us. We have not recorded any significant
reserves for any litigation in our financial statements.
On
September 18, 2006, Peter Brinckerhoff, a purported unitholder of TEPPCO, filed
a complaint in the Court of Chancery of the State of Delaware (the “Delaware
Court”), in his individual capacity, as a putative class action on behalf of
other unitholders of TEPPCO and derivatively on behalf of TEPPCO, concerning,
among other things, certain transactions involving TEPPCO and us or our
affiliates. Mr. Brinckerhoff filed an amended complaint on July 12,
2007. The amended complaint names as defendants (i) TEPPCO, certain
of its current and former directors, and certain of its affiliates, (ii) us and
certain of our affiliates, (iii) EPCO and (iv) Dan L. Duncan.
The amended complaint alleges, among
other things, that the defendants caused TEPPCO to enter into specified
transactions that were unfair to TEPPCO or otherwise unfairly favored us or our
affiliates over TEPPCO. These transactions are alleged to include:
(i) the joint venture to further expand the Jonah system entered into by TEPPCO
and us in August 2006 (the plaintiff alleges that TEPPCO did not receive fair
value for allowing us to participate in the joint venture); (ii) the sale by
TEPPCO of its Pioneer natural gas processing plant and certain gas processing
rights to us in March 2006 (the plaintiff alleges that the purchase price we
paid did not provide fair value to TEPPCO); and (iii) certain amendments to
TEPPCO’s partnership agreement, including a reduction in the maximum tier of
TEPPCO’s incentive distribution rights in exchange for TEPPCO
units. The amended complaint seeks (i) rescission of the amendments
to TEPPCO’s partnership agreement, (ii) damages for profits and special benefits
allegedly obtained by defendants as a result of the alleged wrongdoings in the
amended complaint and (iii) an award to plaintiff of the costs of the action,
including fees and expenses of his attorneys and experts. By its
Opinion and Order dated November 25, 2008, the Delaware Court dismissed Mr.
Brinckerhoff’s individual and putative class action claims with respect to the
amendments to TEPPCO’s partnership agreement. We refer to this action
and the remaining claims in this action as the “Derivative Action.”
On April 29, 2009, Peter Brinckerhoff
and Renee Horowitz, as Attorney in Fact for Rae Kenrow, purported unitholders of
TEPPCO, filed separate complaints in the Delaware Court as putative class
actions on behalf of other unitholders of TEPPCO, concerning the TEPPCO
Merger. On May 11, 2009, these actions were consolidated under the
caption Texas Eastern Products Pipeline Company, LLC Merger Litigation, C.A. No.
4548-VCL (“Merger Action”). The complaints name as defendants us, EPGP, TEPPCO
GP, the directors of TEPPCO GP, EPCO and Dan L. Duncan.
The Merger Action complaints allege,
among other things, that the terms of the merger (as proposed as of the time the
Merger Action complaints were filed) are grossly unfair to TEPPCO’s unitholders
and that the TEPPCO Merger is an attempt to extinguish the Derivative Action
without consideration. The complaints further allege that the process
through which the Special Committee of the ACG Committee of TEPPCO GP was
appointed to consider the TEPPCO Merger is contrary to the spirit
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
and
intent of TEPPCO’s partnership agreement and constitutes a breach of the implied
covenant of fair dealing.
The complaints seek relief (i)
enjoining the defendants and all persons acting in concert with them from
pursuing the TEPPCO Merger, (ii) rescinding the TEPPCO Merger to the extent it
is consummated, or awarding rescissory damages in respect thereof, (iii)
directing the defendants to account for all damages suffered or to be suffered
by the plaintiffs and the purported class as a result of the defendants’ alleged
wrongful conduct, and (iv) awarding plaintiffs’ costs of the actions, including
fees and expenses of their attorneys and experts.
On June 28, 2009, the parties entered
into a Memorandum of Understanding pursuant to which we, TEPPCO, EPCO, TEPPCO
GP, all other individual defendants and the plaintiffs have proposed to settle
the Merger Action and the Derivative Action. The Memorandum of
Understanding contemplated that the parties would enter into a stipulation of
settlement within 30 days from the date of the Memorandum of
Understanding. On August 5, 2009, the parties entered into a
Stipulation and Agreement of Compromise, Settlement and Release (the “Settlement
Agreement”) contemplated by the Memorandum of Understanding. Pursuant
to the Settlement Agreement, the board of directors of TEPPCO GP recommended to
TEPPCO’s unitholders that they approve the adoption of the merger agreement and
took all necessary steps to seek unitholder approval for the merger as soon as
practicable. Pursuant to the Settlement Agreement, approval of the
merger required, in addition to votes required under TEPPCO’s partnership
agreement, that the actual votes cast in favor of the proposal by holders of
TEPPCO’s outstanding units, excluding those held by defendants to the Derivative
Action, exceed the actual votes cast against the proposal by those
holders. The Settlement Agreement further provides that the
Derivative Action was considered by TEPPCO GP’s Special Committee to be a
significant TEPPCO benefit for which fair value was obtained in the merger
consideration.
The Settlement Agreement is subject to
customary conditions, including Delaware Court approval. A hearing
regarding approval of the Settlement Agreement by the Delaware Court was held on
October 12, 2009, but the Delaware Court has yet to rule on the
settlement. There can be no assurance that the Delaware Court will
approve the settlement in the Settlement Agreement. In such event,
the proposed settlement as contemplated by the Settlement Agreement may be
terminated. Among other things, the plaintiffs’ agreement to settle
the Derivative Action and Merger Action litigation, including their agreement to
the fairness of the terms and process of the merger negotiations, is subject to
(i) the drafting and execution of other such documentation as may be required to
obtain final Delaware Court approval and dismissal of the actions, (ii) Delaware
Court approval and the mailing of the notice of settlement which sets forth the
terms of settlement to TEPPCO’s unitholders, (iii) consummation of the TEPPCO
Merger and (iv) final Delaware Court certification and approval of the
settlement and dismissal of the actions. See Notes 12 and 18 for
additional information regarding our relationship with TEPPCO, including
information related to the TEPPCO Merger.
Additionally,
on June 29 and 30, 2009, respectively, M. Lee Arnold and Sharon Olesky,
purported unitholders of TEPPCO, filed separate complaints in the District
Courts of Harris County, Texas, as putative class actions on behalf of other
unitholders of TEPPCO, concerning the TEPPCO Merger (the “Texas
Actions”). The complaints name as defendants us, TEPPCO, TEPPCO GP,
EPGP, EPCO, Dan L. Duncan, Jerry Thompson, and the board of directors of TEPPCO
GP. The allegations in the complaints are similar to the complaints
filed in Delaware on April 29, 2009 and seek similar relief. The
named plaintiffs in the two Texas Actions (the “Texas Plaintiffs/Objectors”)
have also appeared in the Delaware proceedings as objectors to the settlement of
those cases which are awaiting court approval. On October 7, 2009,
the Texas Plaintiffs/Objectors and the parties to the Settlement Agreement
entered into a Stipulation to Withdraw Objection (the
“Stipulation”). In accordance with the Stipulation, TEPPCO made
certain supplemental disclosures and, if the Settlement Agreement obtains Final
Court Approval (as defined in the Settlement Agreement), the Texas
Plaintiffs/Objectors have agreed to dismiss the Texas Actions with prejudice
and, pending such Final Court Approval, will take no action to prosecute the
Texas Actions.
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
In
February 2007, EPO received a letter from the Environment and Natural Resources
Division of the U.S. Department of Justice related to an ammonia release in
Kingman County, Kansas on October 27, 2004 from a pressurized anhydrous ammonia
pipeline owned by a third party, Magellan Ammonia Pipeline, L.P. (“Magellan”),
and a previous release of ammonia on September 27, 2004 from the same pipeline.
EPO was the operator of this pipeline until July 1, 2008. This
matter was settled in September 2009, and Magellan has agreed to pay all
assessed penalties.
The Attorney General of Colorado on
behalf of the Colorado Department of Public Health and Environment filed suit
against us and others on April 15, 2008 in connection with the construction of a
pipeline near Parachute, Colorado. The State sought a temporary
restraining order and an injunction to halt construction activities since it
alleged that the defendants failed to install measures to minimize damage to the
environment and to follow requirements for the pipeline’s stormwater permit and
appropriate stormwater plan. We have entered into a settlement agreement
with the State that dismisses the suit and assesses a fine of approximately $0.2
million.
In
January 2009, the State of New Mexico filed suit in District Court in Santa Fe
County, New Mexico, under the New Mexico Air Quality Control Act. The
lawsuit arose out of a February 27, 2008 Notice Of Violation issued to Marathon
Oil Corp. (“Marathon”) as operator of the Indian Basin natural gas processing
facility located in Eddy County, New Mexico. We own a 42.4% undivided
interest in the assets comprising the Indian Basin facility. The
State alleges violations of its air laws, and Marathon is attempting to
negotiate an acceptable resolution with the state. The State seeks
penalties and remedial projects above $0.1 million. Marathon continues to
work with the State to determine if resolution of the case is
possible. We believe that any potential penalties will not have a
material impact on our consolidated financial position, results of operations or
cash flows.
In
connection with the dissociation of TEPPCO and us from TOPS (see Note 7),
Oiltanking filed an original petition against Enterprise Offshore Port System,
LLC, EPO, TEPPCO O/S Port System, LLC, TEPPCO and TEPPCO GP in the District
Court of Harris County, Texas, 61st Judicial District (Cause No. 2009-31367),
asserting, among other things, that the dissociation was wrongful and in breach
of the TOPS partnership agreement, citing provisions of the agreement that, if
applicable, would continue to obligate us and TEPPCO to make capital
contributions to fund the project and impose liabilities on us and
TEPPCO. On September 17, 2009, we and TEPPCO entered into a
settlement agreement with certain affiliates of Oiltanking and TOPS that
resolved all disputes between the parties related to the business and affairs of
the TOPS project (including the litigation described above). We and
TEPPCO each recognized approximately $33.5 million of expense during the third
quarter of 2009 in connection with this settlement. This charge is
classified within our Offshore Pipelines & Services business
segment.
Regulatory
Matters
Recent scientific studies have
suggested that emissions of certain gases, commonly referred to as “greenhouse
gases” or “GHGs” and including carbon dioxide and methane, may be contributing
to climate change. On April 17, 2009, the U.S. Environmental
Protection Agency (“EPA”) issued a notice of its proposed finding and
determination that emission of carbon dioxide, methane, and other GHGs present
an endangerment to human health and the environment because emissions of such
gases are, according to the EPA, contributing to warming of the earth’s
atmosphere. The EPA’s finding and determination would allow it to
begin regulating emissions of GHGs under existing provisions of the federal
Clean Air Act. Although it may take the EPA several years to adopt
and impose regulations limiting emissions of GHGs, any such regulation could
require us to incur costs to reduce emissions of GHGs associated with our
operations. In addition, on June 26, 2009, the U.S. House of
Representatives approved adoption of the “American Clean Energy and Security Act
of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or
“ACESA.” ACESA would establish an economy-wide cap on emissions of
GHGs in the United States and would require most sources of GHG emissions to
obtain GHG emission “allowances” corresponding to their annual emissions of
GHGs. The U.S. Senate has also begun work on its own legislation for
controlling and reducing emissions of GHGs in the United States. Any
laws or regulations that may be adopted to restrict or reduce emissions of GHGs
would likely require us to incur increased
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
operating
costs, and may have an adverse effect on our business, financial position,
demand for our operations, results of operations and cash flows.
Contractual
Obligations
Scheduled
maturities of long-term debt. See
Notes 9 and 18 for information regarding changes in our consolidated debt
obligations.
Operating
lease obligations. During the second quarter of 2009, we
entered into a 20-year right-of-way agreement with the Jicarilla Apache Nation
in support of continued natural gas gathering activities on our San Juan
gathering system in Northwest New Mexico. Pending approval of this
agreement by the U.S. Department of the Interior, our minimum lease obligations
will be $3.0 million for the first year and $2.0 million per year for each of
the next succeeding four years. Aggregate minimum lease commitments
are $43.3 million over the 20-year contractual term. The agreement
also provides for contingent rentals that are calculated annually based on
actual throughput volumes and then current natural gas and NGL
prices. Our agreement with the Jicarilla Apache Nation does not
provide for renewal options beyond the 20-year lease term.
Prior to
May 2009, we leased rail and truck terminal facilities in Mont Belvieu, Texas
from Martin. At December 31, 2008, our remaining aggregate minimum
lease commitments under this agreement were $56.8 million through the
contractual term ending in 2023. The lease agreement with Martin was
terminated upon our acquisition of such facilities in May 2009. See
Note 6 for additional information regarding our acquisition of certain rail and
truck terminal facilities from Martin.
Except
for the foregoing, there have been no material changes in our operating lease
commitments since December 31, 2008. Lease and rental expense was
$11.4 million and $8.5 million during the three months ended September 30, 2009
and 2008, respectively. For the nine months ended September 30, 2009
and 2008, lease and rental expense was $31.0 million and $26.9 million,
respectively.
Purchase
obligations. Apart from that
discussed below, there have been no material changes in our consolidated
purchase obligations since December 31, 2008.
As a
result of our dissociation from TOPS, capital expenditure commitments decreased
by an estimated $68.0 million from that reported in our Recast Form 8-K.
See Note 7 for additional information regarding TOPS.
Other
Claims
As part of our normal business
activities with joint venture partners and certain customers and suppliers, we
occasionally have claims made against us as a result of disputes related to
contractual agreements or similar arrangements. As of September 30,
2009, claims against us totaled approximately $4.6 million. These
matters are in various stages of assessment and the ultimate outcome of such
disputes cannot be reasonably estimated. However, in our opinion, the
likelihood of a material adverse outcome related to disputes against us is
remote. Accordingly, accruals for loss contingencies related to these
matters, if any, that might result from the resolution of such disputes have not
been reflected in our consolidated financial statements.
Insurance
Matters
EPCO
completed its annual insurance renewal process during the second quarter of
2009. In light of recent hurricane and other weather-related events, the
renewal of policies for weather-related risks resulted in significant increases
in premiums and certain deductibles, as well as changes in the scope of
coverage.
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
EPCO’s
deductible for onshore physical damage from windstorms increased from $10.0
million per storm to $25.0 million per storm. EPCO’s onshore program
currently provides $150.0 million per occurrence for named windstorm events
compared to $175.0 million per occurrence in the prior year. With
respect to offshore assets, the windstorm deductible increased significantly
from $10.0 million per storm (with a one-time aggregate deductible of $15.0
million) to $75.0 million per storm. EPCO’s offshore program
currently provides $100.0 million in the aggregate compared to $175.0 million in
the aggregate for the prior year. For non-windstorm events, EPCO’s
deductible for both onshore and offshore physical damage
remained at $5.0 million per occurrence. For certain of our major offshore
assets, our producer customers have agreed to provide a specified level of
physical damage insurance for named windstorms. For example, the
producers associated with our Independence Hub and Marco Polo platforms have
agreed to cover windstorm generated physical damage costs up to $250.0 million
for each platform.
Business
interruption coverage in connection with a windstorm event remains in place for
onshore assets, but was eliminated for offshore assets. Onshore
assets covered by business interruption insurance must be out-of-service in
excess of 60 days before any losses from business interruption will be
covered. Furthermore, pursuant to the current policy, we will now
absorb 50% of the first $50.0 million of any loss in excess of deductible
amounts for our onshore assets.
In the third quarter of 2008, certain
of our onshore and offshore facilities located along the Gulf Coast of Texas and
Louisiana were damaged by Hurricanes Gustav and Ike. The disruptions
in hydrocarbon production caused by these storms resulted in decreased volumes
for some of our pipeline systems, natural gas processing plants, NGL
fractionators and offshore platforms, which in turn caused a decrease in gross
operating margin from these operations. As a result of our share of
EPCO’s insurance deductibles for windstorm coverage, we expensed a combined
cumulative total of $47.6 million of repair costs for property damage in
connection with these two storms through September 30, 2009. We
continue to file property damage claims in connection with the damage caused by
these storms. We recognize business interruption proceeds as income
when they are received in cash.
The
following table summarizes proceeds we received during the periods indicated
from business interruption and property damage insurance claims with respect to
certain named storms:
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Business
interruption proceeds:
|
|
|
|
|
|
|
|
|
|
|
|
|
Hurricane
Katrina
|
|
$ |
-- |
|
|
$ |
-- |
|
|
$ |
-- |
|
|
$ |
0.5 |
|
Hurricane
Rita
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
0.7 |
|
Hurricane
Ike
|
|
|
19.2 |
|
|
|
-- |
|
|
|
19.2 |
|
|
|
-- |
|
Total
business interruption proceeds
|
|
|
19.2 |
|
|
|
-- |
|
|
|
19.2 |
|
|
|
1.2 |
|
Property
damage proceeds:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hurricane
Ivan
|
|
|
0.7 |
|
|
|
-- |
|
|
|
0.7 |
|
|
|
-- |
|
Hurricane
Katrina
|
|
|
3.5 |
|
|
|
2.5 |
|
|
|
26.7 |
|
|
|
9.4 |
|
Hurricane
Rita
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
2.7 |
|
Total
property damage proceeds
|
|
|
4.2 |
|
|
|
2.5 |
|
|
|
27.4 |
|
|
|
12.1 |
|
Total
|
|
$ |
23.4 |
|
|
$ |
2.5 |
|
|
$ |
46.6 |
|
|
$ |
13.3 |
|
At
September 30, 2009, we have $22.6 million of estimated property damage claims
outstanding related to storms that we believe are probable of collection during
the next twelve months and $45.2 million thereafter. To the extent we
estimate the dollar value of such damages, please be aware that a change in our
estimates may occur, if and when additional information becomes
available.
Credit
Risk due to Industry Concentrations
Our
largest customer for 2008 was LyondellBassell Industries and its affiliates
(“LBI”), which accounted for 9.6% of our consolidated revenues during
2008. On January 6, 2009, LBI announced that its U.S. operations had
voluntarily filed to reorganize under Chapter 11 of the U.S. Bankruptcy
Code. At the time of the bankruptcy filing, we had approximately
$10.0 million of net credit exposure to LBI. We
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
resolved
our outstanding claims with LBI in October 2009 with no gain or loss being
recorded in connection with the settlement. We continue to do
business with this important customer; however, we continue to manage our credit
exposure to LBI.
