epdform10q_033112.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 March 31, 2012
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 Street, 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 883,776,574 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 April 30, 2012. Our 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)
| |
|
March 31,
|
|
|
December 31,
|
|
|
ASSETS
|
|
2012
|
|
|
2011
|
|
|
Current assets:
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
88.3 |
|
|
$ |
19.8 |
|
|
Restricted cash
|
|
|
81.8 |
|
|
|
38.5 |
|
|
Accounts receivable – trade, net of allowance for doubtful accounts
of $13.0 at March 31, 2012 and $13.4 at December 31, 2011
|
|
|
4,526.7 |
|
|
|
4,501.8 |
|
|
Accounts receivable – related parties
|
|
|
13.4 |
|
|
|
43.5 |
|
|
Inventories
|
|
|
934.1 |
|
|
|
1,111.7 |
|
|
Prepaid and other current assets
|
|
|
452.9 |
|
|
|
353.4 |
|
|
Total current assets
|
|
|
6,097.2 |
|
|
|
6,068.7 |
|
|
Property, plant and equipment, net
|
|
|
22,910.3 |
|
|
|
22,191.6 |
|
|
Investments in unconsolidated affiliates
|
|
|
895.3 |
|
|
|
1,859.6 |
|
|
Intangible assets, net of accumulated amortization of $987.9 at
March 31, 2012 and $990.4 at December 31, 2011
|
|
|
1,644.2 |
|
|
|
1,656.2 |
|
|
Goodwill
|
|
|
2,092.3 |
|
|
|
2,092.3 |
|
|
Other assets
|
|
|
253.4 |
|
|
|
256.7 |
|
|
Total assets
|
|
$ |
33,892.7 |
|
|
$ |
34,125.1 |
|
| |
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
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Current maturities of debt
|
|
$ |
1,050.0 |
|
|
$ |
500.0 |
|
|
Accounts payable – trade
|
|
|
872.0 |
|
|
|
773.0 |
|
|
Accounts payable – related parties
|
|
|
79.3 |
|
|
|
211.6 |
|
|
Accrued product payables
|
|
|
4,830.4 |
|
|
|
5,047.1 |
|
|
Accrued interest
|
|
|
184.5 |
|
|
|
288.1 |
|
|
Other current liabilities
|
|
|
680.4 |
|
|
|
612.6 |
|
|
Total current liabilities
|
|
|
7,696.6 |
|
|
|
7,432.4 |
|
|
Long-term debt (see Note 9)
|
|
|
13,570.8 |
|
|
|
14,029.4 |
|
|
Deferred tax liabilities
|
|
|
22.0 |
|
|
|
91.2 |
|
|
Other long-term liabilities
|
|
|
215.0 |
|
|
|
352.8 |
|
|
Commitments and contingencies (see Note 14)
|
|
|
|
|
|
|
|
|
|
Equity: (see Note 10)
|
|
|
|
|
|
|
|
|
|
Partners’ equity:
|
|
|
|
|
|
|
|
|
|
Limited partners:
|
|
|
|
|
|
|
|
|
|
Common units (883,831,574 units outstanding at March 31, 2012
and 881,620,418 units outstanding at December 31, 2011)
|
|
|
12,502.1 |
|
|
|
12,346.3 |
|
|
Class B units (4,520,431 units outstanding at March 31, 2012
and December 31, 2011)
|
|
|
118.5 |
|
|
|
118.5 |
|
|
Accumulated other comprehensive loss
|
|
|
(341.8 |
) |
|
|
(351.4 |
) |
|
Total partners’ equity
|
|
|
12,278.8 |
|
|
|
12,113.4 |
|
|
Noncontrolling interests
|
|
|
109.5 |
|
|
|
105.9 |
|
|
Total equity
|
|
|
12,388.3 |
|
|
|
12,219.3 |
|
|
Total liabilities and equity
|
|
$ |
33,892.7 |
|
|
$ |
34,125.1 |
|
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
|
|
| |
|
Ended March 31,
|
|
| |
|
2012
|
|
|
2011
|
|
|
Revenues:
|
|
|
|
|
|
|
|
Third parties
|
|
$ |
11,221.7 |
|
|
$ |
9,933.6 |
|
|
Related parties
|
|
|
30.8 |
|
|
|
250.1 |
|
|
Total revenues (see Note 11)
|
|
|
11,252.5 |
|
|
|
10,183.7 |
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
Third parties
|
|
|
10,318.8 |
|
|
|
9,111.5 |
|
|
Related parties
|
|
|
148.4 |
|
|
|
425.6 |
|
|
Total operating costs and expenses
|
|
|
10,467.2 |
|
|
|
9,537.1 |
|
|
General and administrative costs:
|
|
|
|
|
|
|
|
|
|
Third parties
|
|
|
23.6 |
|
|
|
12.9 |
|
|
Related parties
|
|
|
22.7 |
|
|
|
25.0 |
|
|
Total general and administrative costs
|
|
|
46.3 |
|
|
|
37.9 |
|
|
Total costs and expenses (see Note 11)
|
|
|
10,513.5 |
|
|
|
9,575.0 |
|
|
Equity in income of unconsolidated affiliates
|
|
|
9.9 |
|
|
|
16.2 |
|
|
Operating income
|
|
|
748.9 |
|
|
|
624.9 |
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(186.5 |
) |
|
|
(183.8 |
) |
|
Interest income
|
|
|
0.3 |
|
|
|
0.3 |
|
|
Other, net (see Note 2)
|
|
|
58.4 |
|
|
|
0.2 |
|
|
Total other expense, net
|
|
|
(127.8 |
) |
|
|
(183.3 |
) |
|
Income before income taxes
|
|
|
621.1 |
|
|
|
441.6 |
|
|
Benefit from (provision for) income taxes (see Note 2)
|
|
|
34.4 |
|
|
|
(7.1 |
) |
|
Net income
|
|
|
655.5 |
|
|
|
434.5 |
|
|
Net income attributable to noncontrolling interests (see Note 10)
|
|
|
(4.2 |
) |
|
|
(13.8 |
) |
|
Net income attributable to limited partners
|
|
$ |
651.3 |
|
|
$ |
420.7 |
|
| |
|
|
|
|
|
|
|
|
|
Earnings per unit: (see Note 13)
|
|
|
|
|
|
|
|
|
|
Basic earnings per unit
|
|
$ |
0.76 |
|
|
$ |
0.52 |
|
|
Diluted earnings per unit
|
|
$ |
0.73 |
|
|
$ |
0.49 |
|
See Notes to Unaudited Condensed Consolidated Financial Statements.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED
COMPREHENSIVE INCOME
(Dollars in millions)
| |
|
For the Three Months
|
|
| |
|
Ended March 31,
|
|
| |
|
2012
|
|
|
2011
|
|
| |
|
|
|
|
|
|
|
Net income
|
|
$ |
655.5 |
|
|
$ |
434.5 |
|
|
Other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
Cash flow hedges:
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments:
|
|
|
|
|
|
|
|
|
|
Changes in fair value of cash flow hedges
|
|
|
(59.6 |
) |
|
|
(151.4 |
) |
|
Reclassification of gains and losses to net income
|
|
|
22.0 |
|
|
|
68.9 |
|
|
Interest rate derivative instruments:
|
|
|
|
|
|
|
|
|
|
Changes in fair value of cash flow hedges
|
|
|
28.9 |
|
|
|
14.1 |
|
|
Reclassification of gains and losses to net income
|
|
|
2.7 |
|
|
|
1.5 |
|
|
Total cash flow hedges
|
|
|
(6.0 |
) |
|
|
(66.9 |
) |
|
Change in funded status of pension and postretirement plans, net of tax
|
|
|
(1.2 |
) |
|
|
0.3 |
|
|
Proportionate share of other comprehensive income (loss) of unconsolidated affiliate
|
|
|
1.0 |
|
|
|
(1.0 |
) |
|
Change in fair value of available-for-sale equity securities
|
|
|
15.8 |
|
|
|
-- |
|
|
Total other comprehensive income (loss)
|
|
|
9.6 |
|
|
|
(67.6 |
) |
|
Comprehensive income
|
|
|
665.1 |
|
|
|
366.9 |
|
|
Comprehensive income attributable to noncontrolling interests
|
|
|
(4.2 |
) |
|
|
(13.8 |
) |
|
Comprehensive income attributable to limited partners
|
|
$ |
660.9 |
|
|
$ |
353.1 |
|
See Notes to Unaudited Condensed Consolidated Financial Statements.
ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in millions)
| |
|
For the Three Months
|
|
| |
|
Ended March 31,
|
|
| |
|
2012
|
|
|
2011
|
|
|
Operating activities:
|
|
|
|
|
|
|
|
Net income
|
|
$ |
655.5 |
|
|
$ |
434.5 |
|
|
Reconciliation of net income to net cash flows provided by operating activities:
|
|
|
|
|
|
|
|
|
|
Depreciation, amortization and accretion
|
|
|
266.1 |
|
|
|
241.1 |
|
|
Non-cash asset impairment charges
|
|
|
5.4 |
|
|
|
-- |
|
|
Equity in income of unconsolidated affiliates
|
|
|
(9.9 |
) |
|
|
(16.2 |
) |
|
Distributions received from unconsolidated affiliates
|
|
|
27.0 |
|
|
|
42.5 |
|
|
Gains from asset sales and related transactions
|
|
|
(55.2 |
) |
|
|
(18.4 |
) |
|
Deferred income tax expense (benefit)
|
|
|
(67.2 |
) |
|
|
0.8 |
|
|
Changes in fair market value of derivative instruments
|
|
|
(15.4 |
) |
|
|
(1.3 |
) |
|
Net effect of changes in operating accounts (see Note 15)
|
|
|
(201.1 |
) |
|
|
120.0 |
|
|
Other operating activities
|
|
|
(0.3 |
) |
|
|
(0.3 |
) |
|
Net cash flows provided by operating activities
|
|
|
604.9 |
|
|
|
802.7 |
|
|
Investing activities:
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(973.1 |
) |
|
|
(713.5 |
) |
|
Contributions in aid of construction costs
|
|
|
5.0 |
|
|
|
3.2 |
|
|
Increase in restricted cash
|
|
|
(15.0 |
) |
|
|
(92.9 |
) |
|
Investments in unconsolidated affiliates
|
|
|
(50.6 |
) |
|
|
(3.8 |
) |
|
Proceeds from asset sales (see Note 15)
|
|
|
998.2 |
|
|
|
84.2 |
|
|
Other investing activities
|
|
|
-- |
|
|
|
(3.6 |
) |
|
Cash used in investing activities
|
|
|
(35.5 |
) |
|
|
(726.4 |
) |
|
Financing activities:
|
|
|
|
|
|
|
|
|
|
Borrowings under debt agreements
|
|
|
1,396.6 |
|
|
|
2,821.6 |
|
|
Repayments of debt
|
|
|
(1,300.0 |
) |
|
|
(2,316.0 |
) |
|
Debt issuance costs
|
|
|
(7.1 |
) |
|
|
(12.8 |
) |
|
Monetization of interest rate derivative instruments (see Note 4)
|
|
|
(77.6 |
) |
|
|
(5.7 |
) |
|
Cash distributions paid to limited partners (see Note 10)
|
|
|
(530.4 |
) |
|
|
(479.7 |
) |
|
Cash distributions paid to noncontrolling interests (see Note 10)
|
|
|
(6.6 |
) |
|
|
(17.2 |
) |
|
Cash contributions from noncontrolling interests (see Note 10)
|
|
|
4.9 |
|
|
|
1.3 |
|
|
Net cash proceeds from issuance of common units
|
|
|
29.0 |
|
|
|
21.0 |
|
|
Other financing activities
|
|
|
(9.7 |
) |
|
|
(3.9 |
) |
|
Cash provided by (used in) financing activities
|
|
|
(500.9 |
) |
|
|
8.6 |
|
|
Net change in cash and cash equivalents
|
|
|
68.5 |
|
|
|
84.9 |
|
|
Cash and cash equivalents, January 1
|
|
|
19.8 |
|
|
|
65.5 |
|
|
Cash and cash equivalents, March 31
|
|
$ |
88.3 |
|
|
$ |
150.4 |
|
See Notes to Unaudited Condensed Consolidated Financial Statements.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY
(See Note 10 for Unit History, Accumulated Other Comprehensive
Income (Loss) and Noncontrolling Interests)
(Dollars in millions)
| |
|
Partners’ Equity
|
|
|
|
|
|
|
|
| |
|
Limited
Partners
|
|
|
Accumulated
Other
Comprehensive
Income (Loss)
|
|
|
Noncontrolling
Interests
|
|
|
Total
|
|
|
Balance, December 31, 2011
|
|
$ |
12,464.8 |
|
|
$ |
(351.4 |
) |
|
$ |
105.9 |
|
|
$ |
12,219.3 |
|
|
Net income
|
|
|
651.3 |
|
|
|
-- |
|
|
|
4.2 |
|
|
|
655.5 |
|
|
Cash distributions paid to limited partners
|
|
|
(530.4 |
) |
|
|
-- |
|
|
|
-- |
|
|
|
(530.4 |
) |
|
Cash distributions paid to noncontrolling interests
|
|
|
-- |
|
|
|
-- |
|
|
|
(6.6 |
) |
|
|
(6.6 |
) |
|
Cash contributions from noncontrolling interests
|
|
|
-- |
|
|
|
-- |
|
|
|
4.9 |
|
|
|
4.9 |
|
|
Net cash proceeds from issuance of common units
|
|
|
29.0 |
|
|
|
-- |
|
|
|
-- |
|
|
|
29.0 |
|
|
Amortization of fair value of equity-based awards
|
|
|
15.6 |
|
|
|
-- |
|
|
|
-- |
|
|
|
15.6 |
|
|
Cash flow hedges
|
|
|
-- |
|
|
|
(6.0 |
) |
|
|
-- |
|
|
|
(6.0 |
) |
|
Change in fair value of available-for-sale equity securities
|
|
|
-- |
|
|
|
15.8 |
|
|
|
-- |
|
|
|
15.8 |
|
|
Other
|
|
|
(9.7 |
) |
|
|
(0.2 |
) |
|
|
1.1 |
|
|
|
(8.8 |
) |
|
Balance, March 31, 2012
|
|
$ |
12,620.6 |
|
|
$ |
(341.8 |
) |
|
$ |
109.5 |
|
|
$ |
12,388.3 |
|
| |
|
Partners’ Equity
|
|
|
|
|
|
|
|
| |
|
Limited
Partners
|
|
|
Accumulated
Other
Comprehensive
Income (Loss)
|
|
|
Noncontrolling
Interests
|
|
|
Total
|
|
|
Balance, December 31, 2010
|
|
$ |
11,406.7 |
|
|
$ |
(32.5 |
) |
|
$ |
526.6 |
|
|
$ |
11,900.8 |
|
|
Net income
|
|
|
420.7 |
|
|
|
-- |
|
|
|
13.8 |
|
|
|
434.5 |
|
|
Cash distributions paid to limited partners
|
|
|
(479.7 |
) |
|
|
-- |
|
|
|
-- |
|
|
|
(479.7 |
) |
|
Cash distributions paid to noncontrolling interests
|
|
|
-- |
|
|
|
-- |
|
|
|
(17.2 |
) |
|
|
(17.2 |
) |
|
Cash contributions from noncontrolling interests
|
|
|
-- |
|
|
|
-- |
|
|
|
1.3 |
|
|
|
1.3 |
|
|
Net cash proceeds from issuance of common units
|
|
|
21.0 |
|
|
|
-- |
|
|
|
-- |
|
|
|
21.0 |
|
|
Amortization of fair value of equity-based awards
|
|
|
12.0 |
|
|
|
-- |
|
|
|
0.1 |
|
|
|
12.1 |
|
|
Cash flow hedges
|
|
|
-- |
|
|
|
(66.9 |
) |
|
|
-- |
|
|
|
(66.9 |
) |
|
Other
|
|
|
(3.7 |
) |
|
|
(0.7 |
) |
|
|
(1.5 |
) |
|
|
(5.9 |
) |
|
Balance, March 31, 2011
|
|
$ |
11,377.0 |
|
|
$ |
(100.1 |
) |
|
$ |
523.1 |
|
|
$ |
11,800.0 |
|
See Notes to Unaudited Condensed Consolidated Financial Statements.
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
With the exception of 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.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Unless the context requires otherwise, references to “we,” “us,” “our,” “Enterprise” 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, and its consolidated subsidiaries, through which Enterprise Products Partners L.P. conducts its business. Enterprise is managed by its general partner, Enterprise Products Holdings LLC (“Enterprise GP”), which is a wholly owned subsidiary of Dan Duncan LLC, a Delaware limited liability company.
The membership interests of Dan Duncan LLC are owned of record by a voting trust, the current trustees (“DD LLC Trustees”) of which are: (i) Randa Duncan Williams, who is also a director of Enterprise GP; (ii) Dr. Ralph S. Cunningham, who is also a director and the Chairman of Enterprise GP; and (iii) Richard H. Bachmann, who is also a director of Enterprise GP. Each of the DD LLC Trustees also currently serves as one of the three managers of Dan Duncan LLC.