The
following table provides information regarding the net effect of changes in our
operating assets and liabilities for the periods indicated:
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
Decrease
(increase) in:
|
|
|
|
|
|
|
Accounts
and notes receivable – trade
|
|
$ |
(286.0 |
) |
|
$ |
91.6 |
|
Accounts
receivable – related parties
|
|
|
37.2 |
|
|
|
(6.7 |
) |
Inventories
|
|
|
(799.2 |
) |
|
|
(299.1 |
) |
Prepaid
and other current assets
|
|
|
3.0 |
|
|
|
(43.9 |
) |
Other
assets
|
|
|
(24.6 |
) |
|
|
24.2 |
|
Increase
(decrease) in:
|
|
|
|
|
|
|
|
|
Accounts
payable – trade
|
|
|
8.3 |
|
|
|
(57.2 |
) |
Accounts
payable – related parties
|
|
|
8.0 |
|
|
|
51.2 |
|
Accrued
product payables
|
|
|
537.5 |
|
|
|
14.2 |
|
Accrued
interest payable
|
|
|
(3.0 |
) |
|
|
27.2 |
|
Other
accrued expenses
|
|
|
(34.8 |
) |
|
|
(29.0 |
) |
Other
current liabilities
|
|
|
(30.8 |
) |
|
|
7.7 |
|
Other
liabilities
|
|
|
(5.6 |
) |
|
|
(8.6 |
) |
Net
effect of changes in operating accounts
|
|
$ |
(590.0 |
) |
|
$ |
(228.4 |
) |
We
incurred liabilities for construction in progress that had not been paid at
September 30, 2009 and December 31, 2008 of $109.2 million and $91.6 million,
respectively. Such amounts are not included under the caption
“Capital expenditures” on the Unaudited Condensed Statements of Consolidated
Cash Flows.
EPO
conducts substantially all of our business. Currently, we have no
independent operations and no material assets outside those of
EPO. EPO consolidates the financial statements of Duncan Energy
Partners with its own financial statements.
Enterprise
Products Partners L.P. guarantees the debt obligations of EPO, with the
exception of Duncan Energy Partners’ debt obligations. If EPO were to
default on any of its guaranteed debt, Enterprise Products Partners L.P. would
be responsible for full repayment of that obligation. See Note 9 for
additional information regarding our consolidated debt obligations.
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
The
reconciling items between our consolidated financial statements and those of EPO
are insignificant. The following table presents condensed
consolidated balance sheet data for EPO at the dates indicated:
|
|
September
30,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
ASSETS
|
|
|
|
|
|
|
Current
assets
|
|
$ |
3,149.8 |
|
|
$ |
2,175.6 |
|
Property,
plant and equipment, net
|
|
|
13,661.6 |
|
|
|
13,154.8 |
|
Investments
in unconsolidated affiliates
|
|
|
901.0 |
|
|
|
949.5 |
|
Intangible
assets, net
|
|
|
793.0 |
|
|
|
855.4 |
|
Goodwill
|
|
|
706.9 |
|
|
|
706.9 |
|
Other
assets
|
|
|
145.1 |
|
|
|
126.6 |
|
Total
|
|
$ |
19,357.4 |
|
|
$ |
17,968.8 |
|
LIABILITIES
AND EQUITY
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
$ |
2,689.4 |
|
|
$ |
2,222.7 |
|
Long-term
debt
|
|
|
9,198.3 |
|
|
|
9,108.4 |
|
Other
long-term liabilities
|
|
|
165.5 |
|
|
|
147.3 |
|
Equity
|
|
|
7,304.2 |
|
|
|
6,490.4 |
|
Total
|
|
$ |
19,357.4 |
|
|
$ |
17,968.8 |
|
|
|
|
|
|
|
|
|
|
Total
EPO debt obligations guaranteed Enterprise
Products Partners L.P.
|
|
$ |
8,682.2 |
|
|
$ |
8,561.8 |
|
The
following table presents condensed consolidated statements of operations data
for EPO for the periods indicated:
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Revenues
|
|
$ |
4,596.1 |
|
|
$ |
6,297.9 |
|
|
$ |
11,527.1 |
|
|
$ |
18,322.1 |
|
Costs
and expenses
|
|
|
4,245.8 |
|
|
|
5,993.4 |
|
|
|
10,465.6 |
|
|
|
17,308.5 |
|
Equity
in income of unconsolidated affiliates
|
|
|
22.5 |
|
|
|
14.9 |
|
|
|
18.3 |
|
|
|
48.1 |
|
Operating
income
|
|
|
372.8 |
|
|
|
319.4 |
|
|
|
1,079.8 |
|
|
|
1,061.7 |
|
Other
expense
|
|
|
(128.0 |
) |
|
|
(101.5 |
) |
|
|
(373.7 |
) |
|
|
(287.7 |
) |
Income
before provision for income taxes
|
|
|
244.8 |
|
|
|
217.9 |
|
|
|
706.1 |
|
|
|
774.0 |
|
Provision
for income taxes
|
|
|
(6.6 |
) |
|
|
(6.6 |
) |
|
|
(24.0 |
) |
|
|
(17.2 |
) |
Net
income
|
|
|
238.2 |
|
|
|
211.3 |
|
|
|
682.1 |
|
|
|
756.8 |
|
Net
income attributable to the noncontrolling interest
|
|
|
(17.0 |
) |
|
|
(8.0 |
) |
|
|
(42.7 |
) |
|
|
(29.4 |
) |
Net
income attributable to EPO
|
|
$ |
221.2 |
|
|
$ |
203.3 |
|
|
$ |
639.4 |
|
|
$ |
727.4 |
|
Issuance
of Senior Notes Q and R
On
October 5, 2009, EPO issued $500.0 million in principal amount of 10-year
unsecured Senior Notes Q and $600.0 million in principal amount of 30-year
unsecured Senior Notes R. Senior Notes Q were issued at 99.355% of
their principal amount, have a fixed interest rate of 5.25% and mature on
January 31, 2020. Senior Notes R were issued at 99.386% of their
principal amount, have a fixed interest rate of 6.125% and mature on October 15,
2039. Net proceeds from the issuance of Senior Notes Q and R were
used (i) to repay $500.0 million in aggregate principal amount of Senior Notes F
that matured in October 2009, (ii) to temporarily reduce borrowings outstanding
under EPO’s Multi-Year Revolving Credit Facility and (iii) for general
partnership purposes.
Senior
Notes Q and R rank equal with EPO’s existing and future unsecured and
unsubordinated indebtedness. They are senior to any existing and
future subordinated indebtedness of EPO. Senior Notes Q and R are
subject to make-whole redemption rights and were issued under indentures
containing certain
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
covenants,
which generally restrict EPO’s ability, with certain exceptions, to incur debt
secured by liens and engage in sale and leaseback transactions.
Completion
of TEPPCO Merger
On October 26, 2009, the related
mergers of our wholly owned subsidiaries with TEPPCO and TEPPCO GP were
completed. Under terms of the merger agreements, TEPPCO and TEPPCO GP
became wholly owned subsidiaries of ours and each of TEPPCO's unitholders,
except for a privately held affiliate of EPCO, were entitled to receive 1.24 of
our common units for each TEPPCO unit. In total, we issued an
aggregate of 126,932,318 common units and 4,520,431 Class B units (described
below) as consideration in the TEPPCO Merger for both TEPPCO units and the
TEPPCO GP membership interests. TEPPCO’s units, which had been
trading on the NYSE under the ticker symbol TPP, have been delisted and are no
longer publicly traded.
A
privately held affiliate of EPCO exchanged a portion of its TEPPCO units, based
on the 1.24 exchange rate, for 4,520,431 of our Class B units in lieu of common
units. The Class B units are not entitled to regular quarterly cash
distributions for the first sixteen quarters following the closing date of the
merger. The Class B units automatically convert into the same number
of common units on the date immediately following the payment date for the
sixteenth quarterly distribution following the closing date of the
merger. The Class B units are entitled to vote together with the
common units as a single class on partnership matters and, except for the
payment of distributions, have the same rights and privileges as our common
units.
Under the
terms of the TEPPCO Merger agreements, Enterprise GP Holdings received 1,331,681
of our common units and an increase in the capital account of EPGP to maintain
its 2% general partner interest in us as consideration for 100% of the
membership interests of TEPPCO GP. Following the closing of the
TEPPCO Merger, affiliates of EPCO owned approximately 31.3% of our outstanding
limited partner units, including 3.4% owned by Enterprise GP
Holdings.
The
post-merger partnership, which retains the name Enterprise Products Partners
L.P., accesses the largest producing basins of natural gas, NGLs and crude oil
in the U.S., and serves some of the largest consuming regions for natural gas,
NGLs, refined products, crude oil and petrochemicals. The post-merger
partnership owns almost 48,000 miles of pipelines comprised of over 22,000 miles
of NGL, refined product and petrochemical pipelines, over 20,000 miles of
natural gas pipelines and more than 5,000 miles of crude oil
pipelines. The merged partnership’s logistical assets include
approximately 200 MMBbls of NGL, refined product and crude oil storage capacity;
27 Bcf of natural gas storage capacity; one of the largest NGL import/export
terminals in the U.S., located on the Houston Ship Channel; 60 NGL, refined
product and chemical terminals spanning the U.S. from the west coast to the east
coast; and crude oil import terminals on the Texas Gulf Coast. The
post-merger partnership owns interests in 17 fractionation plants with over 600
thousand barrels per day (“MBPD”) of net capacity; 25 natural gas processing
plants with a net capacity of approximately 9 Bcf/d; and 3 butane isomerization
facilities with a capacity of 116 MBPD. The post-merger partnership is also one
of the largest inland tank barge companies in the U.S.
The
merger transactions will be accounted for as a reorganization of entities under
common control in a manner similar to a pooling of interests. The
financial and operating activities of Enterprise Products Partners, TEPPCO and
Enterprise GP Holdings and their respective general partners, and EPCO and its
privately held subsidiaries, are under the common control of Dan L.
Duncan.
We
incurred $14.4 million of merger-related expenses during the nine months ended
September 30, 2009 that are reflected as a component of general and
administrative costs.
The
following table presents selected unaudited pro forma earnings information for
the periods presented as if the TEPPCO Merger had occurred on January 1 of each
period. The selected unaudited pro forma earnings information is
based on assumptions that we believe are reasonable under the circumstances and
are intended for informational purposes only. They are not
necessarily indicative of the financial results that would have occurred if the
TEPPCO Merger had taken place on the dates indicated, nor are they
ENTERPRISE
PRODUCTS PARTNERS L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
indicative
of the future consolidated results of the post-merger
partnership. Amounts presented in the table are in millions, except
per unit amounts.
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
Revenues
|
|
$ |
17,110.5 |
|
|
$ |
29,544.1 |
|
Costs
and expenses
|
|
|
15,863.5 |
|
|
|
28,251.0 |
|
Operating
income
|
|
|
1,210.6 |
|
|
|
1,325.0 |
|
Net
income
|
|
|
714.3 |
|
|
|
912.8 |
|
|
|
|
|
|
|
|
|
|
Basic EPU:
|
|
|
|
|
|
|
|
|
Units
outstanding, as reported
|
|
|
458.4 |
|
|
|
436.6 |
|
Units
outstanding, pro forma
|
|
|
585.3 |
|
|
|
563.5 |
|
Basic
EPU, as reported
|
|
$ |
1.09 |
|
|
$ |
1.41 |
|
Basic
EPU, pro forma
|
|
$ |
0.88 |
|
|
$ |
1.32 |
|
|
|
|
|
|
|
|
|
|
Diluted
EPU:
|
|
|
|
|
|
|
|
|
Units
outstanding, as reported
|
|
|
458.5 |
|
|
|
436.9 |
|
Units
outstanding, pro forma
|
|
|
590.0 |
|
|
|
568.4 |
|
Diluted
EPU, as reported
|
|
$ |
1.09 |
|
|
$ |
1.41 |
|
Diluted
EPU, pro forma
|
|
$ |
0.87 |
|
|
$ |
1.31 |
|
In
connection with the TEPPCO Merger, EPO commenced offers in September 2009 to
exchange all of TEPPCO’s outstanding notes for a corresponding series of new EPO
notes. The purpose of the exchange offer was to simplify our capital
structure following the TEPPCO Merger. The exchanges were completed
on October 27, 2009. The new EPO notes are guaranteed by Enterprise
Products Partners L.P. As presented in the following
table, the aggregate principal amount of the TEPPCO notes was $2 billion, of
which $1.95 billion was exchanged:
|
|
Principal
Amount
Exchanged
|
|
|
Principal
Amount
Remaining
|
|
7.625%
Senior Notes due 2012
|
|
$ |
490.5 |
|
|
$ |
9.5 |
|
6.125%
Senior Notes due 2013
|
|
|
182.5 |
|
|
|
17.5 |
|
5.90%
Senior Notes due 2013
|
|
|
237.6 |
|
|
|
12.4 |
|
6.65%
Senior Notes due 2018
|
|
|
349.7 |
|
|
|
0.3 |
|
7.55%
Senior Notes due 2038
|
|
|
399.6 |
|
|
|
0.4 |
|
7.00%
Junior Fixed/Floating Subordinated Notes due 2067
|
|
|
285.8 |
|
|
|
14.2 |
|
|
|
$ |
1,945.7 |
|
|
$ |
54.3 |
|
The EPO
notes issued in the exchange will be recorded at the same carrying value as the
TEPPCO notes being replaced. Accordingly, we will recognize no gain
or loss for accounting purposes related to this exchange. All note
exchange direct costs paid to third parties will be expensed.
In
addition to the debt exchange, we gained approval from the requisite TEPPCO
noteholders to eliminate substantially all of the restrictive covenants and
reporting requirements associated with the remaining TEPPCO notes.
Upon the
consummation of the TEPPCO Merger, EPO repaid and terminated indebtedness under
TEPPCO’s revolving credit facility.
For
the three and nine months ended September 30, 2009 and 2008.
The following information should be
read in conjunction with our unaudited condensed consolidated financial
statements and accompanying notes included in this report. The
following information and such unaudited condensed consolidated financial
statements should also be read in conjunction with the financial statements and
related notes, together with our discussion and analysis of financial position
and results of operations included in our Current Report on Form 8-K dated July
8, 2009 (the “Recast Form 8-K”), which retroactively adjusted portions of our
Annual Report for the year ended December 31, 2008. The Recast Form
8-K reflects our adoption of the provisions under Accounting Standards
Codification (“ASC”) 810, Consolidation, related to noncontrolling interests,
our adoption of the provisions under ASC 260, Earnings Per Share, pertaining to
the application of the two-class method to master limited partnerships in
computing basic and diluted earnings per share, and the resulting change in
presentation and disclosure requirements.
Our
financial statements have been prepared in accordance with U.S. generally
accepted accounting principles (“GAAP”).
Key
References Used in this Quarterly Report
Enterprise Products Partners L.P. is a
publicly traded Delaware limited partnership, the common units of which are
listed on the New York Stock Exchange (“NYSE”) under the ticker symbol
“EPD.” Unless the context requires otherwise, references to “we,”
“us,” “our,” or “Enterprise Products Partners” are intended to mean the business
and operations of Enterprise Products Partners L.P. and its consolidated
subsidiaries.
References to “EPO” mean Enterprise
Products Operating LLC, which is a wholly owned subsidiary of Enterprise
Products Partners through which Enterprise Products Partners conducts
substantially all of its business.
References
to “Duncan Energy Partners” mean Duncan Energy Partners L.P., which is a
consolidated subsidiary of EPO and a publicly traded Delaware limited
partnership, the common units of which are listed on the NYSE under the ticker
symbol “DEP.” References to “DEP GP” mean DEP Holdings, LLC, which is
the general partner of Duncan Energy Partners and is wholly owned by
EPO.
References
to “EPGP” mean Enterprise Products GP, LLC, which is our general
partner.
References to “Enterprise GP Holdings”
mean Enterprise GP Holdings L.P., a publicly traded limited partnership, the
units of which are listed on the NYSE under the ticker symbol
“EPE.” Enterprise GP Holdings owns EPGP. References to
“EPE Holdings” mean EPE Holdings, LLC, which is the general partner of
Enterprise GP Holdings.
References
to “TEPPCO” and “TEPPCO GP” mean TEPPCO Partners, L.P. and Texas Eastern
Products Pipeline Company, LLC (which is the general partner of TEPPCO) prior to
their mergers with our subsidiaries. On October 26, 2009, we
completed our merger with TEPPCO and TEPPCO GP (such related mergers referred to
herein individually and together as the “TEPPCO Merger”). For
additional information regarding the TEPPCO Merger, see “Recent Developments”
included within this Item 2.
References
to “Energy Transfer Equity” mean the business and operations of Energy Transfer
Equity, L.P. and its consolidated subsidiaries, which include Energy Transfer
Partners, L.P. Energy Transfer Equity is a publicly traded Delaware
limited partnership, the common units of which are listed on the NYSE under the
ticker symbol “ETE.” The general partner of Energy Transfer Equity is
LE GP, LLC (“LE GP”). Enterprise GP Holdings owns a noncontrolling
interest in both LE GP and Energy Transfer Equity. Enterprise GP
Holdings accounts for its investments in LE GP and Energy Transfer Equity using
the equity method of accounting.
References
to “EPCO” mean EPCO, Inc. and its wholly owned, privately held affiliates, which
are related parties to all of the foregoing named entities.
We, EPO,
Duncan Energy Partners, DEP GP, EPGP, Enterprise GP Holdings, EPE Holdings,
TEPPCO and TEPPCO GP are affiliates under the common control of Dan L. Duncan,
the Group Co-Chairman and controlling shareholder of EPCO.
As
generally used in the energy industry and in this discussion, the identified
terms have the following meanings:
|
/d
|
|
=
per day
|
|
BBtus
|
|
=
billion British thermal units
|
|
MBPD
|
|
=
thousand barrels per day
|
|
MMBbls
|
|
=
million barrels
|
|
MMBtus
|
|
=
million British thermal units
|
|
MMcf
|
|
=
million cubic feet
|
|
Bcf
|
|
=
billion cubic feet
|
Cautionary
Note Regarding Forward-Looking Statements
This
discussion contains various forward-looking statements and information that are
based on our beliefs and those of our general partner, as well as assumptions
made by us and information currently available to us. When used in
this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,”
“goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “will,” “believe,”
“may,” “potential” and similar expressions and statements regarding our plans
and objectives for future operations, are intended to identify forward-looking
statements. Although we and our general partner believe that such
expectations reflected in such forward-looking statements are reasonable,
neither we nor our general partner can give any assurances that such
expectations will prove to be correct. Such statements are subject to
a variety of risks, uncertainties and assumptions as described in more detail in
Item 1A “Risk Factors” included in our Annual Report on Form 10-K for
2008. If one or more of these risks or uncertainties materialize, or
if underlying assumptions prove incorrect, our actual results may vary
materially from those anticipated, estimated, projected or
expected. You should not put undue reliance on any forward-looking
statements. The forward-looking statements in this Quarterly Report
speak only as of the date hereof. Except as required by federal and
state securities laws, we undertake no obligation to publicly update or revise
any forward-looking statements, whether as a result of new information, future
events or any other reason.