References to “EPCO” mean Enterprise Products Company and its privately held affiliates. A majority of the outstanding voting capital stock of EPCO is owned of record by a voting trust, the current trustees (“EPCO Trustees”) of which are: (i) Ms. Williams, who also serves as Chairman of EPCO; (ii) Dr. Cunningham, who also serves as a Vice Chairman of EPCO; and (iii) Mr. Bachmann, who also serves as the President and Chief Executive Officer (“CEO”) of EPCO. Each of the EPCO Trustees is also a director of EPCO.
On April 28, 2011, we, our general partner, EPD MergerCo LLC (“Duncan MergerCo,” a Delaware limited liability company and our wholly owned subsidiary), Duncan Energy Partners L.P. (“Duncan Energy Partners”) and DEP Holdings, LLC (“DEP GP,” the general partner of Duncan Energy Partners) entered into a definitive merger agreement (the “Duncan Merger Agreement”). On September 7, 2011, the Duncan Merger Agreement was approved by the unitholders of Duncan Energy Partners and the merger of Duncan MergerCo with and into Duncan Energy Partners and related transactions were completed, with Duncan Energy Partners surviving such merger as our wholly owned subsidiary (collectively, we refer to these transactions as the “Duncan Merger”). See Note 1 for additional information regarding the Duncan Merger.
References to “TEPPCO” mean TEPPCO Partners, L.P. prior to its merger with one of our subsidiaries on October 26, 2009.
References to “Energy Transfer Equity” mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries.
Note 1. Partnership Operations, Organization and Basis of Presentation
General
We are 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.” We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are now a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, refined products and certain petrochemicals. 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 (“U.S.”), Canada and the Gulf of Mexico with domestic consumers and international markets. Our assets
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
include approximately 50,600 miles of onshore and offshore pipelines; 190 million barrels (“MMBbls”) of storage capacity for NGLs, crude oil, refined products and certain petrochemicals; and 14 billion cubic feet (“Bcf”) of natural gas storage capacity.
Our midstream energy operations include: natural gas gathering, treating, processing, transportation and storage; NGL transportation, fractionation, storage, and import and export terminaling; crude oil and refined products transportation, storage, and terminaling; offshore production platforms; petrochemical transportation and services; and a marine transportation business that operates primarily on the U.S. inland and Intracoastal Waterway systems and in the Gulf of Mexico. We have six reportable business segments: (i) NGL Pipelines & Services; (ii) Onshore Natural Gas Pipelines & Services; (iii) Onshore Crude Oil Pipelines & Services; (iv) Offshore Pipelines & Services; (v) Petrochemical & Refined Products Services; and (vi) Other Investments.
We are 100% owned by our limited partners from an economic perspective. We are managed and controlled by Enterprise GP, which has a non-economic general partner interest in us. We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates and under the collective common control of the DD LLC Trustees and the EPCO Trustees. We have no employees. All of our operating functions and general and administrative support services are provided by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers. See Note 12 for information regarding the ASA and other related party matters.
Completion of Duncan Merger
On September 7, 2011, the Duncan Merger Agreement was approved by the unitholders of Duncan Energy Partners and the merger of Duncan MergerCo and Duncan Energy Partners and related transactions were completed, with Duncan Energy Partners surviving such merger as our wholly owned subsidiary. Each issued and outstanding common unit of Duncan Energy Partners was cancelled and converted into the right to receive common units representing limited partner interests in Enterprise based on an exchange ratio of 1.01 Enterprise common units for each Duncan Energy Partners common unit. Enterprise issued 24,277,310 of its common units (net of fractional common units cashed out) as consideration in the Duncan Merger. No Enterprise common units were issued to Enterprise or its subsidiaries as merger consideration. Since we historically consolidated Duncan Energy Partners for financial reporting purposes, the Duncan Merger did not change the basis of presentation of our historical financial statements.
Our results of operations for the three months ended March 31, 2012 are not necessarily indicative of results expected for the full year of 2012. 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 and 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 the Notes thereto should be read in conjunction with the Audited Consolidated Financial Statements and Notes thereto included in our annual report on Form 10-K for the year ended December 31, 2011 (the “2011 Form 10-K”) filed with the SEC on February 29, 2012.
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Allowance for Doubtful Accounts
Our allowance for doubtful accounts is determined based on specific identification and estimates of future uncollectible accounts. The following table presents our allowance for doubtful accounts activity for the periods presented:
| |
|
For the Three Months
|
|
| |
|
Ended March 31,
|
|
| |
|
2012
|
|
|
2011
|
|
|
Balance at beginning of period
|
|
$ |
13.4 |
|
|
$ |
18.4 |
|
|
Charged to costs and expenses
|
|
|
0.1 |
|
|
|
0.2 |
|
|
Deductions (1)
|
|
|
(0.5 |
) |
|
|
(5.1 |
) |
|
Balance at end of period
|
|
$ |
13.0 |
|
|
$ |
13.5 |
|
| |
|
|
|
|
|
|
|
|
|
(1) The 2011 deduction is primarily due to our reassessment of the allowance for doubtful accounts as a result of improved credit ratings of a significant customer, which reduced our exposure to potential uncollectibility.
|
|
Contingencies
Certain conditions may exist as of the date our consolidated financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. Management has regular quarterly litigation reviews, including updates from legal counsel, to assess the need for accounting recognition or disclosure of these contingencies, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in such proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.
We accrue an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when it is believed to be only reasonably possible or remote.
For contingencies where an unfavorable outcome is reasonably possible and the impact would be material, we disclose the nature of the contingency and, if feasible, an estimate of the possible loss or range of loss.
Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. See Note 14 for additional information regarding our contingencies.
Derivative Instruments
We use derivative instruments such as futures, swaps, options, forward contracts and other arrangements to manage price risks associated with inventories, firm commitments, interest rates, foreign currencies and certain anticipated future transactions. To qualify for hedge accounting, the hedged item must expose us to risk and the related derivative instrument must reduce that exposure and meet specific hedge documentation requirements related to designation dates, expectations for hedge effectiveness and the probability that hedged future transactions will occur as forecasted. We formally designate derivative instruments as hedges and document and assess their effectiveness at inception of the hedge and on a monthly or quarterly basis thereafter. Forecasted transactions are evaluated for the probability of occurrence and are periodically back-tested once the forecasted period has passed to determine whether similarly forecasted transactions are probable of occurring in the future.
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
For certain of our physical forward derivative contracts, we apply the normal purchase/normal sale exception, whereby changes in the mark-to-market values of such contracts are not recognized in income. As a result, the revenues and expenses associated with the physical contract transactions are recognized during the period when volumes are physically delivered or received. Physical derivative contracts are evaluated for the probability of future delivery and are periodically back-tested once the forecasted period has passed to determine whether similar contracts are probable of physically delivering in the future.
See Note 4 for additional information regarding our derivative instruments and related interest rate and commodity hedging activities.
Estimates
Preparing our consolidated financial statements in conformity with GAAP requires us to make estimates that affect amounts presented in the financial statements. Our most significant estimates relate to (i) the useful lives and depreciation/amortization methods used for fixed and identifiable intangible assets; (ii) measurement of fair value and projections used in impairment testing of fixed and intangible assets (including goodwill); (iii) contingencies; and (iv) revenue and expense accruals.
Actual results could differ materially from our estimates. On an ongoing basis, we review our estimates based on currently available information. Any changes in the facts and circumstances underlying our estimates may require us to update such estimates, which could have a material impact on our consolidated financial statements.
Income Tax Benefit
During the first quarter of 2012, we recognized a net income tax benefit of $34.4 million, which was primarily due to a $46.5 million net income tax benefit related to the conversion of certain of our subsidiaries to limited liability companies partially offset by accruals for the Texas Margin Tax. The $46.5 million benefit is attributable to the difference between deferred income taxes accrued by the applicable subsidiaries through the date of conversion and any current income tax due in connection with the conversion.
Other Non-Operating Income
The following table presents the components of “Other, net” income for the periods presented:
| |
|
For the Three Months
Ended March 31,
|
|
| |
|
2012
|
|
|
2011
|
|
|
Gain on sales of available-for-sale securities (1)
|
|
$ |
53.3 |
|
|
$ |
-- |
|
|
Distribution income from available-for-sale securities
|
|
|
4.1 |
|
|
|
-- |
|
|
Other
|
|
|
1.0 |
|
|
|
0.2 |
|
| |
|
$ |
58.4 |
|
|
$ |
0.2 |
|
| |
|
|
|
|
|
|
|
|
|
(1) Represents gains on the sale of Energy Transfer Equity common units. See Note 7 for information regarding our investment in Energy Transfer Equity.
|
|
Recent Accounting Developments
Accounting standard setting organizations have been very active in recent years. Recently, they issued new and revised accounting guidance on a number of topics, including balance sheet offsetting. We do not believe that adoption of this new guidance will have a material impact on our consolidated financial statements.
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
An allocated portion of the fair value of EPCO’s equity-based awards is charged to us under the ASA. The following table summarizes the expense we recognized in connection with equity-based awards for the periods presented:
| |
|
For the Three Months
Ended March 31,
|
|
| |
|
2012
|
|
|
2011
|
|
|
Restricted common unit awards
|
|
$ |
14.8 |
|
|
$ |
11.4 |
|
|
Unit option awards
|
|
|
0.7 |
|
|
|
0.9 |
|
|
Other (1)
|
|
|
0.9 |
|
|
|
(0.5 |
) |
|
Total compensation expense
|
|
$ |
16.4 |
|
|
$ |
11.8 |
|
| |
|
|
|
|
|
|
|
|
|
(1) Primarily consists of unit appreciation rights (“UARs”), phantom units and similar awards.
|
|
The fair value of equity-classified awards (e.g., restricted common unit and unit option awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards (e.g., UARs and phantom units) is recognized over the requisite service or vesting period based on the fair value of the award remeasured at each reporting period. Liability-classified awards are settled in cash upon vesting.
At March 31, 2012, EPCO’s significant long-term incentive plans applicable to us were the Enterprise Products 1998 Long-Term Incentive Plan (“1998 Plan”) and the Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan (“2008 Plan”). In addition, there were unvested awards outstanding under an inactive plan, the Enterprise Products 2006 TPP Long-Term Incentive Plan (“2006 Plan”). After giving effect to awards granted under the 1998 Plan and 2008 Plan through March 31, 2012, a total of 531,669 and 4,885,394 additional common units could be issued under these plans, respectively.
Restricted Common Unit Awards
Restricted common unit awards allow recipients to acquire our common units (at no cost to the recipient apart from service or other conditions) once a defined vesting period expires, subject to customary forfeiture provisions. Restricted common unit awards issued in 2012 generally vest at a rate of 25% per year beginning one year after the grant date. As used in the context of EPCO’s long-term incentive plans, the term “restricted common unit” represents a time-vested unit. Such awards are non-vested until the required service period expires. Restricted common units are included in the number of common units presented on our Unaudited Condensed Consolidated Balance Sheets.
The fair value of a restricted common unit award is based on the market price per unit of the underlying security on the date of grant. Compensation expense is recognized based on the grant date fair value, net of an allowance for estimated forfeitures, over the requisite service or vesting period.
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table presents information regarding restricted common unit awards for the period presented:
| |
|
Number of
Units
|
|
|
Weighted-
Average Grant
Date Fair Value
per Unit (1)
|
|
|
Restricted common units at December 31, 2011
|
|
|
3,868,216 |
|
|
$ |
34.22 |
|
|
Granted (2)
|
|
|
1,529,438 |
|
|
$ |
51.92 |
|
|
Vested (3)
|
|
|
(632,298 |
) |
|
$ |
38.31 |
|
|
Forfeited
|
|
|
(24,800 |
) |
|
$ |
36.33 |
|
|
Restricted common units at March 31, 2012
|
|
|
4,740,556 |
|
|
$ |
39.37 |
|
| |
|
|
|
|
|
|
|
|
|
(1) Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued.
(2) The aggregate grant date fair value of restricted common unit awards issued in 2012 was $79.4 million based on a grant date market price of $51.92 per unit. An estimated annual forfeiture rate of 3.25% was applied to these awards.
(3) Includes awards granted to the independent directors of the board of directors of Enterprise GP as part of their annual compensation for 2012. A total of 10,038 restricted common units were issued in February 2012 to the independent directors of Enterprise GP that immediately vested upon issuance.
|
|
Typically, each recipient is also entitled to nonforfeitable cash distributions equal to the product of the number of restricted common units outstanding for the participant and the cash distribution per unit paid to limited partners. Since these restricted common units are participating securities, such distributions are included in “Cash distributions paid to limited partners” as presented on our Unaudited Condensed Statements of Consolidated Cash Flows.
The following table presents supplemental information regarding our restricted common unit awards for the periods presented:
| |
|
For the Three Months
|
|
| |
|
Ended March 31,
|
|
| |
|
2012
|
|
|
2011
|
|
|
Cash distributions paid to restricted common unit holders
|
|
$ |
2.4 |
|
|
$ |
2.1 |
|
|
Total intrinsic value of our restricted common unit awards
vesting during period
|
|
|
32.6 |
|
|
|
14.7 |
|
For the EPCO group of companies, the unrecognized compensation cost associated with restricted common unit awards was an aggregate $107.5 million at March 31, 2012, of which our allocated share of the cost is currently estimated to be $102.2 million. We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 2.2 years.
Unit Option Awards
EPCO’s long-term incentive plans provide for the issuance of non-qualified incentive options. These unit option awards are denominated in our common units. When issued, the exercise price of each unit option grant may be no less than the market price of our common units on the date of grant. In general, option grants have a vesting period of four years from the date of grant and expire at the end of the calendar year following the year of vesting (e.g., an option vesting on May 29, 2011 will expire on December 31, 2012). However, unit options only become exercisable at certain times during the calendar year following the year in which they vest (typically the months of February, May, August and November).
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The fair value of each unit option is estimated on the date of grant using a Black-Scholes option pricing model. Compensation expense recorded in connection with unit options is based on the grant date fair value of such awards, net of an allowance for estimated forfeitures, over the requisite service or vesting period. The following table presents unit option activity for the period presented:
| |
|
Number of
Units
|
|
|
Weighted-
Average
Strike Price
(dollars/unit)
|
|
|
Weighted-
Average
Remaining
Contractual
Term
(in years)
|
|
|
Aggregate
Intrinsic
Value (1)
|
|
|
Unit options at December 31, 2011
|
|
|
3,753,420 |
|
|
$ |
28.08 |
|
|
|
2.6 |
|
|
$ |
11.1 |
|
|
Exercised
|
|
|
(712,280 |
) |
|
$ |
30.76 |
|
|
|
|
|
|
|
|
|
|
Unit options at March 31, 2012
|
|
|
3,041,140 |
|
|
$ |
27.45 |
|
|
|
2.8 |
|
|
$ |
-- |
|
|
Options exercisable at March 31, 2012
|
|
|
-- |
|
|
|
|
|
|
|
-- |
|
|
|
-- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Aggregate intrinsic value reflects fully vested unit options at the date indicated.
|
|
In order to fund its unit option-related obligations, EPCO may purchase common units at fair value either in the open market or directly from us. When employees exercise unit options, we reimburse EPCO for the cash difference between the strike price paid by the employee and the actual purchase price paid by EPCO for the units issued to the employee.
The following table presents supplemental information regarding our unit options during the periods presented:
| |
|
For the Three Months
Ended March 31,
|
|
| |
|
2012
|
|
|
2011
|
|
|
Total intrinsic value of unit option awards exercised during period
|
|
$ |
14.0 |
|
|
$ |
-- |
|
|
Cash received from EPCO in connection with the
exercise of unit option awards
|
|
|
10.2 |
|
|
|
-- |
|
|
Unit option-related reimbursements to EPCO
|
|
|
14.0 |
|
|
|
-- |
|
For the EPCO group of companies, the unrecognized compensation cost associated with unit option awards was an aggregate $3.0 million at March 31, 2012, of which our allocated share of the cost is currently estimated to be $2.7 million. We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 1.3 years.
Unit Appreciation Rights
UARs entitle the recipient to receive a cash payment on the vesting date of the award equal to the excess, if any, of the then current fair market value of our common units over the grant date fair value of the award. UARs are accounted for as liability awards.
At March 31, 2012 and December 31, 2011, there were 107,328 UARs outstanding that had been granted under the 2006 Plan. The accrued liability for UARs at March 31, 2012 and December 31, 2011 was $1.1 million and $0.5 million, respectively.
Note 4. Derivative Instruments, Hedging Activities and Fair Value Measurements
In the normal course of our business operations, we are exposed to certain risks, including changes in interest rates and commodity prices. In order to manage risks associated with certain anticipated future transactions, we use derivative instruments. Substantially all of our derivatives are used for non-trading activities.
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
We are required to recognize derivative instruments at fair value as either assets or liabilities on our balance sheet unless such instruments meet certain normal purchase/normal sale criteria. While all derivatives are required to be reported at fair value on the balance sheet, changes in fair value of the derivative instruments are reported in different ways, depending on the nature and effectiveness of the hedging activities to which they relate. An effective hedge relationship is one in which the change in fair value of a derivative instrument can be expected to offset 80% to 125% of the changes in fair value of a hedged item at inception and throughout the life of the hedging relationship. Any ineffectiveness associated with a hedge relationship 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.
A contract designated as a cash flow hedge of an anticipated transaction that is not probable of occurring is immediately recognized in earnings.
Certain of our derivative instruments do not qualify for hedge accounting treatment; therefore, they are accounted for using mark-to-market accounting.