Critical
Accounting Policies and Estimates
A summary
of the significant accounting policies we have adopted and followed in the
preparation of our consolidated financial statements is included in our Recast
Form 8-K. Certain of these accounting policies require the use of
estimates. As more fully described therein, the following estimates,
in our opinion, are subjective in nature, require the exercise of judgment and
involve complex analysis: depreciation methods and estimated useful lives of
property, plant and equipment; measuring recoverability of long-lived assets and
equity method investments; amortization methods and estimated useful lives of
qualifying intangible assets; methods we employ to measure the fair value of
goodwill; revenue recognition policies and use of estimates for revenues and
expenses; reserves for environmental matters; and natural gas
imbalances. These estimates are based on our current knowledge and
understanding and may change as a result of actions we may take in the
future. Changes in these estimates will occur as a result of the
passage of time and the occurrence of future events. Subsequent
changes in these estimates may have a significant impact on our financial
position, results of operations and cash flows.
Overview
of Business
We are a
North American midstream energy company providing a wide range of services to
producers and consumers of natural gas, natural gas liquids (“NGLs”), crude oil
and certain petrochemicals. In addition, we are an industry leader in
the development of pipeline and other midstream energy
infrastructure
in the continental United States and Gulf of Mexico. We are a
publicly traded Delaware limited partnership formed in 1998, the common units of
which are listed on the NYSE under the ticker symbol “EPD.”
Our
midstream energy asset network links producers of natural gas, NGLs and crude
oil from some of the largest supply basins in the United States, Canada and the
Gulf of Mexico to domestic consumers and international markets. We
have four reportable business segments: NGL Pipelines & Services; Onshore
Natural Gas Pipelines & Services; Offshore Pipelines & Services; and
Petrochemical Services. Our business segments are generally organized
and managed according to the type of services rendered (or technologies
employed) and products produced and/or sold.
We
conduct substantially all of our business through EPO. We are owned
98% by our limited partners and 2% by our general partner, EPGP. EPGP
is owned 100% by Enterprise GP Holdings.
Recent
Developments
The
following information highlights our significant developments since January 1,
2009 through the date of this filing.
Merger
of TEPPCO and TEPPCO GP with Enterprise Products Partners
On
October 26, 2009, the related mergers of our wholly owned subsidiaries with
TEPPCO and TEPPGO GP were completed. Under terms of the merger
agreements, TEPPCO and TEPPCO GP became wholly owned subsidiaries of ours and
each of TEPPCO's unitholders, except for a privately held affiliate of EPCO,
were entitled to receive 1.24 of our common units for each TEPPCO
unit. In total, we issued an aggregate of 126,932,318 common units
and 4,520,431 Class B units (described below) as consideration in the TEPPCO
Merger for both TEPPCO units and the TEPPCO GP membership
interests. TEPPCO’s units, which had been trading on the NYSE under
the ticker symbol TPP, have been delisted and are no longer publicly
traded.
A
privately held affiliate of EPCO exchanged a portion of its TEPPCO units, based
on the 1.24 exchange rate, for 4,520,431 of our Class B units in lieu of common
units. The Class B units are not entitled to regular quarterly cash
distributions for the first sixteen quarters following the closing date of the
merger. The Class B units automatically convert into the same number
of common units on the date immediately following the payment date for the
sixteenth quarterly distribution following the closing date of the
merger. The Class B units are entitled to vote together with the
common units as a single class on partnership matters and, except for the
payment of distributions, have the same rights and privileges as our common
units.
Under the
terms of the TEPPCO Merger agreements, Enterprise GP Holdings received 1,331,681
of our common units and an increase in the capital account of EPGP to maintain
its 2% general partner interest in us as consideration for 100% of the
membership interests of TEPPCO GP. Following the closing of the
TEPPCO Merger, affiliates of EPCO owned approximately 31.3% of our outstanding
limited partner units, including 3.4% owned by Enterprise GP
Holdings.
The
post-merger partnership, which retains the name Enterprise Products Partners
L.P., accesses the largest producing basins of natural gas, NGLs and crude oil
in the U.S., and serves some of the largest consuming regions for natural gas,
NGLs, refined products, crude oil and petrochemicals. The post-merger
partnership owns almost 48,000 miles of pipelines comprised of over 22,000 miles
of NGL, refined product and petrochemical pipelines, over 20,000 miles of
natural gas pipelines and more than 5,000 miles of crude oil
pipelines. The merged partnership’s logistical assets include
approximately 200 MMBbls of NGL, refined product and crude oil storage capacity;
27 Bcf of natural gas storage capacity; one of the largest NGL import/export
terminals in the U.S., located on the Houston Ship Channel; 60 NGL, refined
product and chemical terminals spanning the U.S. from the west coast to the east
coast; and crude oil import terminals on the Texas Gulf Coast. The
post-merger partnership owns interests in 17 fractionation plants with over 600
MBPD of net capacity; 25 natural gas processing plants with a net capacity of
approximately
9 Bcf/d;
and 3 butane isomerization facilities with a capacity of 116 MBPD. The
post-merger partnership is also one of the largest inland tank barge companies
in the U.S.
The
merger transactions will be accounted for as a reorganization of entities under
common control in a manner similar to a pooling of interests. The
financial and operating activities of Enterprise Products Partners, TEPPCO and
Enterprise GP Holdings and their respective general partners, and EPCO and its
privately held subsidiaries, are under the common control of Dan L.
Duncan. See Note 18 of the Notes to Unaudited Condensed
Consolidated Financial Statements included under Item 1 of this Quarterly Report
for selected financial information, including selected unaudited pro forma data,
related to the merger.
In
connection with the TEPPCO Merger, EPO commenced offers in September 2009 to
exchange all of TEPPCO’s outstanding notes (a combined principal amount of $2
billion) for a corresponding series of new EPO notes. The purpose of
the exchange offer was to simplify our capital structure following the TEPPCO
Merger. The exchanges were completed on October 27,
2009. The new EPO notes are guaranteed by Enterprise Products
Partners L.P. The EPO notes issued in the exchange will be recorded
at the same carrying value as the TEPPCO notes being
replaced. Accordingly, we will recognize no gain or loss for
accounting purposes related to this exchange. All note exchange
direct costs paid to third parties will be expensed. In addition to
the debt exchange, we gained approval from the requisite TEPPCO noteholders to
eliminate substantially all of the restrictive covenants and reporting
requirements associated with the remaining TEPPCO notes. Upon the
consummation of the TEPPCO Merger, EPO repaid and terminated indebtedness under
TEPPCO’s revolving credit facility.
Enterprise
Products Partners and Duncan Energy Partners Announce Extension of
Acadian
Gas System into Haynesville Shale Play
In
October 2009, we and our affiliate, Duncan Energy Partners, announced plans for
our jointly owned Acadian Gas System to extend its Louisiana intrastate natural
gas pipeline system into Northwest Louisiana to provide producers in the rapidly
expanding Haynesville Shale resource basin with access to additional markets
through connections with the Acadian Gas System in South Louisiana and nine
major interstate natural gas pipelines (“Haynesville Extension”). The
Haynesville Shale covers about 2 million acres in Northwest Louisiana, almost
all of which is under lease. Production from the approximately 200
wells drilled to date is estimated at more than 1 Bcf/d. Over 400
locations are in various stages of drilling and completion with approximately
150 rigs now working in the region.
As
currently designed, our Haynesville Extension pipeline project will have the
capacity to transport up to 1.4 Bcf/d of natural gas from the Haynesville area
through a 249-mile pipeline that will connect with our existing Acadian Gas
System. Subject to additional long-term commitments received before
pipe orders are placed, the capacity of the Haynesville Extension could be
increased to 2.0 Bcf/d. The pipeline is expected to be in service in
September 2011.
The
Acadian Gas System serves major natural gas markets along the Mississippi River
corridor between Baton Rouge and New Orleans and has the ability to make
physical deliveries into the Henry Hub. The Haynesville Extension
will also have interconnects with major interstate pipelines include Florida
Gas, Texas Eastern, Transco, Sonat, Columbia Gulf, Trunkline, ANR, Tennessee Gas
and Texas Gas. Together with the capacity of the existing Acadian Gas
System, the extension project will provide approximately 5.5 Bcf/d of redelivery
capacity into an estimated 12 Bcf/d of available downstream pipeline takeaway
capacity. Initially, the project will connect to nine Haynesville
Shale producer locations in DeSoto and Red River parishes.
Along
with providing much needed natural gas takeaway capacity for growing Haynesville
production, the new pipeline is expected to provide shippers the opportunity to
benefit from more favorable pricing points and diverse service options and
access to the South Louisiana marketplace. For producers, the more
flexible contracting options associated with an intrastate pipeline environment
would help facilitate a seamless transaction for the producer from the field to
the end user.
Currently,
Duncan Energy Partners owns a 66% equity interest in the entities that own the
Acadian Gas System, with EPO owning the remaining 34% equity
interests. Duncan Energy Partners and EPO are in discussions as to
the funding of the Haynesville Extension project.
EPO
Issues $1.1 Billion of Senior Notes
In
October 2009, EPO issued $500.0 million in principal amount of 5.25% fixed-rate,
unsecured senior notes due January 2020 (“Senior Notes Q”) and $600.0 million in
principal amount of 6.125% fixed-rate, unsecured senior notes due October 2039
(“Senior Notes R”). Net proceeds from this offering were used (i) to
repay $500.0 million in aggregate principal amount of senior notes that matured
in October 2009 (“Senior Notes F”), (ii) to temporarily reduce borrowings
outstanding under EPO’s Multi-Year Revolving Credit Facility and (iii) for
general partnership purposes. For additional information regarding
these issuances of debt, see Note 18 of the Notes to Unaudited Condensed
Consolidated Financial Statements included under Item 1 of this Quarterly
Report.
Enterprise
Products Partners Issues $226.4 million of Common Units
In
September 2009, we issued 8,337,500 common units (including an overallotment
amount of 1,087,500 common units) in an underwritten public offering at a price
of $28.00 per unit. We used the combined net offering proceeds of $226.4 million
to reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit
Facility and for general partnership purposes.
Enterprise
Products Partners to Provide Natural Gas Transportation and Processing
Services
for
Major Eagle Ford Shale Producer
In
September 2009, we announced that we had entered into a long-term agreement to
provide natural gas transportation and processing services on dedicated acreage
owned by one of the largest and most active producers in the developing Eagle
Ford Shale natural gas play in South Texas. The agreement covers more
than 150,000 acres in the heart of the Eagle Ford Shale natural gas
play. Stretching from the Mexico border along the Gulf Coast to near
Louisiana, the Eagle Ford Shale production area covers more than 10 million
acres in Texas and lies beneath or near our existing natural gas and NGL asset
infrastructure in the region.
Enterprise
Products Partners Enters into Agreement for $150.0 Million
Private
Placement of Common Units
On
September 4, 2009, we agreed to issue 5,940,594 common units in a private
placement to EPCO Holdings, Inc., a privately held affiliate controlled by Dan
L. Duncan, for approximately $150.0 million, or $25.25 per unit. In
accordance with the terms of the private placement, as approved by the Audit,
Conflicts and Governance Committee of EPGP’s Board of Directors on September 1,
2009, the per unit purchase price of $25.25 was calculated based on a five
percent discount to the five-day volume weighted average price (“5-Day VWAP”) of
our common units, as reported by the NYSE at the close of business on September
4, 2009. The 5-Day VWAP was based on (i) the closing price for the
common units on the NYSE for each of the trading days in such five-day period
and (ii) the total trading volume for the common units reported by the NYSE for
each such trading day. We used the net proceeds from this private
placement to temporarily reduce borrowings outstanding under EPO’s Multi-Year
Revolving Credit Facility and for other general partnership
purposes. The common units were issued on September 8,
2009.
Enterprise
Products Partners Announces Expansion of NGL Fractionation Capacity
at
Mont
Belvieu, Texas Complex
In August
2009, we announced plans to build a new 75 MBPD NGL fractionator at our Mont
Belvieu, Texas complex that will provide us with additional capacity to handle
growing NGL volumes from producing areas in the Rockies, the Barnett Shale and
the emerging Eagle Ford Shale play in South Texas. This expansion,
which is supported by long-term contracts, will be based on the design of our 75
MBPD
Hobbs fractionator in Gaines County, Texas that began service in August
2007. When completed,
the
project will increase our NGL fractionation capacity at Mont Belvieu to
approximately 300 MBPD and net system-wide capacity to approximately 600
MBPD. The project is expected to be completed in the first quarter of
2011.
Duncan
Energy Partners’ Equity Offering
In June 2009, Duncan Energy Partners
completed an offering of 8,000,000 of its common units, which
generated net proceeds of approximately $122.9 million. In July 2009,
the underwriters to this offering exercised their option to purchase an
additional 943,400 common units, which generated $14.5 million of additional net
proceeds for Duncan Energy Partners. Duncan Energy Partners used the
aggregate net proceeds from this offering to repurchase an equal number of its
common units that were beneficially owned by EPO. Duncan Energy
Partners subsequently cancelled the common units it repurchased from
EPO.
Jicarilla
Apache Nation and Enterprise Products Partners Announce
Long-Term
Right-of-Way Agreement
In June
2009, the Jicarilla Apache Nation and an affiliate of ours announced they had
signed a 20-year right-of-way agreement that will allow us to continue our
natural gas gathering operations on the Nation’s reservation lands in Northwest
New Mexico. Under the terms of the agreement, we will continue to own
and operate existing infrastructure and related assets located on tribal land,
including 545 miles of gathering lines connected to our San Juan Gathering
system that have current throughput in excess of 30 MMcf/d of natural
gas.
EPO
Issues $500.0 Million of Senior Notes
In June
2009, EPO issued $500.0 million in principal amount of 4.60% fixed-rate,
unsecured senior notes due August 2012 (“Senior Notes P”). Net
proceeds from this offering were used (i) to repay the $200.0 Million Term Loan,
(ii) to temporarily reduce borrowings outstanding under EPO’s Multi-Year
Revolving Credit Facility and (iii) for general partnership
purposes. For additional information regarding this issuance of debt,
see Note 9 of the Notes to Unaudited Condensed Consolidated Financial
Statements included under Item 1 of this Quarterly Report.
Enterprise
Products Partners Exits Texas Offshore Port System Partnership
In August
2008, a wholly owned subsidiary of ours, together with a subsidiary of TEPPCO
and Oiltanking Holding Americas, Inc. (“Oiltanking”), formed the Texas Offshore
Port System partnership (“TOPS”). Effective April 16, 2009, our
wholly owned subsidiary dissociated (exited) from TOPS. As a result,
equity earnings for the nine months ended September 30, 2009 reflects a non-cash
charge of $34.2 million. This loss represented our cumulative
investment in TOPS through the date of dissociation and reflected our capital
contributions to TOPS for construction in progress amounts. The
subsidiary of TEPPCO also dissociated from TOPS in April 2009. On
September 17, 2009, we and TEPPCO entered into a settlement agreement with
certain affiliates of Oiltanking that resolved all disputes between the parties
related to the business and affairs of the TOPS project. We and
TEPPCO each recognized approximately $33.5 million of expense during the third
quarter of 2009 in connection with this settlement. See Note 14 of
the Notes to Unaudited Condensed Consolidated Financial Statements included
under Item 1 of this Quarterly Report for litigation matters associated with our
dissociation from TOPS.
Service
Begins on Shenzi Crude Oil Export Pipeline
In April 2009, we announced that
construction of our crude oil pipeline serving the Shenzi field in the Gulf of
Mexico had been completed and is now transporting production from the deepwater
discovery. The 83-mile pipeline has a transportation capacity of 230
MBPD of crude oil and gives Shenzi producers access to the Cameron Highway Oil
Pipeline and Poseidon Oil Pipeline systems, in which we have ownership interests
and operate.
Service
Begins on Sherman Extension Pipeline
In late February 2009, we and Duncan
Energy Partners announced that construction had been completed on the 174-mile
Sherman Extension expansion of our Texas Intrastate System, which extends
through the heart of the prolific Barnett Shale natural gas play of North
Texas. The completion of the Sherman Extension adds 1.1 Bcf/d of
incremental natural gas takeaway capacity from the region, while providing
producers in the Barnett Shale, and as far away as the Waha area of West Texas,
with greater flexibility to reach the most attractive natural gas
markets. The Texas Intrastate System is part of our Onshore Natural
Gas Pipelines & Services business segment.
Initially, the Sherman Extension was in
very limited service due to pipeline integrity issues on the connecting third
party take-away pipeline, the Gulf Crossing Pipeline owned by Boardwalk Pipeline
Partners, LP (“Boardwalk”). The Gulf Crossing Pipeline began ramping
up its operations on August 1, 2009. As a result, the Sherman
Extension started billing its demand charges at 95% of contracted volumes, which
are 950 MMcf/d. Effective September 1, 2009, the Sherman Extension
started billing demand charges at 100% of contracted volumes irrespective of
actual transportation volumes. We are currently flowing approximately
700 MMcf/d. The demand charges are approximately $5.0 million a
month.
Review
of Consolidated Results
We have
four reportable business segments: NGL Pipelines & Services, Onshore Natural
Gas Pipelines & Services, Offshore Pipelines & Services and
Petrochemical Services. Our business segments are generally organized
and managed according to the type of services rendered (or technologies
employed) and products produced and/or sold. For additional
information regarding our business segments, see Note 11 of the Notes to
Unaudited Condensed Consolidated Financial Statements included under Item 1 of
this Quarterly Report.