Interest Rate Derivative Instruments
We may utilize interest rate swaps, forward starting swaps and similar derivative instruments to manage our exposure to changes in interest rates charged on borrowings under certain consolidated debt agreements. The following table summarizes our portfolio of interest rate swaps at March 31, 2012:
|
Hedged Transaction
|
Number and Type
of Derivatives
Outstanding
|
Notional
Amount
|
Period of
Hedge
|
Rate
Swap
|
Accounting
Treatment
|
|
Senior Notes AA
|
10 fixed-to-floating swaps
|
$750.0
|
1/11 to 2/16
|
3.2% to 1.5%
|
Fair value hedge
|
|
Undesignated swaps
|
6 floating-to-fixed swaps
|
$600.0
|
5/10 to 7/14
|
0.6% to 2.0%
|
Mark-to-market
|
Interest expense for the three months ended March 31, 2012 and 2011 reflects a benefit of $2.8 million and $9.7 million, respectively, attributable to interest rate swaps.
In February 2012, we settled 11 fixed-to-floating interest rate swaps having an aggregate notional amount of $800.0 million, resulting in gains totaling $37.7 million. These gains will be amortized to earnings (as a decrease in interest expense) using the effective interest method over the forecasted hedged period of approximately three years.
The following table summarizes our portfolio of forward starting swaps outstanding at March 31, 2012. Forward starting swaps hedge the expected underlying benchmark interest rates related to future issuances of debt.
|
Hedged Transaction
|
Number and Type
of Derivatives
Outstanding
|
Notional
Amount
|
Expected Termination
Date
|
Average Rate
Locked
|
Accounting
Treatment
|
|
Future debt offering
|
7 forward starting swaps
|
$350.0
|
8/12
|
3.7%
|
Cash flow hedge
|
|
Future debt offering
|
16 forward starting swaps
|
$1,000.0
|
3/13
|
3.7%
|
Cash flow hedge
|
In connection with the issuance of Senior Notes EE in February 2012 (see Note 9), we settled ten forward starting swaps having an aggregate notional value of $500.0 million, resulting in losses totaling $115.3 million. These losses are reflected in other comprehensive income for the three months ended March 31, 2012 and amortized to earnings (as an increase in interest expense) using the effective interest method over the forecasted hedge period of ten years.
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Commodity Derivative Instruments
The prices of natural gas, NGLs, crude oil, refined products and certain petrochemical products are subject to fluctuations in response to changes in supply and demand, market conditions and a variety of additional factors that are beyond our control. In order to manage such price risks, we enter into commodity derivative instruments such as physical forward contracts, futures contracts, fixed-for-float swaps, basis swaps and options contracts. The following table summarizes our commodity derivative instruments outstanding at March 31, 2012:
| |
Volume (1)
|
Accounting
|
|
Derivative Purpose
|
Current (2)
|
Long-Term (2)
|
Treatment
|
|
Derivatives designated as hedging instruments:
|
|
|
|
|
Natural gas processing:
|
|
|
|
|
Forecasted natural gas purchases for plant thermal reduction (“PTR”) (3)
|
27.7 Bcf
|
n/a
|
Cash flow hedge
|
|
Forecasted sales of NGLs (4)
|
2.4 MMBbls
|
n/a
|
Cash flow hedge
|
|
Octane enhancement:
|
|
|
|
|
Forecasted purchases of NGLs
|
0.3 MMBbls
|
n/a
|
Cash flow hedge
|
|
Forecasted sales of octane enhancement products
|
3.2 MMBbls
|
n/a
|
Cash flow hedge
|
|
Natural gas marketing:
|
|
|
|
|
Natural gas storage inventory management activities
|
10.5 Bcf
|
n/a
|
Fair value hedge
|
|
NGL marketing:
|
|
|
|
|
Forecasted purchases of NGLs and related hydrocarbon products
|
3.7 MMBbls
|
n/a
|
Cash flow hedge
|
|
Forecasted sales of NGLs and related hydrocarbon products
|
3.6 MMBbls
|
0.2 MMBbls
|
Cash flow hedge
|
|
Refined products marketing:
|
|
|
|
|
Forecasted purchases of refined products
|
0.4 MMBbls
|
n/a
|
Cash flow hedge
|
|
Forecasted sales of refined products
|
0.4 MMBbls
|
n/a
|
Cash flow hedge
|
|
Refined products inventory management activities
|
0.1 MMBbls
|
n/a
|
Fair value hedge
|
|
Crude oil marketing:
|
|
|
|
|
Forecasted purchases of crude oil
|
1.6 MMBbls
|
n/a
|
Cash flow hedge
|
|
Forecasted sales of crude oil
|
2.6 MMBbls
|
n/a
|
Cash flow hedge
|
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
Natural gas risk management activities (5,6)
|
416.9 Bcf
|
69.6 Bcf
|
Mark-to-market
|
|
Refined products risk management activities (6)
|
0.4 MMBbls
|
n/a
|
Mark-to-market
|
|
Crude oil risk management activities (6)
|
6.1 MMBbls
|
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 designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2013, May 2012 and October 2015, respectively.
(3) PTR represents the British thermal unit (“Btu”) 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.
(4) Forecasted sales of NGL volumes under natural gas processing exclude 4.9 MMBbls of additional hedges executed under contracts that have been designated as normal sales agreements.
(5) Current volumes include approximately 104.2 Bcf of physical derivative instruments that are predominantly priced at an index plus a premium or minus a discount related to location differences.
(6) Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.
|
Our predominant hedging strategies are: (i) hedging natural gas processing margins; (ii) hedging anticipated future contracted sales of NGLs, refined products and crude oil associated with volumes held in inventory; and (iii) hedging the fair value of natural gas in inventory. The following information summarizes these hedging strategies:
|
§
|
The objective of our natural gas processing strategy is to hedge an amount of gross margin associated with our natural gas processing activities. We achieve this objective by using physical and financial instruments to lock in the purchase prices of natural gas consumed as PTR and the sales prices of the related NGL products. This program consists of (i) the forward sale of a portion
|
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
|
of our expected equity NGL production at fixed prices through December 2012, which is achieved through the use of forward physical sales contracts and commodity derivative instruments and (ii) the purchase of commodity derivative instruments having a notional amount based on the volume of natural gas expected to be consumed as PTR in the production of such equity NGL production.
|
|
§
|
The objective of our NGL, refined products and crude oil sales hedging program is to hedge the margins of anticipated future sales of inventory by locking in sales prices through the use of forward physical sales contracts and 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.
|
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
|
|
| |
March 31, 2012
|
|
December 31, 2011
|
|
March 31, 2012
|
|
December 31, 2011
|
|
| |
Balance
Sheet
Location
|
|
Fair
Value
|
|
Balance
Sheet
Location
|
|
Fair
Value
|
|
Balance
Sheet
Location
|
|
Fair
Value
|
|
Balance
Sheet
Location
|
|
Fair
Value
|
|
|
Derivatives designated as hedging instruments
|
|
|
Interest rate derivatives
|
Other current
assets
|
|
$ |
14.7 |
|
Other current
assets
|
|
$ |
43.7 |
|
Other current
liabilities
|
|
$ |
146.5 |
|
Other current
liabilities
|
|
$ |
163.6 |
|
|
Interest rate derivatives
|
Other assets
|
|
|
22.7 |
|
Other assets
|
|
|
44.2 |
|
Other liabilities
|
|
|
-- |
|
Other liabilities
|
|
|
127.1 |
|
|
Total interest rate derivatives
|
|
|
|
37.4 |
|
|
|
|
87.9 |
|
|
|
|
146.5 |
|
|
|
|
290.7 |
|
|
Commodity derivatives
|
Other current
assets
|
|
|
47.0 |
|
Other current
assets
|
|
|
20.3 |
|
Other current
liabilities
|
|
|
100.1 |
|
Other current
liabilities
|
|
|
30.3 |
|
|
Commodity derivatives
|
Other assets
|
|
|
0.4 |
|
Other assets
|
|
|
-- |
|
Other liabilities
|
|
|
-- |
|
Other liabilities
|
|
|
0.2 |
|
|
Total commodity derivatives (1)
|
|
|
|
47.4 |
|
|
|
|
20.3 |
|
|
|
|
100.1 |
|
|
|
|
30.5 |
|
|
Total derivatives designated as
hedging instruments
|
|
|
$ |
84.8 |
|
|
|
$ |
108.2 |
|
|
|
$ |
246.6 |
|
|
|
$ |
321.2 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments
|
|
|
Interest rate derivatives
|
Other current
assets
|
|
$ |
-- |
|
Other current
assets
|
|
$ |
-- |
|
Other current
liabilities
|
|
$ |
10.9 |
|
Other current
liabilities
|
|
$ |
10.1 |
|
|
Interest rate derivatives
|
Other assets
|
|
|
-- |
|
Other assets
|
|
|
-- |
|
Other liabilities
|
|
|
9.7 |
|
Other liabilities
|
|
|
10.6 |
|
|
Total interest rate derivatives
|
|
|
|
-- |
|
|
|
|
-- |
|
|
|
|
20.6 |
|
|
|
|
20.7 |
|
|
Commodity derivatives
|
Other current
assets
|
|
|
37.2 |
|
Other current
assets
|
|
|
34.4 |
|
Other current
liabilities
|
|
|
16.9 |
|
Other current
liabilities
|
|
|
32.5 |
|
|
Commodity derivatives
|
Other assets
|
|
|
5.3 |
|
Other assets
|
|
|
12.6 |
|
Other liabilities
|
|
|
2.4 |
|
Other liabilities
|
|
|
2.0 |
|
|
Total commodity derivatives
|
|
|
|
42.5 |
|
|
|
|
47.0 |
|
|
|
|
19.3 |
|
|
|
|
34.5 |
|
|
Total derivatives not designated as
hedging instruments
|
|
|
$ |
42.5 |
|
|
|
$ |
47.0 |
|
|
|
$ |
39.9 |
|
|
|
$ |
55.2 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Represents commodity derivative instrument transactions that have either 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.