Selected
Price and Volumetric Data
The
following table illustrates selected annual and quarterly industry index prices
for natural gas, crude oil and selected NGL and petrochemical products for the
periods presented:
|
|
|
|
|
|
|
|
Polymer
|
Refinery
|
|
Natural
|
|
|
|
Normal
|
|
Natural
|
Grade
|
Grade
|
|
Gas,
|
Crude
Oil,
|
Ethane,
|
Propane,
|
Butane,
|
Isobutane,
|
Gasoline,
|
Propylene,
|
Propylene,
|
|
$/MMBtus
|
$/barrel
|
$/gallon
|
$/gallon
|
$/gallon
|
$/gallon
|
$/gallon
|
$/pound
|
$/pound
|
|
(1)
|
(2)
|
(1)
|
(1)
|
(1)
|
(1)
|
(1)
|
(1)
|
(1)
|
2008
|
|
|
|
|
|
|
|
|
|
1st
Quarter
|
$8.03
|
$97.91
|
$1.01
|
$1.47
|
$1.80
|
$1.87
|
$2.12
|
$0.61
|
$0.54
|
2nd
Quarter
|
$10.94
|
$123.88
|
$1.05
|
$1.70
|
$2.05
|
$2.08
|
$2.64
|
$0.70
|
$0.67
|
3rd
Quarter
|
$10.25
|
$118.01
|
$1.09
|
$1.68
|
$1.97
|
$1.99
|
$2.52
|
$0.78
|
$0.66
|
4th
Quarter
|
$6.95
|
$58.32
|
$0.42
|
$0.80
|
$0.90
|
$0.96
|
$1.09
|
$0.37
|
$0.22
|
2008
Averages
|
$9.04
|
$99.53
|
$0.89
|
$1.41
|
$1.68
|
$1.72
|
$2.09
|
$0.62
|
$0.52
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
1st
Quarter
|
$4.91
|
$42.96
|
$0.36
|
$0.68
|
$0.87
|
$0.97
|
$0.96
|
$0.26
|
$0.20
|
2nd
Quarter
|
$3.51
|
$59.54
|
$0.43
|
$0.73
|
$0.93
|
$1.11
|
$1.21
|
$0.34
|
$0.28
|
3rd
Quarter
|
$3.39
|
$68.20
|
$0.47
|
$0.87
|
$1.12
|
$1.19
|
$1.42
|
$0.48
|
$0.43
|
2009
Averages
|
$3.93
|
$56.90
|
$0.42
|
$0.76
|
$0.97
|
$1.09
|
$1.20
|
$0.36
|
$0.30
|
|
|
|
|
|
|
|
|
|
|
(1)
Natural
gas, NGL, polymer grade propylene and refinery grade propylene prices
represent an average of various commercial index prices including Oil
Price Information Service (“OPIS”) and Chemical Market Associates, Inc.
(“CMAI”). Natural gas price is representative of Henry-Hub
I-FERC. NGL prices are representative of Mont Belvieu Non-TET
pricing. Refinery grade propylene represents a weighted-average
of CMAI spot prices. Polymer-grade propylene represents average
CMAI contract pricing.
(2)
Crude
oil price is representative of an index price for West Texas
Intermediate.
|
The
following table presents our material average throughput, production and
processing volumetric data. These statistics are reported on a net
basis, taking into account our ownership interests in certain joint ventures and
reflect the periods in which we owned an interest in such
operations. These statistics include volumes for newly constructed
assets since the dates such assets were placed into service and for recently
purchased assets since the date of acquisition.
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
NGL
Pipelines & Services, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL
transportation volumes (MBPD)
|
|
|
1,981 |
|
|
|
1,758 |
|
|
|
1,905 |
|
|
|
1,788 |
|
NGL
fractionation volumes (MBPD)
|
|
|
453 |
|
|
|
413 |
|
|
|
444 |
|
|
|
424 |
|
Equity
NGL production (MBPD)
|
|
|
116 |
|
|
|
109 |
|
|
|
116 |
|
|
|
108 |
|
Fee-based
natural gas processing (MMcf/d)
|
|
|
2,247 |
|
|
|
2,064 |
|
|
|
2,685 |
|
|
|
2,469 |
|
Onshore
Natural Gas Pipelines & Services, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas transportation volumes (BBtus/d)
|
|
|
8,207 |
|
|
|
7,562 |
|
|
|
8,149 |
|
|
|
7,313 |
|
Offshore
Pipelines & Services, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas transportation volumes (BBtus/d)
|
|
|
1,374 |
|
|
|
1,244 |
|
|
|
1,458 |
|
|
|
1,449 |
|
Crude
oil transportation volumes (MBPD)
|
|
|
369 |
|
|
|
147 |
|
|
|
278 |
|
|
|
190 |
|
Platform
natural gas processing (MMcf/d)
|
|
|
694 |
|
|
|
583 |
|
|
|
741 |
|
|
|
588 |
|
Platform
crude oil processing (MBPD)
|
|
|
17 |
|
|
|
14 |
|
|
|
10 |
|
|
|
19 |
|
Petrochemical
Services, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Butane
isomerization volumes (MBPD)
|
|
|
104 |
|
|
|
71 |
|
|
|
98 |
|
|
|
85 |
|
Propylene
fractionation volumes (MBPD)
|
|
|
67 |
|
|
|
58 |
|
|
|
67 |
|
|
|
67 |
|
Octane
additive production volumes (MBPD)
|
|
|
13 |
|
|
|
8 |
|
|
|
9 |
|
|
|
9 |
|
Petrochemical
transportation volumes (MBPD)
|
|
|
125 |
|
|
|
95 |
|
|
|
114 |
|
|
|
110 |
|
Total,
net:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL,
crude oil and petrochemical transportation volumes (MBPD)
|
|
|
2,475 |
|
|
|
2,000 |
|
|
|
2,297 |
|
|
|
2,088 |
|
Natural
gas transportation volumes (BBtus/d)
|
|
|
9,581 |
|
|
|
8,806 |
|
|
|
9,607 |
|
|
|
8,762 |
|
Equivalent
transportation volumes (MBPD) (1)
|
|
|
4,996 |
|
|
|
4,317 |
|
|
|
4,825 |
|
|
|
4,394 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Reflects
equivalent energy volumes where 3.8 MMBtus of natural gas are equivalent
to one barrel of NGLs.
|
|
Comparison
of Consolidated Results of Operations
The
following table summarizes the key components of our consolidated income
statement for the periods indicated (dollars in millions):
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Revenues
|
|
$ |
4,596.1 |
|
|
$ |
6,297.9 |
|
|
$ |
11,527.1 |
|
|
$ |
18,322.1 |
|
Operating
costs and expenses
|
|
|
4,220.2 |
|
|
|
5,971.9 |
|
|
|
10,395.7 |
|
|
|
17,243.1 |
|
General
and administrative costs
|
|
|
33.9 |
|
|
|
21.8 |
|
|
|
84.7 |
|
|
|
67.0 |
|
Equity
in income of unconsolidated affiliates
|
|
|
22.5 |
|
|
|
14.9 |
|
|
|
18.3 |
|
|
|
48.1 |
|
Operating
income
|
|
|
364.5 |
|
|
|
319.1 |
|
|
|
1,065.0 |
|
|
|
1,060.1 |
|
Interest
expense
|
|
|
128.0 |
|
|
|
102.7 |
|
|
|
374.6 |
|
|
|
290.4 |
|
Provision
for income taxes
|
|
|
6.6 |
|
|
|
6.6 |
|
|
|
24.0 |
|
|
|
17.2 |
|
Net
income
|
|
|
229.9 |
|
|
|
211.0 |
|
|
|
667.3 |
|
|
|
755.3 |
|
Net
income attributable to noncontrolling interest
|
|
|
17.0 |
|
|
|
7.9 |
|
|
|
42.5 |
|
|
|
29.3 |
|
Net
income attributable to Enterprise Products Partners L.P.
|
|
|
212.9 |
|
|
|
203.1 |
|
|
|
624.8 |
|
|
|
726.0 |
|
Effective
January 1, 2009, we adopted new accounting guidance that has been codified under
ASC 810, which established accounting and reporting standards for noncontrolling
interests, which were previously identified as minority interest in our
financial statements. The new guidance requires, among other things,
that (i) noncontrolling interests be presented as a component of equity on our
consolidated balance sheet (i.e., elimination of the “mezzanine” presentation
previously used for minority interest); (ii) minority interest amounts be
eliminated as a deduction in deriving net income or loss and, as a result, that
net income or loss be allocated between controlling and noncontrolling
interests; and (iii) comprehensive income or loss to be allocated between
controlling and noncontrolling interest. Earnings per unit
amounts are not affected by these changes. See Note 2 of the Notes to
Unaudited Condensed Consolidated Financial
Statements
included under Item 1 of this Quarterly Report for additional information
regarding the establishment of the ASC by the Financial Accounting Standards
Board (“FASB”). See Note 10 of the Notes to Unaudited Condensed
Consolidated Financial Statements included under Item 1 of this Quarterly Report
for additional information regarding noncontrolling interest.
The new presentation and disclosure
requirements pertaining to noncontrolling interests have been applied
retroactively to the consolidated financial statements and notes included in
this Quarterly Report. As a result, net income reported for the three
and nine months ended September 30, 2008 in these financial statements is higher
than that disclosed previously; however, the allocation of such net income
results in our unitholders, general partner and noncontrolling interests (i.e.,
the former minority interest) receiving the same amounts as they did
previously.
We
evaluate segment performance based on the non-GAAP financial measure of gross
operating margin. Gross operating margin (either in total or by
individual segment) is an important performance measure of the core
profitability of our operations. This measure forms the basis of our
internal financial reporting and is used by management in deciding how to
allocate capital resources among business segments. We believe that
investors benefit from having access to the same financial measures that our
management uses in evaluating segment results. The GAAP financial
measure most directly comparable to total segment gross operating margin is
operating income. Our non-GAAP financial measure of total segment
gross operating margin should not be considered as an alternative to GAAP
operating income.
Our consolidated gross operating margin
amounts include the gross operating margin amounts of Duncan Energy Partners on
a 100% basis. Volumetric data associated with the operations of
Duncan Energy Partners are also included on a 100% basis in our consolidated
statistical data.
Our gross
operating margin by segment and in total is as follows for the periods indicated
(dollars in millions):
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Gross
operating margin by segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL
Pipelines & Services
|
|
$ |
392.0 |
|
|
$ |
336.1 |
|
|
$ |
1,088.8 |
|
|
$ |
943.5 |
|
Onshore
Natural Gas Pipelines & Services
|
|
|
62.3 |
|
|
|
88.1 |
|
|
|
252.6 |
|
|
|
321.2 |
|
Offshore
Pipeline & Services
|
|
|
56.3 |
|
|
|
17.5 |
|
|
|
150.7 |
|
|
|
134.4 |
|
Petrochemical
Services
|
|
|
50.3 |
|
|
|
37.2 |
|
|
|
126.7 |
|
|
|
136.4 |
|
Total
segment gross operating margin
|
|
$ |
560.9 |
|
|
$ |
478.9 |
|
|
$ |
1,618.8 |
|
|
$ |
1,535.5 |
|
For a
reconciliation of non-GAAP gross operating margin to GAAP operating income and
income before provision for income taxes, see “Other Items – Non-GAAP
Reconciliations” included within this Item 2.
The
following table summarizes the contribution to revenues from each business
segment (including the effects of eliminations and adjustments) during the
periods indicated (dollars in millions):
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
NGL
Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
of NGLs
|
|
$ |
3,054.9 |
|
|
$ |
4,257.8 |
|
|
$ |
7,623.0 |
|
|
$ |
12,514.6 |
|
Sales
of other petroleum and related products
|
|
|
0.6 |
|
|
|
0.5 |
|
|
|
1.5 |
|
|
|
1.9 |
|
Midstream
services
|
|
|
160.4 |
|
|
|
170.7 |
|
|
|
448.5 |
|
|
|
528.9 |
|
Total
|
|
|
3,215.9 |
|
|
|
4,429.0 |
|
|
|
8,073.0 |
|
|
|
13,045.4 |
|
Onshore
Natural Gas Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
of natural gas
|
|
|
585.7 |
|
|
|
859.2 |
|
|
|
1,645.3 |
|
|
|
2,400.4 |
|
Midstream
services
|
|
|
113.3 |
|
|
|
118.6 |
|
|
|
326.6 |
|
|
|
370.5 |
|
Total
|
|
|
699.0 |
|
|
|
977.8 |
|
|
|
1,971.9 |
|
|
|
2,770.9 |
|
Offshore
Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
of natural gas
|
|
|
0.3 |
|
|
|
0.9 |
|
|
|
0.9 |
|
|
|
2.5 |
|
Sales
of other petroleum and related products
|
|
|
2.0 |
|
|
|
3.7 |
|
|
|
3.1 |
|
|
|
10.8 |
|
Midstream
services
|
|
|
99.4 |
|
|
|
60.4 |
|
|
|
243.5 |
|
|
|
191.9 |
|
Total
|
|
|
101.7 |
|
|
|
65.0 |
|
|
|
247.5 |
|
|
|
205.2 |
|
Petrochemical
Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
of other petroleum and related products
|
|
|
558.8 |
|
|
|
803.4 |
|
|
|
1,165.3 |
|
|
|
2,233.7 |
|
Midstream
services
|
|
|
20.7 |
|
|
|
22.7 |
|
|
|
69.4 |
|
|
|
66.9 |
|
Total
|
|
|
579.5 |
|
|
|
826.1 |
|
|
|
1,234.7 |
|
|
|
2,300.6 |
|
Total
consolidated revenues
|
|
$ |
4,596.1 |
|
|
$ |
6,297.9 |
|
|
$ |
11,527.1 |
|
|
$ |
18,322.1 |
|
Comparison
of Three Months Ended September 30, 2009 with
Three
Months Ended September 30, 2008
Revenues
for the third quarter of 2009 were $4.60 billion compared to $6.30 billion for
the third quarter of 2008. The $1.70 billion quarter-to-quarter
decrease in consolidated revenues is primarily due to lower energy commodity
sales prices associated with our NGL, natural gas and petrochemical marketing
activities during the third quarter of 2009 relative to the third quarter of
2008. Consolidated revenues for the third quarter of 2009 include
$19.2 million of cash proceeds from business interruption insurance due to the
effects of Hurricane Ike on our operations.
Operating
costs and expenses were $4.22 billion for the third quarter of 2009 versus $5.97
billion for the third quarter of 2008, a $1.75 billion quarter-to-quarter
decrease. The cost of sales of our marketing activities decreased
$1.46 billion quarter-to-quarter primarily due to lower energy commodity
prices. Likewise, the operating costs and expenses of our natural gas
processing plants decreased $315.1 million quarter-to-quarter primarily due to
lower plant thermal reduction (i.e., PTR) costs attributable to the decline in
energy commodity prices. Consolidated operating costs and expenses
for the third quarter of 2009 include $33.5 million of expenses related to the
settlement of litigation involving TOPS. General and administrative
costs increased $12.1 million quarter-to-quarter primarily due to expenses we
incurred during the third quarter of 2009 related to the TEPPCO
Merger.
Changes
in our revenues and costs and expenses quarter-to-quarter are primarily
explained by fluctuations in energy commodity prices. The
weighted-average indicative market price for NGLs was $0.88 per gallon during
the third quarter of 2009 versus $1.68 per gallon during the third quarter of
2008 – a 48% decrease quarter-to-quarter. Our determination of the
weighted-average indicative market price for NGLs is based on U.S. Gulf Coast
prices for such products at Mont Belvieu, Texas, which is the primary industry
hub for domestic NGL production. The market price of natural gas (as
measured at Henry Hub in Louisiana) decreased 67% quarter-to-quarter to an
average of $3.39 per MMBtus during the third quarter of 2009 versus $10.25 per
MMBtus during the third quarter of 2008. See “Results of Operations -
Selected Price and Volumetric Data” within this Item 2 for additional historical
energy commodity pricing information.
Equity in
income from our unconsolidated affiliates was $22.5 million for the third
quarter of 2009 compared to $14.9 million for the third quarter of 2008, a $7.6
million quarter-to-quarter increase. Collectively, equity in
income from our investments in Cameron Highway Oil Pipeline Company (“Cameron
Highway”) and Poseidon Oil Pipeline, L.L.C. (“Poseidon”) increased $8.7 million
quarter-to-quarter due to higher transportation volumes during the third quarter
of 2009 relative to the third quarter of 2008. Our investments in
White River Hub, LLC (“White River Hub”) and Skelly-Belvieu Pipeline Company,
L.L.C. (“Skelly-Belvieu”) contributed equity in income of $0.9 million and $0.3
million, respectively, for the third quarter of 2009. The assets
owned by White River Hub began commercial operations in December
2008. We acquired a 49% equity interest in Skelly-Belvieu during
December 2008. Equity in income decreased $3.2 million
quarter-to-quarter from our Marco Polo platform due to the expiration of demand
fee revenues during March 2009. The Marco Polo platform is owned
through our investment in Deepwater Gateway, L.L.C. (“Deepwater
Gateway”). Collectively, equity in income from our other equity
investments increased $1.0 million quarter-to-quarter.
Operating
income for the third quarter of 2009 was $364.5 million compared to $319.1
million for the third quarter of 2008. Consolidated revenues and
certain operating costs and expenses (e.g., cost of sales amounts) can fluctuate
significantly due to changes in energy commodity prices without necessarily
affecting our operating income to the same degree. Consequently, the
aforementioned changes in revenues, costs and expenses and equity in income of
unconsolidated affiliates contributed to the $45.4 million quarter-to-quarter
increase in operating income.
Interest
expense increased to $128.0 million for the third quarter of 2009 from $102.7
million for the third quarter of 2008. The $25.3 million
quarter-to-quarter increase in interest expense is primarily due to our issuance
of Senior Notes O in the fourth quarter of 2008, Senior Notes P in the second
quarter of 2009 and a $10.7 million decrease in capitalized interest during the
third quarter of 2009 relative to the third quarter of 2008. Average
debt principal outstanding increased during the third quarter of 2009 to $9.44
billion from $8.14 billion during the third quarter of 2008 primarily due to
debt incurred to fund growth capital projects.
As a
result of items noted in the previous paragraphs, net income increased $18.9
million quarter-to-quarter to $229.9 million for the third quarter of 2009
compared to $211.0 million for the third quarter of 2008. Net income
attributable to noncontrolling interests was $17.0 million for the third quarter
of 2009 compared to $7.9 million for the third quarter of 2008. Net
income attributable to Enterprise Products Partners increased $9.8 million
quarter-to-quarter to $212.9 million for the third quarter of 2009 compared to
$203.1 million for the third quarter of 2008.
In
general, Hurricanes Gustav and Ike had an adverse effect on our operations in
the Gulf of Mexico and onshore along the U.S. Gulf Coast during the third
quarter of 2008. Storm-related disruptions in natural gas, NGL and
crude oil production in these regions resulted in reduced volumes available to
our pipeline systems, natural gas processing plants, NGL fractionators and
offshore platforms, which in turn caused a decrease in gross operating margin
for certain operations. In addition, property damage caused by these
hurricanes resulted in lower revenues due to facility downtime as well as higher
operating costs and expenses at certain of our plants and
pipelines. As a result of insurance deductibles for windstorm damage,
gross operating margin for the third quarter of 2008 includes $46.0 million of
repair expenses for property damage sustained by our assets as a result of
Hurricanes Gustav and Ike. Gross operating margin for the third
quarter of 2009 includes $19.2 million of proceeds from business interruption
insurance due to the effects of Hurricane Ike on our operations. For
more information regarding our insurance program and claims related to these
storms, see “Other Items – Insurance Matters” included within this Item
2.