|
|
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 presented:
|
Derivatives in Fair Value
Hedging Relationships
|
Location
|
|
Gain/(Loss) Recognized in
Income on Derivative
|
|
| |
|
|
For the Three Months
Ended March 31,
|
|
| |
|
|
2012
|
|
|
2011
|
|
|
Interest rate derivatives
|
Interest expense
|
|
$ |
(1.5 |
) |
|
$ |
(12.3 |
) |
|
Commodity derivatives
|
Revenue
|
|
|
0.7 |
|
|
|
0.3 |
|
|
Total
|
|
|
$ |
(0.8 |
) |
|
$ |
(12.0 |
) |
|
Derivatives in Fair Value
Hedging Relationships
|
Location
|
|
Gain/(Loss) Recognized in
Income on Hedged Item
|
|
| |
|
|
For the Three Months
Ended March 31,
|
|
| |
|
|
2012
|
|
|
2011
|
|
|
Interest rate derivatives
|
Interest expense
|
|
$ |
1.1 |
|
|
$ |
11.3 |
|
|
Commodity derivatives
|
Revenue
|
|
|
0.4 |
|
|
|
(1.3 |
) |
|
Total
|
|
|
$ |
1.5 |
|
|
$ |
10.0 |
|
The following tables present the effect of our derivative instruments designated as cash flow hedges on our Unaudited Condensed Statements of Consolidated Operations and Unaudited Condensed Statements of Consolidated Comprehensive Income for the periods presented:
|
Derivatives in Cash Flow
Hedging Relationships
|
|
Change in Value
Recognized in Other
Comprehensive
Income/(Loss)
on Derivative
(Effective Portion)
|
|
| |
|
For the Three Months
Ended March 31,
|
|
| |
|
2012
|
|
|
2011
|
|
|
Interest rate derivatives
|
|
$ |
28.9 |
|
|
$ |
14.1 |
|
|
Commodity derivatives – Revenue
|
|
|
(39.6 |
) |
|
|
(155.4 |
) |
|
Commodity derivatives – Operating costs and expenses
|
|
|
(20.0 |
) |
|
|
4.0 |
|
|
Total
|
|
$ |
(30.7 |
) |
|
$ |
(137.3 |
) |
|
Derivatives in Cash Flow
Hedging Relationships
|
Location
|
|
Gain/(Loss) Reclassified
from Accumulated Other
Comprehensive
Income/(Loss) to Income
(Effective Portion)
|
|
| |
|
|
For the Three Months
|
|
| |
|
|
Ended March 31,
|
|
| |
|
|
2012
|
|
|
2011
|
|
|
Interest rate derivatives
|
Interest expense
|
|
$ |
(2.7 |
) |
|
$ |
(1.5 |
) |
|
Commodity derivatives
|
Revenue
|
|
|
(10.0 |
) |
|
|
(69.2 |
) |
|
Commodity derivatives
|
Operating costs and expenses
|
|
|
(12.0 |
) |
|
|
0.3 |
|
|
Total
|
|
|
$ |
(24.7 |
) |
|
$ |
(70.4 |
) |
|
Derivatives in Cash Flow
Hedging Relationships
|
Location
|
|
Gain/(Loss) Recognized
in Income on Derivative
(Ineffective Portion)
|
|
| |
|
|
For the Three Months
|
|
| |
|
|
Ended March 31,
|
|
| |
|
|
2012
|
|
|
2011
|
|
|
Commodity derivatives
|
Revenue
|
|
$ |
-- |
|
|
$ |
(0.1 |
) |
|
Commodity derivatives
|
Operating costs and expenses
|
|
|
0.3 |
|
|
|
-- |
|
|
Total
|
|
|
$ |
0.3 |
|
|
$ |
(0.1 |
) |
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Over the next twelve months, we expect to reclassify $19.1 million of losses attributable to interest rate derivative instruments from accumulated other comprehensive loss to earnings as an increase in interest expense. Likewise, we expect to reclassify $59.3 million of losses attributable to commodity derivative instruments from accumulated other comprehensive loss to earnings, $18.2 million as an increase in operating costs and expenses and $41.1 million as a decrease in revenue.
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 presented:
|
Derivatives Not Designated
as Hedging Instruments
|
Location
|
|
Gain/(Loss) Recognized in
Income on Derivative
|
|
| |
|
|
For the Three Months
|
|
| |
|
|
Ended March 31,
|
|
| |
|
|
2012
|
|
|
2011
|
|
|
Interest rate derivatives
|
Interest expense
|
|
$ |
(2.2 |
) |
|
$ |
(2.1 |
) |
|
Commodity derivatives
|
Revenue
|
|
|
20.8 |
|
|
|
3.8 |
|
|
Commodity derivatives
|
Operating costs and expenses
|
|
|
(2.8 |
) |
|
|
-- |
|
|
Total
|
|
|
$ |
15.8 |
|
|
$ |
1.7 |
|
Fair Value Measurements
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, in the principal market of the asset or liability at a specified measure date. Recognized valuation techniques employ inputs such as contractual prices, quoted market prices or rates, 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.
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table sets forth, by level within the fair value hierarchy, the carrying values of our financial assets and liabilities at March 31, 2012. These assets and liabilities are measured on a recurring basis and are classified based on the lowest level of input that is significant to their respective fair value. Our assessment of the relative significance of such inputs requires judgment.
| |
|
At March 31, 2012
|
|
| |
|
Quoted Prices
|
|
|
|
|
|
|
|
|
|
|
| |
|
in Active
|
|
|
|
|
|
|
|
|
|
|
| |
|
Markets for
|
|
|
Significant
|
|
|
Significant
|
|
|
|
|
| |
|
Identical Assets
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
|
| |
|
and Liabilities
|
|
|
Inputs
|
|
|
Inputs
|
|
|
|
|
| |
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Total
|
|
|
Financial assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in equity securities – available-for-sale (1)
|
|
$ |
119.8 |
|
|
$ |
-- |
|
|
$ |
-- |
|
|
$ |
119.8 |
|
|
Interest rate derivatives
|
|
|
-- |
|
|
|
37.4 |
|
|
|
-- |
|
|
|
37.4 |
|
|
Commodity derivatives
|
|
|
34.8 |
|
|
|
50.5 |
|
|
|
4.6 |
|
|
|
89.9 |
|
|
Total
|
|
$ |
154.6 |
|
|
$ |
87.9 |
|
|
$ |
4.6 |
|
|
$ |
247.1 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate derivatives
|
|
$ |
-- |
|
|
$ |
167.1 |
|
|
$ |
-- |
|
|
$ |
167.1 |
|
|
Commodity derivatives
|
|
|
89.9 |
|
|
|
25.8 |
|
|
|
3.7 |
|
|
|
119.4 |
|
|
Total
|
|
$ |
89.9 |
|
|
$ |
192.9 |
|
|
$ |
3.7 |
|
|
$ |
286.5 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) See Note 7 for information related to our investment in Energy Transfer Equity common units, which trade on the NYSE under ticker symbol “ETE.”
|
|
The following table sets forth a reconciliation of changes in the overall fair values of our Level 3 financial assets and liabilities for the periods presented:
| |
|
|
For the Three Months
|
|
| |
|
|
Ended March 31,
|
|
| |
Location
|
|
2012
|
|
|
2011
|
|
|
Balance, January 1
|
|
|
$ |
0.4 |
|
|
$ |
(25.9 |
) |
|
Total gains (losses) included in:
|
|
|
|
|
|
|
|
|
|
|
Net income (1)
|
Revenue
|
|
|
0.5 |
|
|
|
(0.5 |
) |
|
Other comprehensive income (loss)
|
Commodity derivative instruments – changes in
fair value of cash flow hedges
|
|
|
0.5 |
|
|
|
16.2 |
|
|
Settlements
|
|
|
|
(0.5 |
) |
|
|
0.8 |
|
|
Transfers out of Level 3 (2)
|
|
|
|
-- |
|
|
|
9.8 |
|
|
Balance, March 31
|
|
|
$ |
0.9 |
|
|
$ |
0.4 |
|
| |
|
|
|
|
|
|
|
|
|
|
(1) There were unrealized gains of $0.1 million and losses of $0.2 million included in these amounts for the three months ended March 31, 2012 and 2011, respectively.
(2) Transfers out of Level 3 into Level 2 during 2011 were primarily due to the change in observability of forward NGL prices.
|
|
The following table provides quantitative information about our Level 3 fair value measurements at March 31, 2012:
| |
|
Fair Value
|
|
|
|
|
| |
|
Financial
Assets
|
|
|
Financial
Liabilities
|
|
Valuation
Techniques
|
Unobservable
Input
|
Range
|
|
Commodity derivatives – Propane
|
|
$ |
0.6 |
|
|
$ |
-- |
|
Discounted cash flow
|
Forward commodity price
|
$1.27 – $1.33 /gallon
|
|
Commodity derivatives – Crude Oil
|
|
|
3.9 |
|
|
|
3.6 |
|
Discounted cash flow
|
Forward commodity price
|
$103.02 – $104.66 /barrel
|
|
Commodity derivatives – Natural gas
|
|
|
0.1 |
|
|
|
0.1 |
|
Discounted cash flow
|
Forward commodity price
|
$2.11 – $2.22 /MMBtu
|
|
Total
|
|
$ |
4.6 |
|
|
$ |
3.7 |
|
|
|
|
We believe certain forward commodity prices are the most significant unobservable inputs in determining our recurring Level 3 fair value measurements at March 31, 2012. In general, changes in the price of the underlying commodity increases or decreases the fair value of a commodity derivative
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
depending on whether the derivative was purchased or sold. We generally expect changes in the fair value of our derivative instruments to be offset by corresponding changes in the fair value of our hedged exposures.
We have a risk management policy that covers our Level 3 commodity derivatives. Governance and oversight of risk management activities for these commodities are provided by our CEO with guidance and support from a risk management committee (“RMC”), which meets quarterly (or on a more frequent basis if needed). Members of executive management attend the RMC meetings, which are chaired by the head of our commodities risk control group. This group is responsible for preparing and distributing daily reports and risk analysis to members of the RMC and other appropriate members of management. These reports include mark-to-market valuations with the one-day and month-to-date changes in fair values. This group also develops and validates forward curves used to determine the fair values of our Level 3 commodity derivatives. These forward curves are based on published indexes, market quotes or are derived from other available inputs.
Nonfinancial Assets and Liabilities
Using appropriate valuation techniques, we reduced the carrying value of certain assets recorded as property, plant and equipment to an estimated fair value of $0.5 million based on the present value of expected future cash flows (Level 3), resulting in nonrecurring fair value adjustments (i.e., non-cash asset impairment charges) totaling $5.4 million during the three months ended March 31, 2012. These impairment charges recorded during the first quarter 2012 were recorded to reflect assets that are no longer in use or to reduce the fair value to what we can expect to receive from anticipated sales. We did not record any non-cash asset impairment charges during the three months ended March 31, 2011.
The following table summarizes our non-cash impairment charges, which are a component of operating costs and expenses, by business segment during the three months ended March 31, 2012:
|
NGL Pipelines & Services
|
|
$ |
5.1 |
|
|
Petrochemical & Refined Products Services
|
|
|
0.3 |
|
|
Total non-cash impairment charges
|
|
$ |
5.4 |
|
Forecast data and other assumptions supporting the fair value of fixed assets being tested for impairment are based on the nonfinancial assets’ highest and best use, which includes estimated probabilities where multiple outcomes are possible. Such probability weights are generally obtained from business management personnel having oversight responsibilities for the assets in question. Key commercial assumptions (e.g., anticipated operating margins, growth rates and timing of cash flows) and test results are certified by members of senior management.
Other Fair Value Information
The carrying amounts of cash and cash equivalents (including restricted cash), accounts receivable and accounts payable approximate their fair values based on their short-term nature. The estimated total fair value of our fixed-rate long-term debt obligations was approximately $16.19 billion and $15.76 billion at March 31, 2012 and December 31, 2011, respectively. The aggregate carrying value of these debt obligations was $14.58 billion and $14.33 billion at March 31, 2012 and December 31, 2011, respectively. These values are based on quoted market prices for such debt or debt of similar terms and maturities (Level 2), our credit standing and the credit standing of our counterparties. Changes in market rates of interest affect the fair value of our fixed-rate debt. The carrying values of our variable-rate long-term debt obligations approximate their fair values since the associated interest rates are market-based. We do not have any long-term investments in debt or equity securities recorded at fair value.
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Our inventory amounts by product type were as follows at the dates indicated:
| |
|
March 31,
2012
|
|
|
December 31,
2011
|
|
|
NGLs
|
|
$ |
402.7 |
|
|
$ |
563.6 |
|
|
Petrochemicals and refined products
|
|
|
433.4 |
|
|
|
443.4 |
|
|
Crude oil
|
|
|
58.7 |
|
|
|
39.2 |
|
|
Natural gas
|
|
|
39.3 |
|
|
|
65.5 |
|
|
Total
|
|
$ |
934.1 |
|
|
$ |
1,111.7 |
|
In those instances where we take ownership of inventory volumes through percent-of-liquids contracts and similar arrangements (as opposed to actually purchasing volumes for cash from third parties), these volumes are valued at market-based prices during the month in which they are acquired.
Due to fluctuating commodity prices, we recognize lower of cost or market adjustments when the carrying value of our inventories exceeds their net realizable value. These non-cash charges are a component of cost of sales in the period they are recognized. To the extent our commodity hedging strategies address inventory-related price risks and are successful, these inventory valuation adjustments are mitigated or offset. See Note 4 for a description of our commodity hedging activities.
The following table summarizes our cost of sales and lower of cost or market adjustments for the periods presented:
| |
|
For the Three Months
Ended March 31,
|
|
| |
|
2012
|
|
|
2011
|
|
|
Cost of sales (1)
|
|
$ |
9,665.8 |
|
|
$ |
8,819.3 |
|
|
Lower of cost or market adjustments
|
|
|
5.9 |
|
|
|
1.2 |
|
|
(1) Cost of sales is a component of “Operating costs and expenses,” as presented on our Unaudited Condensed Statements of Consolidated Operations. Quarter-to-quarter fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.
|
|
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 6. Property, Plant and Equipment
The historical costs of our property, plant and equipment and related accumulated depreciation balances were as follows at the dates indicated:
| |
|
Estimated
Useful Life
in Years
|
|
|
March 31,
2012
|
|
|
December 31,
2011
|
|
|
Plants, pipelines and facilities (1)
|
|
3-45 (6) |
|
|
$ |
22,567.2 |
|
|
$ |
22,354.4 |
|
|
Underground and other storage facilities (2)
|
|
5-40 (7) |
|
|
|
1,416.0 |
|
|
|
1,388.6 |
|
|
Platforms and facilities (3)
|
|
20-31 |
|
|
|
637.5 |
|
|
|
637.5 |
|
|
Transportation equipment (4)
|
|
3-10 |
|
|
|
153.1 |
|
|
|
151.5 |
|
|
Marine vessels (5)
|
|
15-30 |
|
|
|
633.5 |
|
|
|
615.9 |
|
|
Land
|
|
|
|
|
|
141.3 |
|
|
|
136.1 |
|
|
Construction in progress
|
|
|
|
|
|
2,810.8 |
|
|
|
2,145.6 |
|
|
Total
|
|
|
|
|
|
28,359.4 |
|
|
|
27,429.6 |
|
|
Less accumulated depreciation
|
|
|
|
|
|
5,449.1 |
|
|
|
5,238.0 |
|
|
Property, plant and equipment, net
|
|
|
|
|
$ |
22,910.3 |
|
|
$ |
22,191.6 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
(1) Plants and pipelines include processing plants; NGL, natural gas, crude oil and petrochemical and refined products 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; above ground storage tanks; water wells and related assets.
(3) Platforms and facilities include offshore platforms and related facilities and other associated assets located in the Gulf of Mexico.
(4) Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations.
(5) Marine vessels include tow boats, barges and related equipment used in our marine transportation business.
(6) In general, the estimated useful lives of major assets within this category are: processing plants, 20-35 years; pipelines and related equipment, 5-45 years; terminal facilities, 10-35 years; office furniture and equipment, 3-20 years; buildings, 20-40 years; and laboratory and shop equipment, 5-35 years.