The
following information highlights significant quarter-to-quarter variances in
gross operating margin by business segment:
NGL
Pipelines & Services. Gross operating margin from this business
segment was $392.0 million for the third quarter of 2009 compared to $336.1
million for the third quarter of 2008, a $55.9 million quarter-to-quarter
increase. In general, this business segment benefited from a
quarter-to-quarter
increase
in NGL transportation and fractionation volumes, improved results from our NGL
marketing activities and lower fuel costs during the third quarter of 2009
compared to the third quarter of 2008. The third quarter of 2009
includes $1.2 million of cash proceeds from business interruption insurance
claims. The following paragraphs provide a discussion of segment
results excluding cash proceeds from business interruption insurance
claims.
Gross
operating margin from our natural gas processing and related NGL marketing
business was $238.0 million for the third quarter of 2009 compared to $237.6
million for the third quarter of 2008. Equity NGL production
increased to 116 MBPD during the third quarter of 2009 from 109 MBPD during the
third quarter of 2008. Gross operating margin from our NGL marketing
activities increased $16.5 million quarter-to-quarter due to higher NGL sales
margins and volumes during the third quarter of 2009 relative to the third
quarter of 2008. Gross operating margin from our South Louisiana
natural gas processing plants increased $8.1 million
quarter-to-quarter. These facilities were negatively impacted by
downtime and property damage repair expenses caused by Hurricanes Gustav and Ike
during the third quarter of 2008. Collectively, gross operating
margin from the remainder of our natural gas processing plants decreased $24.2
million quarter-to-quarter primarily due to lower processing margins in South
Texas, the Permian Basin and Rocky Mountains.
Gross
operating margin from our NGL pipelines and related storage business was $121.7
million for the third quarter of 2009 compared to $72.6 million for the third
quarter of 2008, a $49.1 million quarter-to-quarter increase. Gross
operating margin from our Mid-America and Seminole pipeline systems increased
$24.9 million quarter-to-quarter due to higher volumes and lower fuel
costs. Collectively, gross operating margin from the remainder of our
NGL pipelines, export dock and storage assets increased $24.2 million
quarter-to-quarter largely due to increased storage volumes and fees at our Mont
Belvieu storage complex, improved results from our assets in South Louisiana and
lower fuel costs during the third quarter of 2009. Total NGL
transportation volumes increased to 1,981 MBPD during the third quarter of 2009
from 1,758 MBPD during the third quarter of 2008.
Gross
operating margin from our NGL fractionation business was $31.1 million for the
third quarter of 2009 compared to $25.9 million for the third quarter of
2008. Fractionation volumes increased to 453 MBPD during the third
quarter of 2009 from 413 MBPD during the third quarter of 2008. The
$5.2 million quarter-to-quarter increase in gross operating margin from this
business is primarily due to increased fractionation volumes at our Mont
Belvieu, Norco and Promix fractionators and lower fuel costs during the third
quarter of 2009 relative to the third quarter of 2008.
Onshore
Natural Gas Pipelines & Services. Gross operating margin
from this business segment was $62.3 million for the third quarter of 2009
compared to $88.1 million for the third quarter of 2008, a $25.8 million
quarter-to-quarter decrease. Our onshore natural gas transportation
volumes were 8,207 BBtus/d during the third quarter of 2009 compared to 7,562
BBtus/d during the third quarter of 2008.
Gross
operating margin from our onshore natural gas pipelines and related natural gas
marketing business was $48.8 million for the third quarter of 2009 compared to
$77.4 million for the third quarter of 2008, a $28.6 million quarter-to-quarter
decrease. The Sherman Extension pipeline segment of our Texas
Intrastate System began commercial operations on August 1, 2009 and contributed
$9.0 million of gross operating margin during the third quarter of 2009,
primarily from firm capacity fee revenues. Gross operating margin
from our San Juan gathering system decreased $27.0 million quarter-to-quarter
primarily due to lower commodity prices, which resulted in reduced revenues
earned from natural gas gathering contracts where fees are indexed to regional
natural gas prices and lower condensate sales revenues. Collectively,
gross operating margin from the remainder of the businesses classified within
this segment decreased $10.6 million quarter-to-quarter largely due to a
decrease in natural gas transportation volumes and condensate sales revenues,
both of which relate primarily to our Texas operations, during the third quarter
of 2009 compared to the third quarter of 2008.
Gross
operating margin from our natural gas storage business was $13.5 million for the
third quarter of 2009 compared to $10.7 million for the third quarter of
2008. The $2.8 million quarter-to-
quarter increase in
gross operating margin is primarily due to increased storage activity at our
Petal and Wilson natural gas storage
facilities.
Offshore
Pipelines & Services. Gross operating margin from this
business segment was $56.3 million for the third quarter of 2009 compared to
$17.5 million for the third quarter of 2008. Results from this
business segment for the third quarter of 2009 include $18.0 million of cash
proceeds from business interruption insurance claims and $33.5 million of
expenses for the TOPS litigation settlement. Results for the third
quarter of 2008 were negatively impacted by downtime, reduced volumes and $35.5
million of property damage repair expenses resulting from Hurricanes Gustav and
Ike. The following paragraphs provide a discussion of segment results
excluding the effect of cash proceeds from business interruption insurance
claims.
Gross
operating margin from our offshore natural gas pipeline business was $8.7
million for the third quarter of 2009 compared to a loss of $22.8 million for
the third quarter of 2008. The $31.5 million quarter-to-quarter
increase in gross operating margin is primarily due to the impact of Hurricanes
Gustav and Ike on this business during the third quarter of 2008, which includes
$32.1 million of hurricane-related property damage repair
expenses. Gross operating margin from our Independence Trail pipeline
increased $6.3 million quarter-to-quarter due to higher transportation
volumes. Collectively, gross operating margin from our other offshore
natural gas pipelines decreased $6.9 million quarter-to-quarter primarily due to
higher maintenance and repair expenses during the third quarter of 2009
associated with our Anaconda and HIOS pipeline systems. Offshore
natural gas transportation volumes were 1,374 BBtus/d during the third quarter
of 2009 compared to 1,244 BBtus/d during the third quarter of 2008.
Gross
operating margin from our offshore crude oil pipeline business was a loss of
$5.6 million for the third quarter of 2009 compared to earnings of $5.7 million
for the third quarter of 2008, an $11.3 million quarter-to-quarter
decrease. Excluding the $33.5 million of expenses we recorded during
the third quarter of 2009 as a result of the TOPS litigation settlement, gross
operating margin from this business increased $22.2 million
quarter-to-quarter.
We
completed the Shenzi crude oil pipeline and began commercial operation during
April 2009. Collectively, gross operating margin from our crude oil
pipelines increased $22.2 million quarter-to-quarter primarily due to the
start-up of our Shenzi crude oil pipeline and higher transportation volumes on
Cameron Highway and Poseidon crude oil pipelines, which were both impacted by
last year’s hurricanes. Offshore crude oil transportation volumes
were 369 MBPD during the third quarter of 2009 versus 147 MBPD during the third
quarter of 2008.
Gross
operating margin from our offshore platform services business was $35.2 million
for the third quarter of 2009 compared to $34.6 million for the third quarter of
2008, a $0.6 million quarter-to-quarter increase. Gross operating
margin from our Independence Hub platform increased $3.1 million
quarter-to-quarter due to higher natural gas processing volumes during the third
quarter of 2009 relative to the third quarter of 2008. Collectively,
gross operating margin from our other offshore platforms decreased $2.5 million
quarter-to-quarter primarily due to the expiration of demand fee revenues at our
Marco Polo platform in March 2009. Our net platform natural gas
processing volumes increased to 694 MMcf/d during the third quarter of 2009 from
583 MMcf/d during the third quarter of 2008. Our net platform crude
oil processing volumes increased to 17 MBPD during the third quarter of 2009
compared to 14 MBPD during the third quarter of 2008.
Petrochemical
Services. Gross operating margin from this business segment
was $50.3 million for the third quarter of 2009 compared to $37.2 million for
the third quarter of 2008. Gross operating margin from our octane
enhancement business was $5.2 million for the third quarter of 2009 compared to
a loss of $12.9 million for the third quarter of 2008. The $18.1
million quarter-to-quarter increase in gross operating margin is due to higher
volumes and lower operating expenses in the third quarter of 2009 compared to
the third quarter of 2008. During the third quarter of 2008, in
addition to downtime associated with Hurricane Ike, the octane enhancement
facility had operational issues that resulted in higher operating expenses,
downtime and decreased production volumes. Octane enhancement
production volumes increased to 13 MBPD during the third quarter of 2009 from 8
MBPD during the third quarter of 2008.
Gross
operating margin from our propylene fractionation and pipeline business was
$22.6 million for the third quarter of 2009 compared to $31.0 million for the
third quarter of 2008. The $8.4 million quarter-to-quarter decrease
in gross operating margin is due to lower propylene sales margins, which more
than offset the benefit of increased propylene fractionation
volumes. Propylene fractionation volumes increased to 67 MBPD during
the third quarter of 2009 from 58 MBPD during the third quarter of 2008. Gross
operating margin from our butane isomerization business was $22.5 million for
the third quarter of 2009 compared to $19.1 million for the third quarter of
2008. The $3.4 million quarter-to-quarter increase in gross operating
margin from this business is attributable to increased isomerization volumes,
partially offset by lower by-product revenues. Butane isomerization
volumes increased to 104 MBPD during the third quarter of 2009 from 71 MBPD
during the third quarter of 2008.
Comparison
of Nine Months Ended September 30, 2009 with
Nine
Months Ended September 30, 2008
Revenues
for the first nine months of 2009 were $11.53 billion compared to $18.32 billion
for the first nine months of 2008. The $6.79 billion period-to-period
decrease in consolidated revenues is primarily due to lower energy commodity
sales prices associated with our NGL, natural gas and petrochemical marketing
activities during the first nine months of 2009 compared to the first nine
months of 2008.
Operating
costs and expenses were $10.40 billion for the first nine months of 2009
compared to $17.24 billion for the first nine months of 2008, a $6.84 billion
period-to-period decrease. The cost of sales of our marketing
activities decreased $5.78 billion period-to-period primarily due to lower
energy commodity prices. Likewise, the operating costs and expenses
of our natural gas processing plants decreased $979.7 million period-to-period
primarily due to lower PTR costs attributable to the decline in energy commodity
prices. Consolidated operating costs and expenses for the first nine
months of 2009 include $33.5 million of expenses related to the settlement of
litigation involving TOPS. General and administrative costs increased
$17.7 million period-to-period primarily due to expenses we incurred during the
first nine months of 2009 in connection with the TEPPCO Merger.
Changes
in our revenues and costs and expenses period-to-period are primarily explained
by fluctuations in energy commodity prices. The weighted-average
indicative market price for NGLs was $0.77 per gallon during the first nine
months of 2009 versus $1.62 per gallon during the first nine months of 2008 – a
52% decrease period-to-period. The Henry Hub market price of natural
gas decreased 60% period-to-period to an average of $3.93 per MMBtus during the
first nine months of 2009 versus $9.74 per MMBtus during the first nine months
of 2008.
Equity in
income from our unconsolidated affiliates was $18.3 million for the first nine
months of 2009 compared to $48.1 million for the first nine months of 2008, a
$29.8 million period-to-period decrease. Equity in income of
unconsolidated affiliates for the first nine months of 2009 includes a $34.2
million non-cash charge to record the forfeiture of our investment in
TOPS. Our investments in White River Hub and Skelly-Belvieu
contributed equity in income of $2.9 million and $1.4 million, respectively, for
the first nine months of 2009. Collectively, equity in loss of
unconsolidated affiliates from our other equity investments increased $0.2
million period-to-period.
Operating
income for the first nine months of 2009 was $1.07 billion compared to $1.06
billion for the first nine months of 2008. Consolidated revenues and
certain operating costs and expenses can fluctuate significantly due to changes
in energy commodity prices without necessarily affecting our operating income to
the same degree. Consequently, the aforementioned changes in
revenues, costs and expenses and equity in income of unconsolidated affiliates
contributed to the $4.9 million period-to-period increase in operating
income.
Interest
expense increased to $374.6 million for the first nine months of 2009 from
$290.4 million for the first nine months of 2008. The $84.2 million
period-to-period increase in interest expense is primarily due to our issuance
of Senior Notes M and N in the second quarter of 2008, Senior Notes O in the
fourth quarter of 2008 and a $28.7 million decrease in capitalized interest
during the first nine months of
2009
relative to the first nine months of 2008. Average debt principal
outstanding increased during the first nine months of 2009 to $9.34 billion from
$7.65 billion during the first nine months of 2008 primarily due to debt
incurred to fund growth capital investments. Provision for income
taxes increased $6.8 million period-to-period primarily due to a one-time charge
of $6.6 million associated with taxable gains arising from Dixie Pipeline
Company’s (“Dixie”) sale of certain assets during the first nine months of
2009.
As a
result of items noted in the previous paragraphs, net income decreased $88.0
million period-to-period to $667.3 million for the first nine months of 2009
compared to $755.3 million for the first nine months of 2008. Net
income attributable to noncontrolling interests was $42.5 million for 2009
compared to $29.3 million for 2008. Net income attributable to
Enterprise Products Partners decreased $101.2 million period-to-period to $624.8
million for the first nine months of 2009 compared to $726.0 million for the
first nine months of 2008.
The
following information highlights significant period-to-period variances in gross
operating margin by business segment:
NGL
Pipelines & Services. Gross operating margin from this business
segment was $1.09 billion for the first nine months of 2009 compared to $943.4
million for the first nine months of 2008, a $145.3 million period-to-period
increase. In general, this business segment benefited from a
period-to-period increase in gross operating margin from our recently
constructed Rocky Mountain natural gas processing plants and related hedging
program, improved results from our NGL marketing activities and lower fuel costs
during the first nine months of 2009 compared to the first nine months of 2008.
The first nine months of 2009 include $1.2 million of proceeds from business
interruption insurance claims compared to $1.1 million of proceeds during the
first nine months of 2008. The following paragraphs provide a
discussion of segment results excluding the effect of cash proceeds from
business interruption insurance.
Gross
operating margin from our natural gas processing and related NGL marketing
business was $652.0 million for the first nine months of 2009 compared to $611.8
million for the first nine months of 2008. Equity NGL production
increased to 116 MBPD during the first nine months of 2009 from 108 MBPD during
the first nine months of 2008. The $40.2 million period-to-period
increase in gross operating margin from this business is attributable to our
Rocky Mountain natural gas processing facilities and related hedging program and
our NGL marketing activities, which benefited from higher sales margins and
increased equity NGL production.
Gross
operating margin from our NGL pipelines and related storage business was $339.4
million for the first nine months of 2009 compared to $252.8 million for the
first nine months of 2008, an $86.6 million period-to-period
increase. Total NGL transportation volumes increased to 1,905 MBPD
during the first nine months of 2009 from 1,788 MBPD during the first nine
months of 2008. Gross operating margin from our Mid-America and
Seminole Pipeline Systems increased $33.6 million period-to-period due to
increased volumes and lower fuel costs. Gross operating margin from
our Mont Belvieu storage complex increased $13.4 million period-to-period
primarily due to higher volumes and fees. Collectively, gross
operating margin from the remainder of our NGL pipelines, export dock and
related storage assets increased $39.6 million period-to-period largely due to
lower fuel costs and higher volumes and fees at certain of our South Louisiana
assets during the first nine months of 2009 relative to the first nine months of
2008.
Gross
operating margin from our NGL fractionation business was $96.2 million for the
first nine months of 2009 compared to $77.7 million for the first nine months of
2008. Fractionation volumes increased to 444 MBPD during the first
nine months of 2009 from 424 MBPD during the first nine months of
2008. Gross operating margin from this business increased $18.5
million period-to-period largely due to higher NGL fractionation volumes at our
Mont Belvieu and Baton Rouge fractionators and lower fuel costs during the first
nine months of 2009 relative to the first nine months of 2008.
Onshore
Natural Gas Pipelines & Services. Gross operating margin
from this business segment was $252.6 million for the first nine months of 2009
compared to $321.2 million for the first nine months of 2008, a $68.6 million
period-to-period decrease. Our onshore natural gas transportation
volumes were
8,149
BBtus/d during the first nine months of 2009 compared to 7,313 BBtus/d during
the first nine months of 2008.
Gross
operating margin from our onshore natural gas pipeline and related natural gas
marketing business was $213.7 million for the first nine months of 2009 compared
to $292.2 million for the first nine months of 2008, a $78.5 million
period-to-period decrease. The Sherman Extension pipeline segment of
our Texas Intrastate System began commercial operations on August 1, 2009 and
contributed $9.0 million of gross operating margin during 2009, primarily from
firm capacity fee revenues. Gross operating margin from our San Juan
gathering system decreased $88.6 million period-to-period due to lower fees
indexed to regional natural gas prices and condensate sales revenues as a result
of the period-to-period decrease in commodity prices. Lower natural
gas gathering volumes in the Permian Basin resulted in a $9.2 million
period-to-period decrease in gross operating margin on our Carlsbad gathering
system. Gross operating margin from our Acadian Gas System decreased
$4.3 million period-to-period due to lower natural gas sales volumes and
margins. Collectively, gross operating margin from the remainder of
the businesses classified within this segment increased $14.6 million
period-to-period attributable to increased natural gas sales volumes and
improved asset utilization as a result of our natural gas marketing activities,
partially offset by a decrease in condensate sales revenues.
Gross
operating margin from our natural gas storage business was $38.9 million for the
first nine months of 2009 compared to $29.0 million for the first nine months of
2008. The $9.9 million period-to-period increase in gross operating
margin is primarily due to increased storage activity at our Petal and Wilson
natural gas storage facilities.
Offshore
Pipelines & Services. Gross operating margin from this
business segment was $150.7 million for the first nine months of 2009 compared
to $134.4 million for the first nine months of 2008, a $16.3 million
period-to-period increase. Results for the first nine months of 2009
include $18.0 million of cash proceeds from business interruption insurance
claims and $67.7 million of total charges associated with the settlement of
TOPS-related litigation and the forfeiture of our investment in
TOPS. Results for the first nine months of 2008 include $0.2 million
of proceeds from business interruption insurance claims and $35.5 million of
property damage repair expenses resulting from Hurricanes Gustav and
Ike. Combined gross operating margin from our Independence Hub
platform and Trail pipeline increased $55.1 million period-to-period reflecting
downtime and repair expenses incurred during the first nine months of
2008. The following paragraphs provide a discussion of segment
results excluding cash proceeds from business interruption
insurance.
Gross
operating margin from our offshore natural gas pipeline business was $43.1
million for the first nine months of 2009 compared to a loss of $8.3 million for
the first nine months of 2008, a $51.4 million period-to-period
increase. Offshore natural gas transportation volumes were 1,458
BBtus/d during the first nine months of 2009 versus 1,449 BBtus/d during the
first nine months of 2008. Gross operating margin from our
Independence Trail pipeline increased $37.4 million
period-to-period. Collectively, gross operating margin from our other
offshore natural gas pipelines increased $14.0 million period-to-period
primarily due to hurricane-related property damage repair expenses recorded
during the first nine months of 2008.
Gross
operating margin from our offshore crude oil pipeline business was a loss of
$20.3 million for the first nine months of 2009 compared to earnings of $32.7
million for the first nine months of 2008, a $53.0 million period-to-period
decrease. Results for the first nine months of 2009 include total
charges of $67.7 million associated with the settlement of TOPS-related
litigation and the forfeiture of our investment in TOPS. In addition,
gross operating margin decreased $3.3 million period-to-period primarily due to
the lingering effects Hurricanes Gustav and Ike had on our assets during the
first nine months of 2009. Gross operating margin from our offshore
crude oil pipelines increased $18.0 million period-to-period due to higher
transportation volumes on our Shenzi, Cameron Highway and Poseidon crude oil
pipelines. Total offshore crude oil transportation volumes were 278
MBPD during the first nine months of 2009 versus 190 MBPD during the first nine
months of 2008.
Gross
operating margin from our offshore platform services business was $109.9 million
for the first nine months of 2009 compared to $109.8 million for the first nine
months of 2008, a $0.1 million period-to-period increase. Gross
operating margin from our Independence Hub platform increased $17.7 million
period-to-period. Collectively, gross operating margin from our other
offshore platforms and related assets decreased $17.6 million period-to-period
primarily due to lower natural gas and crude oil processing volumes at our Marco
Polo platform as a result of continuing hurricane-related disruptions and the
expiration of demand fee revenues at our Marco Polo and Falcon
platforms. Our net platform natural gas processing volumes increased
to 741 MMcf/d during the first nine months of 2009 compared to 588 MMcf/d during
the first nine months of 2008. Our net platform crude oil processing
volumes decreased to 10 MBPD during the first nine months of 2009 compared to 19
MBPD during the first nine months of 2008.
Petrochemical
Services. Gross operating margin from this business segment
was $126.7 million for the first nine months of 2009 compared to $136.4 million
for the first nine months of 2008. Gross operating margin from our
butane isomerization business was $56.5 million for the first nine months of
2009 compared to $77.9 million for the first nine months of 2008. The
$21.4 million period-to-period decrease in gross operating margin from this
business is primarily due to lower proceeds from the sale of plant by-products
as a result of lower commodity prices. Butane isomerization volumes
increased to 98 MBPD during the first nine months of 2009 from 85 MBPD during
the first nine months of 2008.
Gross
operating margin from our octane enhancement business was $4.1 million for the
first nine months of 2009 compared to a loss of $5.8 million for the first nine
months of 2008. The $9.9 million period-to-period increase in gross
operating margin is due to lower operating expenses during the first nine months
of 2009 compared to the first nine months of 2008. During the third
quarter of 2008, in addition to downtime associated with Hurricane Ike, the
octane enhancement facility had operational issues that resulted in higher
operating expenses, downtime and decreased production volumes. Gross
operating margin from our propylene fractionation and pipeline business was
$66.1 million for the first nine months of 2009 compared to $64.3 million for
the first nine months of 2008. The $1.8 million period-to-period
increase in gross operating margin is largely due to higher propylene sales
volumes during the first nine months of 2009 relative to the first nine months
of 2008. Propylene fractionation volumes increased to 67 MBPD during
the first nine months of 2009 from 59 MBPD during the first nine months of
2008.
Liquidity
and Capital Resources
Our
primary cash requirements, in addition to normal operating expenses and debt
service, are for working capital, capital expenditures, business acquisitions
and distributions to partners. We expect to fund our short-term needs
for such items as operating expenses and sustaining capital expenditures with
operating cash flows and revolving credit arrangements. Capital
expenditures for long-term needs resulting from business expansion projects and
acquisitions are expected to be funded by a variety of sources (either
separately or in combination) including operating cash flows, borrowings under
credit facilities, the issuance of additional equity and debt securities and
proceeds from divestitures of ownership interests in assets to affiliates or
third parties. We expect to fund cash distributions to partners
primarily with operating cash flows. Our debt service requirements
are expected to be funded by operating cash flows and/or refinancing
arrangements.
At
September 30, 2009, we had $73.8 million of unrestricted cash on hand and
approximately $1.09 billion of available credit under EPO’s Multi-Year Revolving
Credit Facility. We had approximately $9.15 billion in principal
outstanding under consolidated debt agreements at September 30,
2009. In total, our consolidated liquidity at September 30, 2009 was
approximately $1.31 billion, which includes the available borrowing capacity of
our consolidated subsidiaries such as Duncan Energy Partners.
Registration
Statements
We have a
universal shelf registration statement on file with the SEC that allows us to
issue an unlimited amount of debt and equity securities for general partnership
purposes. In January 2009, we issued 10,590,000 common units
(including an over-allotment of 990,000 common units) to the public at an
offering price of $22.20 per unit under this registration
statement. We used the net proceeds of $225.6 million from the
January 2009 equity offering to temporarily reduce borrowings outstanding under
EPO’s Multi-Year Revolving Credit Facility and for general partnership
purposes. In June 2009, EPO issued $500.0 million in principal amount
of Senior Notes P under this registration statement. Net proceeds
from this senior note offering were used to repay the $200.0 Million Term Loan,
to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving
Credit Facility and for general partnership purposes.
In
September 2009, we issued 8,337,500 common units (including an over-allotment of
1,087,500 common units) to the public at an offering price of $28.00 per unit
under this registration statement. We used the net proceeds of $226.4
million from the September 2009 equity offering to temporarily reduce borrowings
outstanding under EPO’s Multi-Year Revolving Credit Facility and for general
partnership purposes. In October 2009, EPO issued $1.1 billion in
principal amount of Senior Notes Q and R under this registration
statement. Net proceeds from this senior note offering were used to
repay $500.0 million in aggregate principal amount of Senior Notes F that
matured in October 2009, to temporarily reduce borrowings outstanding under
EPO’s Multi-Year Revolving Credit Facility and for general partnership
purposes.
We also
have a registration statement on file with the SEC authorizing the issuance of
up to 40,000,000 common units in connection with our distribution reinvestment
plan (“DRIP”). During the nine months ended September 30, 2009, we
issued 10,731,084 common units in connection with our DRIP, which generated
proceeds of $254.7 million from plan participants. Affiliates of EPCO
reinvested $226.5 million in connection with the DRIP during the nine months
ended September 30, 2009.
In
addition, we have a registration statement on file related to our employee unit
purchase plan (“EUPP”), under which we can issue up to 1,200,000 common
units. During the nine months ended September 30, 2009, we issued
141,512 common units to employees under this plan, which generated proceeds of
$3.5 million.
Duncan
Energy Partners has a universal shelf registration statement filed with the SEC
that allows it to issue up to $1 billion of debt and equity
securities. In June 2009, Duncan Energy Partners completed an
offering of 8,000,000 of its common units, which generated net proceeds of
approximately $122.9 million. In July 2009, the underwriters to this
offering exercised their option to purchase an additional 943,400 common units,
which generated approximately $14.5 million of additional net proceeds for
Duncan Energy Partners. Duncan Energy Partners used the aggregate net
proceeds from this offering to repurchase an equal number of its common units
that were beneficially owned by EPO. Duncan Energy Partners
subsequently cancelled the common units it repurchased from EPO. At
September 30, 2009, Duncan Energy Partners can issue approximately $856.4
million of additional securities under its registration
statement.
For information regarding our public
debt obligations or partnership equity, see Notes 9 and 10,
respectively, of the Notes to Unaudited Condensed Consolidated Financial
Statements included under Item 1 of this Quarterly Report.
Letter
of Credit Facilities
At
September 30, 2009, EPO had outstanding a $50.0 million letter of credit
relating to its commodity derivative instruments and a $58.3 million letter of
credit related to its Petal GO Zone Bonds. These letter of credit
facilities do not reduce the amount available for borrowing under EPO’s credit
facilities. In addition, Duncan Energy Partners had an outstanding
letter of credit in the amount of $1.0 million at September 30, 2009, which
reduces the amount available for borrowing under its credit
facility.
Credit
Ratings of EPO
EPO’s
senior notes are rated investment-grade. Moody’s Investor Services
has assigned a rating of Baa3 and Standard & Poor’s and Fitch Ratings have
each assigned a rating of BBB-. Such ratings reflect only the view of
a rating agency and should not be interpreted as a recommendation to buy, sell
or hold any security. Any rating can be revised upward or downward or
withdrawn at any time by a rating agency if it determines that the circumstances
warrant such a change and should be evaluated independently of any other
rating.
Cash
Flows from Operating, Investing and Financing Activities
The
following table summarizes our cash flows from operating, investing and
financing activities for the periods indicated (dollars in
millions). For information regarding the individual components of our
cash flow amounts, see the Unaudited Condensed Statements of Consolidated Cash
Flows included under Item 1 of this Quarterly Report.
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
Net
cash flows provided by operating activities
|
|
$ |
615.4 |
|
|
$ |
973.0 |
|
Cash
used in investing activities
|
|
|
771.4 |
|
|
|
1,709.1 |
|
Cash
provided by financing activities
|
|
|
194.8 |
|
|
|
751.8 |
|
The
following information highlights the significant period-to-period variances in
our cash flow amounts:
Comparison
of Nine Months Ended September 30, 2009
with
Nine Months Ended September 30, 2008
Operating
Activities. Net cash flows
provided by operating activities were $615.4 million for the nine months ended
September 30, 2009 compared to $973.0 million for the nine months ended
September 30, 2008. This $357.6 million decrease in net cash flows
provided by operating activities was primarily due to the
following:
§
|
Net
cash flows from consolidated operations (excluding cash payments for
interest and distributions received from unconsolidated affiliates)
decreased $306.6 million period-to-period. Although our gross
operating margin increased period-to-period (see “Results of Operations”
within this Item 2), the reduction in operating cash flow is generally due
to the timing of related cash receipts and disbursements and an increase
in cash outlays for forward sales inventory. As a result
of energy market conditions, we significantly increased our physical
inventory purchases and related forward physical sales commitments during
2009. In general, the significant increase in volumes dedicated
to forward physical sales contracts improves the overall utilization and
profitability of our fee-based
assets.
|
§
|
Cash
payments for interest increased $44.7 million period-to-period primarily
due to increased borrowings to finance our capital spending program and
for general partnership purposes.
|
§
|
Distributions
received from unconsolidated affiliates decreased $6.3 million
period-to-period primarily due to lower distributions received from
Deepwater Gateway, partially offset by increased distributions received
from Cameron Highway.
|
Investing
Activities. Cash used in investing activities was $771.4
million for the nine months ended September 30, 2009 compared to $1.71 billion
for the nine months ended September 30, 2008. This $937.7 million
decrease in cash used in investing activities was primarily due to the
following:
§
|
Capital
spending for property, plant and equipment, net of contributions in aid of
construction costs, decreased $626.1 million
period-to-period. For additional information related to our
capital spending program, see “Capital Spending” included within this Item
2.
|
§
|
Restricted
cash related to our hedging activities decreased $100.8 million (a cash
inflow) during the nine months ended September 30, 2009 primarily due to
the reduction of margin requirements related to derivative instruments we
utilized. For the nine months ended September 30, 2008,
restricted cash related to our hedging activities increased $112.2 million
(a cash outflow).
|
§
|
Cash
used for business combinations decreased $32.6 million period-to-period
primarily due to our $23.7 million acquisition of rail and truck terminal
facilities located in Mont Belvieu, Texas in May 2009 compared to our
$57.1 million acquisition of additional interests in Dixie in August
2008.
|
§
|
Investments
in unconsolidated affiliates decreased $57.5 million period-to-period
primarily due to higher contributions made to Jonah Gas Gathering Company
in 2008 compared to 2009.
|
Financing
Activities. Cash provided by financing activities was $194.8
million for the nine months ended September 30, 2009 compared to $751.8 million
for the nine months ended September 30, 2008. The $557.0 million
decrease in cash provided by financing activities was primarily due to the
following:
§
|
Net
borrowings under our consolidated debt agreements were $94.7 million
during the nine months ended September 30, 2009 compared to $1.54 billion
during the nine months ended September 30, 2008. The $1.44
billion decrease in net borrowings was primarily attributable to lower
amounts of senior notes issued period-to-period, the repayment of the
$217.6 million Yen Term Loan in March 2009 and an increase in net
repayments under EPO’s Multi-Year Revolving Credit Facility
period-to-period. During the nine months ended September 30,
2008, EPO issued $1.1 billion in senior notes (Senior Notes M and N),
compared to $500.0 million in senior notes (Senior Notes P) during the
nine months ended September 30,
2009.
|
§
|
Cash
distributions to our partners increased $89.7 million period-to-period due
to increases in our common units outstanding and quarterly distribution
rates.
|
§
|
Net
proceeds from the issuance of common units increased $821.0 million
period-to-period primarily due to (i) the January and September 2009
issuances of common units that generated net proceeds of $452.0 million,
(ii) the September 2009 private placement of common units that generated
net proceeds of $150.0 million and (iii) an increase of $206.9 million in
proceeds generated by our DRIP and EUPP
period-to-period. Affiliates of EPCO reinvested $226.5 million
of their distributions through the DRIP during the nine months ended
September 30, 2009.
|
§
|
Contributions
from noncontrolling interests were $137.4 million for the nine months
ended September 30, 2009, which represents the net proceeds that Duncan
Energy Partners received from the issuance of an aggregate 8,943,400 of
its common units in June and July 2009. Duncan Energy Partners
used the net proceeds from this offering to repurchase and cancel an equal
number of its common units beneficially owned by
EPO.
|
Capital
Spending
The
following table summarizes our capital spending by activity for the periods
indicated (dollars in millions):
|
|
For
the Nine Months
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
|
|
Capital
spending for property, plant and equipment, net of contributions in
aid of construction costs
|
|
$ |
838.3 |
|
|
$ |
1,464.4 |
|
Capital
spending for business combinations
|
|
|
24.5 |
|
|
|
57.1 |
|
Capital
spending for intangible assets
|
|
|
-- |
|
|
|
5.1 |
|
Capital
spending for investments in unconsolidated affiliates
|
|
|
14.5 |
|
|
|
72.0 |
|
Total
capital spending
|
|
$ |
877.3 |
|
|
$ |
1,598.6 |
|
Based on
information currently available and after giving effect to the TEPPCO Merger, we
estimate our consolidated capital spending for the fourth quarter of 2009 will
approximate $700.0 million, which includes estimated expenditures of $630.0
million for growth capital projects and acquisitions and $70.0 million for
sustaining capital expenditures.
Our
forecast of consolidated capital expenditures is based on our current announced
strategic operating and growth plans. Our strategic operating and
growth plans are dependent upon our ability to generate the required funds from
either operating cash flows or from other means, including borrowings under debt
agreements, issuance of equity, and potential divestitures of certain assets to
third and/or related parties. Our forecast of capital expenditures
may change due to factors beyond our control, such as weather-related issues,
changes in supplier prices or adverse economic
conditions. Furthermore, our forecast may change as a result of
decisions made by management at a later date, which may include acquisitions or
decisions to take on additional partners.
Our
success in raising capital, including the formation of joint ventures to share
costs and risks, continues to be a principal factor that determines how much
capital we can invest. We believe our access to capital resources is
sufficient to meet the demands of our current and future operating growth needs,
and although we currently intend to make the forecasted expenditures discussed
above, we may adjust the timing and amounts of projected expenditures in
response to changes in capital markets.
At
September 30, 2009, after giving effect to the TEPPCO Merger, we had
approximately $497.0 million in purchase commitments outstanding that relate to
our capital spending for property, plant and equipment. These
remaining commitments primarily relate to construction of our Barnett Shale and
Piceance Basin natural gas pipeline projects and the construction of a new NGL
fractionator in Mont Belvieu, Texas.
Pipeline
Integrity Costs
Our NGL,
petrochemical and natural gas pipelines are subject to pipeline safety programs
administered by the U.S. Department of Transportation, through its Pipeline and
Hazardous Materials Safety Administration, and participating state
agencies. These federal and state agencies have issued safety
regulations containing requirements for the development of integrity management
programs for hazardous liquid pipelines (which include NGL and petrochemical
pipelines) and natural gas pipelines. In general, these regulations
require companies to assess the condition of their pipelines in certain areas
(such as high consequence areas as defined by the regulations) and to perform
any necessary repairs.
The
following table summarizes our pipeline integrity costs for the periods
indicated (dollars in millions):
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Expensed
|
|
$ |
9.6 |
|
|
$ |
14.5 |
|
|
$ |
27.8 |
|
|
$ |
38.4 |
|
Capitalized
|
|
|
9.7 |
|
|
|
16.2 |
|
|
|
21.5 |
|
|
|
38.9 |
|
Total
|
|
$ |
19.3 |
|
|
$ |
30.7 |
|
|
$ |
49.3 |
|
|
$ |
77.3 |
|
After
giving effect to the TEPPCO Merger, we expect the costs of our pipeline
integrity program, irrespective of whether such costs are capitalized or
expensed, to approximate $39.4 million for the remainder of 2009.
Other
Items
Contractual
Obligations
For information regarding year-to-date
changes in our contractual obligations, please see Note 14 of the Notes to
Unaudited Condensed Consolidated Financial Statements included under Item 1 of
this Quarterly Report.
Off-Balance
Sheet Arrangements
There
have been no significant changes with regards to our off-balance sheet
arrangements since those reported in our Recast Form 8-K.
Summary
of Related Party Transactions
On
October 26, 2009, the TEPPCO Merger was completed. Under terms of the
merger agreements, TEPPCO and TEPPCO GP became our wholly owned subsidiaries.
For additional information regarding this material related party transaction,
see “Recent Developments – Merger of TEPPCO and TEPPCO GP with Enterprise
Products Partners” within this Item 2.
The
following table summarizes other related party transactions for the periods
indicated (dollars in millions):
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Revenues
from consolidated operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
EPCO
and affiliates
|
|
$ |
41.1 |
|
|
$ |
47.2 |
|
|
$ |
98.9 |
|
|
$ |
91.9 |
|
Energy
Transfer Equity and subsidiaries
|
|
|
54.5 |
|
|
|
99.6 |
|
|
|
266.5 |
|
|
|
413.0 |
|
Unconsolidated
affiliates
|
|
|
55.8 |
|
|
|
153.4 |
|
|
|
155.6 |
|
|
|
318.8 |
|
Total
|
|
$ |
151.4 |
|
|
$ |
300.2 |
|
|
$ |
521.0 |
|
|
$ |
823.7 |
|
Cost
of sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EPCO
and affiliates
|
|
$ |
32.1 |
|
|
$ |
10.9 |
|
|
$ |
75.7 |
|
|
$ |
36.5 |
|
Energy
Transfer Equity and subsidiaries
|
|
|
100.6 |
|
|
|
50.6 |
|
|
|
286.5 |
|
|
|
119.4 |
|
Unconsolidated
affiliates
|
|
|
13.0 |
|
|
|
23.7 |
|
|
|
37.5 |
|
|
|
75.9 |
|
Total
|
|
$ |
145.7 |
|
|
$ |
85.2 |
|
|
$ |
399.7 |
|
|
$ |
231.8 |
|
Operating
costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EPCO
and affiliates
|
|
$ |
91.8 |
|
|
$ |
77.1 |
|
|
$ |
258.3 |
|
|
$ |
238.0 |
|
Energy
Transfer Equity and subsidiaries
|
|
|
2.0 |
|
|
|
5.9 |
|
|
|
5.3 |
|
|
|
15.0 |
|
Unconsolidated
affiliates
|
|
|
(2.5 |
) |
|
|
(3.0 |
) |
|
|
(7.7 |
) |
|
|
(7.7 |
) |
Total
|
|
$ |
91.3 |
|
|
$ |
80.0 |
|
|
$ |
255.9 |
|
|
$ |
245.3 |
|
General
and administrative expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EPCO
and affiliates
|
|
$ |
16.8 |
|
|
$ |
13.4 |
|
|
$ |
51.2 |
|
|
$ |
44.6 |
|
Other
expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EPCO
and affiliates
|
|
$ |
0.1 |
|
|
$ |
-- |
|
|
$ |
0.1 |
|
|
$ |
(0.3 |
) |
The
following table summarizes our related party receivable and payable amounts at
the dates indicated (dollars in millions):
|
|
September
30,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
Accounts
receivable - related parties:
|
|
|
|
|
|
|
EPCO
and affiliates
|
|
$ |
27.9 |
|
|
$ |
26.6 |
|
Energy
Transfer Equity and subsidiaries
|
|
|
6.4 |
|
|
|
35.0 |
|
Unconsolidated
affiliates
|
|
|
3.6 |
|
|
|
-- |
|
Total
|
|
$ |
37.9 |
|
|
$ |
61.6 |
|
|
|
|
|
|
|
|
|
|
Accounts
payable - related parties:
|
|
|
|
|
|
|
|
|
EPCO
and affiliates
|
|
$ |
16.9 |
|
|
$ |
39.4 |
|
Energy
Transfer Equity and subsidiaries
|
|
|
27.2 |
|
|
|
0.2 |
|
Unconsolidated
affiliates
|
|
|
3.1 |
|
|
|
-- |
|
Total
|
|
$ |
47.2 |
|
|
$ |
39.6 |
|
For
additional information regarding our related party transactions, see Note 12 of
the Notes to Unaudited Condensed Consolidated Financial Statements included
under Item 1 of this Quarterly Report.
Non-GAAP
Reconciliations
The
following table presents a reconciliation of our measurement of total non-GAAP
gross operating margin to GAAP operating income and income before provision for
income taxes (dollars in millions):
|
|
For
the Three Months
|
|
|
For
the Nine Months
|
|
|
|
Ended
September 30,
|
|
|
Ended
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Total
segment gross operating margin
|
|
$ |
560.9 |
|
|
$ |
478.9 |
|
|
$ |
1,618.8 |
|
|
$ |
1,535.5 |
|
Adjustments
to reconcile total segment gross operating margin to
operating income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
amortization and accretion in operating costs and expenses
|
|
|
(160.6 |
) |
|
|
(138.4 |
) |
|
|
(467.3 |
) |
|
|
(408.6 |
) |
Non-cash
impairment charge included in operating costs and expenses
|
|
|
(1.7 |
) |
|
|
-- |
|
|
|
(1.7 |
) |
|
|
-- |
|
Operating
lease expense paid by EPCO
|
|
|
(0.2 |
) |
|
|
(0.5 |
) |
|
|
(0.5 |
) |
|
|
(1.5 |
) |
Gain
from asset sales and related transactions in operating costs
and expenses
|
|
|
-- |
|
|
|
0.9 |
|
|
|
0.4 |
|
|
|
1.7 |
|
General
and administrative costs
|
|
|
(33.9 |
) |
|
|
(21.8 |
) |
|
|
(84.7 |
) |
|
|
(67.0 |
) |
Operating
income
|
|
|
364.5 |
|
|
|
319.1 |
|
|
|
1,065.0 |
|
|
|
1,060.1 |
|
Other
expense, net
|
|
|
(128.0 |
) |
|
|
(101.5 |
) |
|
|
(373.7 |
) |
|
|
(287.6 |
) |
Income
before provision for income taxes
|
|
$ |
236.5 |
|
|
$ |
217.6 |
|
|
$ |
691.3 |
|
|
$ |
772.5 |
|
Recent
Accounting Developments
The
accounting standard setting bodies have recently issued accounting guidance
since those reported in our Recast Form 8-K that will or may affect our future
financial statements. The recently issued accounting guidance relates
to:
§
|
The
hierarchy of GAAP and the establishment of the ASC (codified under ASC
105, Generally Accepted Accounting
Principles);
|
§
|
Estimating
fair value when the volume and level of activity for the asset or
liability have significantly decreased and identifying circumstances that
indicate a transaction is not orderly (codified under ASC 820, Fair Value
Measurement and
Disclosures);
|
§
|
Measuring
liabilities at fair value (codified under ASC
820);
|
§
|
Providing
quarterly disclosures about fair value estimates for all financial
instruments not measured on the balance sheet at fair value (codified
under ASC 825, Financial
Instruments);
|
§
|
The
accounting for, and disclosure of, events that occur after the balance
sheet date but before financial statements are issued or are available to
be issued (codified under ASC 855, Subsequent Events);
and
|
§
|
Consolidation
of variable interest entities (codified under ASC
810).
|
For
additional information regarding recent accounting developments, see Note 2 of
the Notes to Unaudited Condensed Consolidated Financial Statements included
under Item 1 of this Quarterly Report.
Insurance
Matters
EPCO
completed its annual insurance renewal process during the second quarter of
2009. In light of recent hurricane and other weather-related events, the
renewal of policies for weather-related risks resulted in significant increases
in premiums and certain deductibles, as well as changes in the scope of
coverage.
EPCO’s
deductible for onshore physical damage from windstorms increased from $10.0
million per storm to $25.0 million per storm. EPCO’s onshore program
currently provides $150.0 million per occurrence for named windstorm events
compared to $175.0 million per occurrence in the prior year. With
respect to offshore assets, the windstorm deductible increased significantly
from $10.0 million per storm (with a one-time aggregate deductible of $15.0
million) to $75.0 million per storm. EPCO’s offshore program
currently provides $100.0 million in the aggregate compared to $175.0 million in
the aggregate for the prior year. For non-windstorm events, EPCO’s
deductible for both onshore and offshore physical damage remained at $5.0
million per occurrence. For certain of our major offshore assets, our
producer customers have agreed to provide a specified level of physical damage
insurance for named windstorms. For example, the producers associated
with our Independence Hub and Marco Polo platforms have agreed to cover
windstorm generated physical damage costs up to $250.0 million for each
platform.
Business
interruption coverage in connection with a windstorm event remains in place for
onshore assets, but was eliminated for offshore assets. Onshore
assets covered by business interruption insurance must be out-of-service in
excess of 60 days before any losses from business interruption will be
covered. Furthermore, pursuant to the current policy, we will now
absorb 50% of the first $50.0 million of any loss in excess of deductible
amounts for our onshore assets.
For
additional information regarding weather-related risks, including insurance
matters in connection with Hurricanes Ivan, Katrina, Rita, Gustav and Ike, see
Note 15 of the Notes to Unaudited Condensed Consolidated Financial Statements
included under Item 1 of this Quarterly Report.
In the
course of our normal business operations, we are exposed to certain risks,
including changes in interest rates, commodity prices and, to a limited extent,
foreign exchange rates. In order to manage risks associated with certain
identifiable and anticipated transactions, we use derivative instruments.
Derivatives are financial instruments whose fair value is determined by changes
in a specified benchmark such as interest rates, commodity prices or currency
values. Typical derivative instruments include futures, forward contracts, swaps
and other instruments with similar characteristics. Substantially all
of our derivatives are used for non-trading activities. See Note 4 of
the Notes to Unaudited Condensed Financial Statements included under Item 1 of
this Quarterly Report for additional information regarding our derivative
instruments and hedging activities.
Our
exposures to market risk have not changed materially since those reported under
Item 7A “Quantitative and Qualitative Disclosures About Market Risk” in our
Recast Form 8-K.
Interest
Rate Derivative Instruments
We utilize interest rate swaps,
treasury locks and similar derivative instruments to manage our exposure to
changes in the interest rates of certain consolidated debt agreements. This
strategy is a component in controlling our cost of capital associated with such
borrowings.
The
following tables show the effect of hypothetical price movements on the
estimated fair value (“FV”) of interest rate swap portfolios at the dates
presented (dollars in millions):
Enterprise
Products Partners
|
Resulting
|
|
Swap
Fair Value at
|
|
Scenario
|
Classification
|
|
September
30, 2009
|
|
|
October
20, 2009
|
|
FV
assuming no change in underlying interest rates
|
Asset
|
|
$ |
46.5 |
|
|
$ |
43.7 |
|
FV
assuming 10% increase in underlying interest rates
|
Asset
|
|
|
40.4 |
|
|
|
37.7 |
|
FV
assuming 10% decrease in underlying interest rates
|
Asset
|
|
|
52.7 |
|
|
|
49.6 |
|
Duncan
Energy Partners
|
Resulting
|
|
Swap
Fair Value at
|
|
Scenario
|
Classification
|
|
September
30, 2009
|
|
|
October
20, 2009
|
|
FV
assuming no change in underlying interest rates
|
Liability
|
|
$ |
(6.0 |
) |
|
$ |
(6.2 |
) |
FV
assuming 10% increase in underlying interest rates
|
Liability
|
|
|
(5.8 |
) |
|
|
(6.0 |
) |
FV
assuming 10% decrease in underlying interest rates
|
Liability
|
|
|
(6.2 |
) |
|
|
(6.4 |
) |
The
following table shows the effect of hypothetical price movements on the
estimated fair value of our forward starting swap portfolio at the dates
presented (dollars in millions):
Enterprise
Products Partners
|
Resulting
|
|
Swap
Fair Value at
|
|
Scenario
|
Classification
|
|
September
30, 2009
|
|
|
October
20, 2009
|
|
FV
assuming no change in underlying interest rates
|
Asset
|
|
$ |
8.1 |
|
|
$ |
10.4 |
|
FV
assuming 10% increase in underlying interest rates
|
Asset
|
|
|
16.4 |
|
|
|
20.3 |
|
FV
assuming 10% decrease in underlying interest rates
|
Asset
|
|
|
0.1 |
|
|
|
0.5 |
|
Commodity
Derivative Instruments
The prices of natural gas, NGLs, crude
oil and certain petrochemical products are subject to fluctuations in response
to changes in supply, market uncertainty and a variety of additional factors
that are beyond our control. In order to manage the price risk associated with
such products, we enter into commodity derivative instruments such as forwards,
basis swaps and futures contracts.
The
following table shows the effect of hypothetical price movements on the
estimated fair value of our natural gas marketing portfolio at the dates
presented (dollars in millions):
|
Resulting
|
|
Portfolio
Fair Value at
|
|
Scenario
|
Classification
|
|
September
30, 2009
|
|
|
October
20, 2009
|
|
FV
assuming no change in underlying commodity prices
|
Liability
|
|
$ |
(2.8 |
) |
|
$ |
(4.2 |
) |
FV
assuming 10% increase in underlying commodity prices
|
Liability
|
|
|
(11.6 |
) |
|
|
(13.1 |
) |
FV
assuming 10% decrease in underlying commodity prices
|
Asset
|
|
|
6.1 |
|
|
|
4.7 |
|
The
following table shows the effect of hypothetical price movements on the
estimated fair value of our NGL and petrochemical operations portfolio at the
dates presented (dollars in millions):
|
Resulting
|
|
Portfolio
Fair Value at
|
|
Scenario
|
Classification
|
|
September
30, 2009
|
|
|
October
20, 2009
|
|
FV
assuming no change in underlying commodity prices
|
Liability
|
|
$ |
(84.1 |
) |
|
$ |
(119.2 |
) |
FV
assuming 10% increase in underlying commodity prices
|
Liability
|
|
|
(114.6 |
) |
|
|
(162.1 |
) |
FV
assuming 10% decrease in underlying commodity prices
|
Liability
|
|
|
(53.6 |
) |
|
|
(76.3 |
) |
Foreign
Currency Derivative Instruments
We are exposed to foreign currency
exchange risk in connection with our NGL marketing activities in
Canada. As a result, we could be adversely affected by fluctuations
in currency rates between the U.S. dollar and Canadian dollar. In order to
manage this risk, we may enter into foreign exchange purchase contracts to lock
in the exchange rate.
In addition, we were exposed to foreign
currency exchange risk in connection with a term loan denominated in Japanese
yen. We entered into this loan agreement in November 2008 and the
loan matured in March 2009. The derivative instrument used to hedge
this risk was accounted for as a cash flow hedge and settled upon repayment of
the loan.
At September 30, 2009, we had foreign
currency derivative instruments with a notional amount of $5.5 million Canadian
outstanding. The fair market value of this instrument was an asset of
$0.3 million at September 30, 2009.
Disclosure
Controls and Procedures
As of the end of the period covered by
this Quarterly Report, our management carried out an evaluation, with the
participation of our general partner’s chief executive officer (the “CEO”) and
our general partner’s chief financial officer (the “CFO”), of the effectiveness
of our disclosure controls and procedures pursuant to Rule 13a-15 of the
Securities Exchange Act of 1934. Based on this evaluation, as of the
end of the period covered by this Report, the CEO and CFO
concluded:
(i)
|
that
our disclosure controls and procedures are designed to ensure that
information required to be disclosed by us in the reports that we file or
submit under the Securities Exchange Act of 1934 is recorded, processed,
summarized and reported within the time periods specified in the SEC’s
rules and forms, and that such information is accumulated and communicated
to our management, including the CEO and CFO, as appropriate to allow
timely decisions regarding required disclosure;
and
|
(ii)
|
that
our disclosure controls and procedures are
effective.
|
Changes
in Internal Control over Financial Reporting
There
were no changes in our internal controls over financial reporting (as defined in
Rule 13a-15(f) under the Securities Exchange Act of 1934) or in other factors
during the third quarter of 2009, that have materially affected, or are
reasonably likely to materially affect, our internal controls over financial
reporting.
The certifications of our general
partner’s CEO and CFO required under Sections 302 and 906 of the Sarbanes-Oxley
Act of 2002 have been included as exhibits to this Quarterly
Report.
For
information on legal proceedings, see Part I, Item 1, Financial Statements, Note
14, “Commitments and Contingencies – Litigation,” of the Notes to Unaudited
Condensed Consolidated Financial Statements included in this Quarterly Report,
which is incorporated herein by reference.
Security
holders and potential investors in our securities should carefully consider the
risk factors set forth in our Annual Report on Form 10-K for the year ended
December 31, 2008 in addition to other information in such report and in this
Quarterly Report. We have identified these risk factors as important
factors that could cause our actual results to differ materially from those
contained in any written or oral forward-looking statements made by us or on our
behalf.
As of
September 30, 2009, we and our affiliates could repurchase up to 618,400
additional common units under the December 1998 common unit repurchase
program. We did not repurchase any of our common units in connection
with this announced program during the nine months ended September 30,
2009.
The
following table summarizes our repurchase activity during 2009 in connection
with other arrangements:
|
|
|
|
Maximum
|
|
|
|
Total
Number of
|
Number
of Units
|
|
|
Average
|
of
Units Purchased
|
That
May Yet
|
|
Total
Number of
|
Price
Paid
|
as
Part of Publicly
|
Be
Purchased
|
Period
|
Units
Purchased
|
per
Unit
|
Announced
Plans
|
Under
the Plans
|
February
2009
|
1,357
(1)
|
$22.64
|
--
|
--
|
May
2009
|
419
(2)
|
$24.69
|
--
|
--
|
July
2009
|
2,300
(3)
|
$28.10
|
--
|
--
|
August
2009
|
229,500
(4)
|
$28.00
|
--
|
--
|
|
|
|
|
|
(1)
Of
the 11,000 restricted unit awards that vested in February 2009 and
converted to common units, 1,357 of these units were sold back to the
partnership by employees to cover related withholding tax
requirements.
(2)
Of
the 1,500 restricted unit awards that vested in May 2009 and converted
into common units, 419 of these units were sold back to the partnership by
employees to cover related withholding tax requirements.
(3)
Of
the 2,300 restricted unit awards that vested in July 2009 and converted
into common units, 610 of these units were sold back to the partnership by
employees to cover related withholding tax requirements.
(4)
Of
the 229,500 restricted unit awards that vested in August 2009 and
converted into common units, 61,837 of these units were sold back to the
partnership by employees to cover related withholding tax
requirements.
|
None.
None.
None.
Exhibit
Number
|
Exhibit*
|
2.1
|
Merger
Agreement, dated as of December 15, 2003, by and among Enterprise Products
Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management
LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C.
(incorporated by reference to Exhibit 2.1 to Form 8-K filed December 15,
2003).
|
2.2
|
Amendment
No. 1 to Merger Agreement, dated as of August 31, 2004, by and among
Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise
Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra
Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form
8-K filed September 7, 2004).
|
2.3
|
Parent
Company Agreement, dated as of December 15, 2003, by and among Enterprise
Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products
GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine
River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra
GP Holding Company (incorporated by reference to Exhibit 2.2 to Form 8-K
filed December 15, 2003).
|
2.4
|
Amendment
No. 1 to Parent Company Agreement, dated as of April 19, 2004, by and
among Enterprise Products Partners L.P., Enterprise Products GP, LLC,
Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors
I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments,
L.L.C. and GulfTerra GP Holding Company (incorporated by reference to
Exhibit 2.1 to Form 8-K filed April 21,
2004).
|
2.5
|
Purchase
and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and
between El Paso Corporation, El Paso Field Services Management, Inc., El
Paso Transmission, L.L.C., El Paso Field Services Holding Company and
Enterprise Products Operating L.P. (incorporated by reference to Exhibit
2.4 to Form 8-K filed December 15, 2003).
|
2.6
|
Agreement
and Plan of Merger, dated as of June 28, 2009, by and among Enterprise
Products Partners L.P., Enterprise Products GP, LLC, Enterprise Sub B LLC,
TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC
(incorporated by reference to Exhibit 2.1 to Form 8-K filed June 29,
2009).
|
2.7
|
Agreement
and Plan of Merger, dated as of June 28, 2009, by and among Enterprise
Products Partners L.P., Enterprise Products GP, LLC, Enterprise Sub A LLC,
TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC
(incorporated by reference to Exhibit 2.2 to Form 8-K filed June 29,
2009).
|
3.1
|
Certificate
of Limited Partnership of Enterprise Products Partners L.P. (incorporated
by reference to Exhibit 3.6 to Form 10-Q filed November 9,
2007).
|
3.2
|
Fifth
Amended and Restated Agreement of Limited Partnership of Enterprise
Products Partners L.P., dated effective as of August 8, 2005 (incorporated
by reference to Exhibit 3.1 to Form 8-K filed August 10,
2005).
|
3.3
|
Amendment
No. 1 to the Fifth Amended and Restated Agreement of Limited Partnership
of Enterprise Products Partners L.P. dated as of December 27, 2007
(incorporated by reference to Exhibit 3.1 to Form 8-K/A filed January 3,
2008).
|
3.4
|
Amendment
No. 2 to the Fifth Amended and Restated Agreement of Limited Partnership
of Enterprise Products Partners L.P. dated as of April 14, 2008
(incorporated by reference to Exhibit 10.1 to Form 8-K filed April 16,
2008).
|
3.5
|
Amendment
No. 3 to the Fifth Amended and Restated Agreement of Limited Partnership
of Enterprise Products Partners L.P. dated as of November 6, 2008
(incorporated by reference to Exhibit 3.5 to Form 10-Q filed on November
10, 2008).
|
3.6
|
Amendment
No. 4 to the Fifth Amended and Restated Agreement of Limited Partnership
of Enterprise Products Partners L.P. dated as of October 26, 2009
(incorporated by reference to Exhibit 3.1 to Form 8-K filed on October 28,
2009).
|
3.7
|
Fifth
Amended and Restated Limited Liability Company Agreement of Enterprise
Products GP, LLC, dated as of November 7, 2007 (incorporated by reference
to Exhibit 3.2 to Form 10-Q filed November 9, 2007).
|
3.8
|
First
Amendment to Fifth Amended and Restated Limited Liability Company
Agreement of Enterprise Products GP, LLC, dated as of November 6, 2008
(incorporated by reference to Exhibit 3.7 to Form 10-Q filed on November
10, 2008).
|
3.9
|
Limited
Liability Company Agreement of Enterprise Products Operating LLC dated as
of June 30, 2007 (incorporated by reference to Exhibit 3.3 to Form 10-Q
filed on August 8, 2007).
|
3.10
|
Certificate
of Incorporation of Enterprise Products OLPGP, Inc., dated December 3,
2003 (incorporated by reference to Exhibit 3.5 to Form S-4 Registration
Statement, Reg. No. 333-121665, filed December 27,
2004).
|
3.11
|
Bylaws
of Enterprise Products OLPGP, Inc., dated December 8, 2003 (incorporated
by reference to Exhibit 3.6 to Form S-4 Registration Statement, Reg. No.
333-121665, filed December 27, 2004).
|
4.1
|
Form
of Common Unit certificate (incorporated by reference to Exhibit 4.1 to
Registration Statement on Form S-1/A; File No. 333-52537, filed July 21,
1998).
|
4.2
|
Indenture
dated as of March 15, 2000, among Enterprise Products Operating L.P., as
Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union
National Bank, as Trustee (incorporated by reference to Exhibit 4.1 to
Form 8-K filed March 10, 2000).
|
4.3
|
First
Supplemental Indenture dated as of January 22, 2003, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Guarantor, and Wachovia Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.2 to Registration Statement on
Form S-4, Reg. No. 333-102776, filed January 28, 2003).
|
4.4
|
Second
Supplemental Indenture dated as of February 14, 2003, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Guarantor, and Wachovia Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.3 to Form 10-K filed March 31,
2003).
|
4.5
|
Third
Supplemental Indenture dated as of June 30, 2007, among Enterprise
Products Operating L.P., as Original Issuer, Enterprise Products Partners
L.P., as Parent Guarantor, Enterprise Products Operating LLC, as New
Issuer, and U.S. Bank National Association, as successor Trustee
(incorporated by reference to Exhibit 4.55 to Form 10-Q filed on August 8,
2007).
|
4.6
|
Amended
and Restated Revolving Credit Agreement dated as of November 19, 2007
among Enterprise Products Operating LLC, the financial institutions party
thereto as lenders, Wachovia Bank, National Association, as Administrative
Agent, Issuing Bank and Swingline Lender, Citibank, N.A. and JPMorgan
Chase Bank, as Co-Syndication Agents, and SunTrust Bank, Mizuho Corporate
Bank, Ltd. and The Bank of Nova Scotia, as Co-Documentation Agents
(incorporated by reference to Exhibit 10.1 to Form 8-K filed on November
20, 2007).
|
4.7
|
Amended
and Restated Guaranty Agreement dated as of November 19, 2007
executed by Enterprise Products Partners L.P. in favor of Wachovia Bank,
National Association, as Administrative Agent (incorporated by reference
to Exhibit 10.2 to Form 8-K filed on November 20,
2007).
|
4.8
|
Indenture
dated as of October 4, 2004, among Enterprise Products Operating L.P., as
Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells
Fargo Bank, National Association, as Trustee (incorporated by reference to
Exhibit 4.1 to Form 8-K filed on October 6, 2004).
|
4.9
|
First
Supplemental Indenture dated as of October 4, 2004, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.2 to Form 8-K filed on October 6,
2004).
|
4.10
|
Second
Supplemental Indenture dated as of October 4, 2004, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.3 to Form 8-K filed on October 6,
2004).
|
4.11
|
Third
Supplemental Indenture dated as of October 4, 2004, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.4 to Form 8-K filed on October 6,
2004).
|
4.12
|
Fourth
Supplemental Indenture dated as of October 4, 2004, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.5 to Form 8-K filed on October 6,
2004).
|
4.13
|
Fifth
Supplemental Indenture dated as of March 2, 2005, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.2 to Form 8-K filed on March 3,
2005).
|
4.14
|
Sixth
Supplemental Indenture dated as of March 2, 2005, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.3 to Form 8-K filed on March 3,
2005).
|
4.15
|
Seventh
Supplemental Indenture dated as of June 1, 2005, among Enterprise Products
Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent
Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.46 to Form 10-Q filed November 4,
2005).
|
4.16
|
Eighth
Supplemental Indenture dated as of July 18, 2006, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.2 to Form 8-K filed July 19,
2006).
|
4.17
|
Ninth
Supplemental Indenture dated as of May 24, 2007, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.2 to the Current Report on
Form 8-K filed by Enterprise Products Partners L.P. on May 24,
2007).
|
4.18
|
Tenth
Supplemental Indenture dated as of June 30, 2007, among Enterprise
Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.54 to Form 10-Q filed August 8,
2007).
|
4.19
|
Eleventh
Supplemental Indenture dated as of September 4, 2007, among Enterprise
Products Operating L.P., as Original Issuer, Enterprise Products Operating
LLC, as New Issuer, Enterprise Products Partners L.P., as Parent
Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.3 to Form 8-K filed on September
5, 2007).
|
4.20
|
Twelfth
Supplemental Indenture dated as of April 3, 2008, among Enterprise
Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.3 to Form 8-K filed April 3,
2008).
|
4.21
|
Thirteenth
Supplemental Indenture dated as of April 3, 2008, among Enterprise
Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.4 to Form 8-K filed April 3,
2008).
|
4.22
|
Fourteenth
Supplemental Indenture dated as of December 8, 2008, among Enterprise
Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.3 to Form 8-K filed December 8,
2008).
|
4.23
|
Fifteenth
Supplemental Indenture dated as of June 10, 2009, among Enterprise
Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.3 to Form 8-K filed June 10,
2009).
|
4.24
|
Sixteenth
Supplemental Indenture dated as of October 5, 2009, among Enterprise
Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.3 to Form 8-K filed October 5,
2009).
|
4.25
|
Seventeenth
Supplemental Indenture dated as of October 27, 2009, among Enterprise
Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.1 to Form 8-K filed October 28,
2009).
|
4.26
|
Eighteenth
Supplemental Indenture dated as of October 27, 2009, among Enterprise
Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.2 to Form 8-K filed October 28,
2009).
|
4.27
|
Global
Note representing $350.0 million principal amount of 6.375% Series B
Senior Notes due 2013 with attached Guarantee (incorporated by reference
to Exhibit 4.3 to Registration Statement on Form S-4, Reg. No. 333-102776,
filed January 28, 2003).
|
4.28
|
Global
Note representing $229.2 million principal amount of 6.875% Series B
Senior Notes due 2033 with attached Guarantee (incorporated by reference
to Exhibit 4.5 to Form 10-K filed March 31, 2003).
|
4.29
|
Global
Note representing $450.0 million principal amount of 7.50% Senior Notes
due 2011 (incorporated by reference to Exhibit 4.1 to Form 8-K filed
January 25, 2001).
|
4.30
|
Global
Note representing $500.0 million principal amount of 4.00% Series B Senior
Notes due 2007 with attached Guarantee (incorporated by reference to
Exhibit 4.14 to Form S-3 Registration Statement Reg. No. 333-123150 filed
on March 4, 2005).
|
4.31
|
Global
Note representing $500.0 million principal amount of 5.60% Series B Senior
Notes due 2014 with attached Guarantee (incorporated by reference to
Exhibit 4.17 to Form S-3 Registration Statement Reg. No. 333-123150 filed
on March 4, 2005).
|
4.32
|
Global
Note representing $150.0 million principal amount of 5.60% Series B Senior
Notes due 2014 with attached Guarantee (incorporated by reference to
Exhibit 4.18 to Form S-3 Registration Statement Reg. No. 333-123150 filed
on March 4, 2005).
|
4.33
|
Global
Note representing $350.0 million principal amount of 6.65% Series B Senior
Notes due 2034 with attached Guarantee (incorporated by reference to
Exhibit 4.19 to Form S-3 Registration Statement Reg. No. 333-123150 filed
on March 4, 2005).
|
4.34
|
Global
Note representing $500.0 million principal amount of 4.625% Series B
Senior Notes due 2009 with attached Guarantee (incorporated by reference
to Exhibit 4.27 to Form 10-K for the year ended December 31, 2004 filed on
March 15, 2005).
|
4.35
|
Global
Note representing $250.0 million principal amount of 5.00% Series B Senior
Notes due 2015 with attached Guarantee (incorporated by reference to
Exhibit 4.31 to Form 10-Q filed on November 4, 2005).
|
4.36
|
Global
Note representing $250.0 million principal amount of 5.75% Series B Senior
Notes due 2035 with attached Guarantee (incorporated by reference to
Exhibit 4.32 to Form 10-Q filed on November 4, 2005).
|
4.37
|
Global
Note representing $500.0 million principal amount of 4.95% Senior Notes
due 2010 with attached Guarantee (incorporated by reference to Exhibit
4.47 to Form 10-Q filed November 4, 2005).
|
4.38
|
Form
of Junior Subordinated Note, including Guarantee (incorporated by
reference to Exhibit 4.2 to Form 8-K filed July 19,
2006).
|
4.39
|
Global
Note representing $800.0 million principal amount of 6.30% Senior Notes
due 2017 with attached Guarantee (incorporated by reference to Exhibit
4.38 to Form 10-Q filed November 9, 2007).
|
4.40
|
Form
of Global Note representing $400.0 million principal amount of 5.65%
Senior Notes due 2013 with attached Guarantee (incorporated by reference
to Exhibit 4.3 to Form 8-K filed April 3,
2008).
|
4.41
|
Form
of Global Note representing $700.0 million principal amount of 6.50%
Senior Notes due 2019 with attached Guarantee (incorporated by reference
to Exhibit 4.4 to Form 8-K filed April 3,
2008).
|
4.42
|
Form
of Global Note representing $500.0 million principal amount of 9.75%
Senior Notes due 2014 with attached Guarantee (incorporated by reference
to Exhibit 4.3 to Form 8-K filed December 8,
2008).
|
4.43
|
Form
of Global Note representing $500.0 million principal amount of 4.60%
Senior Notes due 2012 with attached Guarantee (incorporated by reference
to Exhibit 4.3 to Form 8-K filed June 10,
2009).
|
4.44
|
Form
of Global Note representing $500.0 million principal amount of 5.25%
Senior Notes due 2020 with attached Guarantee (incorporated by reference
to Exhibit 4.3 to Form 8-K filed October 5,
2009).
|
4.45
|
Form
of Global Note representing $600.0 million principal amount of 6.125%
Senior Notes due 2039 with attached Guarantee (incorporated by reference
to Exhibit 4.3 to Form 8-K filed October 5,
2009).
|
4.46
|
Form
of Global Note representing $490.5 million principal amount of 7.625%
Senior Notes due 2012 with attached Guarantee (incorporated by reference
to Exhibit 4.3 to Form 8-K filed October 28,
2009).
|
4.47
|
Form
of Global Note representing $182.6 million principal amount of 6.125%
Senior Notes due 2013 with attached Guarantee (incorporated by reference
to Exhibit 4.4 to Form 8-K filed October 28,
2009).
|
4.48
|
Form
of Global Note representing $237.6 million principal amount of 5.90%
Senior Notes due 2013 with attached Guarantee (incorporated by reference
to Exhibit 4.5 to Form 8-K filed October 28,
2009).
|
4.49
|
Form
of Global Note representing $349.7 million principal amount of 6.65%
Senior Notes due 2018 with attached Guarantee (incorporated by reference
to Exhibit 4.6 to Form 8-K filed October 28,
2009).
|
4.50
|
Form
of Global Note representing $399.6 million principal amount of 7.55%
Senior Notes due 2038 with attached Guarantee (incorporated by reference
to Exhibit 4.7 to Form 8-K filed October 28,
2009).
|
4.51
|
Form
of Global Note representing $285.8 million principal amount of 7.000%
Junior Subordinated Notes due 2067 with attached Guarantee (incorporated
by reference to Exhibit 4.8 to Form 8-K filed October 28,
2009).
|
4.52
|
Replacement
Capital Covenant, dated May 24, 2007, executed by Enterprise Products
Operating L.P. and Enterprise Products Partners L.P. in favor of the
covered debtholders described therein (incorporated by reference to
Exhibit 99.1 to Form 8-K filed May 24,
2007).
|
4.53
|
First
Amendment to Replacement Capital Covenant dated August 25, 2006,
executed by Enterprise Products Operating L.P. in favor of the covered
debtholders described therein (incorporated by reference to Exhibit 99.2
to Form 8-K filed August 25, 2006).
|
4.54
|
Purchase
Agreement, dated as of July 12, 2006 between Cerrito Gathering Company,
Ltd., Cerrito Gas Marketing, Ltd., Encinal Gathering, Ltd., as Sellers,
Lewis Energy Group, L.P., as Guarantor, and Enterprise Products Partners
L.P., as Buyer (incorporated by reference to Exhibit 4.6 to Form 10-Q
filed August 8, 2006).
|
4.55
|
Replacement
Capital Covenant, dated October 27, 2009, by and among Enterprise Products
Operating LLC and Enterprise Products Partners L.P. in favor of the
covered debtholders described therein (incorporated by reference to
Exhibit 4.9 to Form 8-K filed October 28,
2009).
|
10.1
|
Stipulation
and Agreement of Compromise, Settlement and Release, dated August 5, 2009
(incorporated by reference to Exhibit 10.3 to Form 10-Q filed by TEPPCO
Partners, L.P. on August 6, 2009).
|
10.2
|
Loan
Agreement, dated August 5, 2009, by and between Enterprise Products
Operating LLC, as Lender, and TEPPCO Partners, L.P., as Borrower
(incorporated by reference to Exhibit 10.4 to Form 10-Q filed by TEPPCO
Partners, L.P. on August 6, 2009).
|
10.3
|
Common
Unit Purchase Agreement, dated September 3, 2009, by and between
Enterprise Products Partners L.P. and EPCO Holdings, Inc. (incorporated by
reference to Exhibit 10.1 to Form 8-K on September 4,
2009).
|
31.1#
|
Sarbanes-Oxley
Section 302 certification of Michael A. Creel for Enterprise Products
Partners L.P. for the September 30, 2009 quarterly report on Form
10-Q.
|
31.2#
|
Sarbanes-Oxley
Section 302 certification of W. Randall Fowler for Enterprise Products
Partners L.P. for the September 30, 2009 quarterly report on Form
10-Q.
|
32.1#
|
Section
1350 certification of Michael A. Creel for the September 30, 2009
quarterly report on Form 10-Q.
|
32.2#
|
Section
1350 certification of W. Randall Fowler for the September 30, 2009
quarterly report on Form 10-Q.
|
*
|
With
respect to any exhibits incorporated by reference to any Exchange Act
filings, the Commission file number for Enterprise Products Partners L.P.,
Duncan Energy Partners L.P. and Enterprise GP Holdings L.P. and TEPPCO
Partners, L.P. are 1-14323, 1-33266, 1-32610 and 1-10403,
respectively.
|
#
|
Filed
with this report.
|
Pursuant to the requirements of Section
13 or 15(d) of the Securities Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned thereunto duly authorized
on November 9, 2009.
|
|
|
|
|
ENTERPRISE
PRODUCTS PARTNERS L.P.
|
|
|
|
|
|
(A
Delaware Limited Partnership)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
By: Enterprise
Products GP, LLC, as General Partner
|
|
|
|
|
|
|
|
|
|
|
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|
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|
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|
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By:
|
/s/
Michael J. Knesek
|
|
|
|
|
|
Name:
|
Michael
J. Knesek
|
|
|
|
|
|
Title:
|
Senior
Vice President, Controller
and
Principal Accounting Officer
of
the General Partner
|