(7) In general, the estimated useful lives of assets within this category are: underground storage facilities, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 years.
|
|
The following table summarizes our depreciation expense and capitalized interest amounts for the periods presented:
| |
|
For the Three Months
|
|
| |
|
Ended March 31,
|
|
| |
|
2012
|
|
|
2011
|
|
|
Depreciation expense (1)
|
|
$ |
212.0 |
|
|
$ |
186.5 |
|
|
Capitalized interest (2)
|
|
|
30.6 |
|
|
|
17.2 |
|
|
(1) Depreciation expense is a component of “Costs and expenses” as presented on our Unaudited Condensed Statements of Consolidated Operations.
(2) Capitalized interest reduces interest expense during the period it is recorded and increases the carrying value of the associated asset, which will subsequently increase depreciation expense once the asset is placed in service.
|
|
Asset Retirement Obligations
We record asset retirement obligations (“AROs”) related to legal requirements to perform retirement activities as specified in contractual arrangements and/or governmental regulations. The following table presents information regarding our AROs since December 31, 2011:
|
ARO liability balance, December 31, 2011
|
|
$ |
112.0 |
|
|
Liabilities incurred during period
|
|
|
0.8 |
|
|
Liabilities settled during period
|
|
|
(1.6 |
) |
|
Revisions in estimated cash flows
|
|
|
3.4 |
|
|
Accretion expense
|
|
|
1.4 |
|
|
ARO liability balance, March 31, 2012
|
|
$ |
116.0 |
|
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Property, plant and equipment at March 31, 2012 and December 31, 2011 includes $37.2 million and $37.7 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset. The following table presents our accretion expense forecasts for AROs for the periods presented:
|
Remainder of
2012
|
|
|
2013
|
|
|
2014
|
|
|
2015
|
|
|
2016
|
|
| $ |
4.0 |
|
|
$ |
5.6 |
|
|
$ |
6.0 |
|
|
$ |
5.8 |
|
|
$ |
6.1 |
|
Certain of our unconsolidated affiliates have AROs recorded at March 31, 2012 and December 31, 2011 relating to contractual agreements and regulatory requirements. These amounts are immaterial to our consolidated financial statements.
Note 7. Investments in Unconsolidated Affiliates
The following table presents our investments in unconsolidated affiliates by business segment at the dates indicated. Unless noted otherwise, we account for these investments using the equity method.
| |
|
Ownership
Interest at
March 31,
2012
|
|
|
March 31,
2012
|
|
|
December 31,
2011
|
|
|
NGL Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
Venice Energy Service Company, L.L.C.
|
|
13.1% |
|
|
$ |
34.8 |
|
|
$ |
35.5 |
|
|
K/D/S Promix, L.L.C.
|
|
50% |
|
|
|
41.6 |
|
|
|
40.7 |
|
|
Baton Rouge Fractionators LLC
|
|
32.2% |
|
|
|
20.9 |
|
|
|
21.0 |
|
|
Skelly-Belvieu Pipeline Company, L.L.C.
|
|
50% |
|
|
|
39.6 |
|
|
|
35.0 |
|
|
Texas Express Pipeline LLC
|
|
45% |
|
|
|
49.8 |
|
|
|
13.9 |
|
|
Onshore Natural Gas Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
Evangeline (1)
|
|
49.5% |
|
|
|
3.9 |
|
|
|
4.4 |
|
|
White River Hub, LLC
|
|
50% |
|
|
|
25.4 |
|
|
|
25.7 |
|
|
Onshore Crude Oil Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
Seaway Crude Pipeline LLC
|
|
50% |
|
|
|
164.6 |
|
|
|
170.7 |
|
|
Offshore Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”)
|
|
36% |
|
|
|
52.7 |
|
|
|
55.4 |
|
|
Cameron Highway Oil Pipeline Company
|
|
50% |
|
|
|
220.8 |
|
|
|
222.8 |
|
|
Deepwater Gateway, L.L.C.
|
|
50% |
|
|
|
93.8 |
|
|
|
94.6 |
|
|
Neptune Pipeline Company, L.L.C.
|
|
25.7% |
|
|
|
50.0 |
|
|
|
51.1 |
|
|
Southeast Keathley Canyon Pipeline Company L.L.C.
|
|
50% |
|
|
|
33.7 |
|
|
|
1.0 |
|
|
Petrochemical & Refined Products Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
Baton Rouge Propylene Concentrator, LLC
|
|
30% |
|
|
|
9.0 |
|
|
|
9.5 |
|
|
Centennial Pipeline LLC (“Centennial”)
|
|
50% |
|
|
|
51.4 |
|
|
|
51.8 |
|
|
Other (2)
|
|
Various
|
|
|
|
3.3 |
|
|
|
3.4 |
|
|
Other Investments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy Transfer Equity (3)
|
|
1.3% |
|
|
|
-- |
|
|
|
1,023.1 |
|
|
Total
|
|
|
|
|
$ |
895.3 |
|
|
$ |
1,859.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Evangeline refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively.
(2) Other unconsolidated affiliates include a 50% interest in a propylene pipeline extending from Mont Belvieu, Texas to La Porte, Texas and a 25% interest in a company that provides logistics communications solutions between petroleum pipelines and their customers.
(3) Effective January 18, 2012, our investment in Energy Transfer Equity common units is no longer accounted for using the equity method (see below).
|
|
At December 31, 2011, we owned 29,303,514 common units of Energy Transfer Equity. On January 18, 2012, we sold 22,762,636 of these common units in a private transaction, which generated cash proceeds of approximately $825.1 million and a gain on the sale of $27.5 million. Following the completion of the January 18 transaction, our ownership percentage in Energy Transfer Equity was below 3%, and we discontinued using the equity method to account for this investment and began accounting for the remaining units as an investment in available-for-sale equity securities. For the period January 1, 2012 to January 18, 2012, we recorded an estimated $2.4 million of equity earnings from Energy Transfer
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Equity, which is presented as a component of “Operating income.” Following the January 18 transaction, we sold an additional 3,569,232 Energy Transfer Equity common units through March 31, which generated cash proceeds of approximately $150.8 million and aggregate gains on these sales of $25.8 million. Gains on the first quarter of 2012 sales are presented as a component of “Other income.” Proceeds from these sales were used for general company purposes, including funding capital expenditures.
At March 31, 2012, we owned 2,971,646 common units of Energy Transfer Equity, which represented approximately 1.3% of its common units outstanding on April 3, 2012. The $119.8 million carrying value of these available-for-sale equity securities is a component of “Prepaid and other current assets” as presented on our Unaudited Condensed Consolidated Balance Sheet at March 31, 2012. Accumulated other comprehensive income (loss) at March 31, 2012 includes $15.8 million of unrealized gains related to these available-for-sale equity securities. We sold the remainder of our investment in Energy Transfer Equity in April 2012.
The following table presents our equity in income (loss) of unconsolidated affiliates by business segment for the periods presented:
| |
|
For the Three Months
|
|
| |
|
Ended March 31,
|
|
| |
|
2012
|
|
|
2011
|
|
|
NGL Pipelines & Services
|
|
$ |
5.2 |
|
|
$ |
5.9 |
|
|
Onshore Natural Gas Pipelines & Services
|
|
|
1.4 |
|
|
|
1.2 |
|
|
Onshore Crude Oil Pipelines & Services
|
|
|
0.5 |
|
|
|
(0.5 |
) |
|
Offshore Pipelines & Services
|
|
|
6.9 |
|
|
|
8.3 |
|
|
Petrochemical & Refined Products Services
|
|
|
(6.5 |
) |
|
|
(5.0 |
) |
|
Other Investments (1)
|
|
|
2.4 |
|
|
|
6.3 |
|
|
Total
|
|
$ |
9.9 |
|
|
$ |
16.2 |
|
| |
|
|
(1) With respect to the first quarter of 2012, amount presented reflects our estimated equity in the income of Energy Transfer Equity from January 1, 2012 to January 18, 2012.
|
|
The following table presents unamortized excess cost amounts by business segment at the dates indicated:
| |
|
March 31,
2012
|
|
|
December 31,
2011
|
|
|
NGL Pipelines & Services
|
|
$ |
24.5 |
|
|
$ |
24.7 |
|
|
Onshore Crude Oil Pipelines & Services
|
|
|
19.0 |
|
|
|
19.2 |
|
|
Offshore Pipelines & Services
|
|
|
14.5 |
|
|
|
14.8 |
|
|
Petrochemical & Refined Products Services
|
|
|
2.8 |
|
|
|
2.9 |
|
|
Other Investments (1)
|
|
|
-- |
|
|
|
1,119.0 |
|
|
Total
|
|
$ |
60.8 |
|
|
$ |
1,180.6 |
|
| |
|
|
|
|
|
|
|
|
|
(1) On January 18, 2012, we discontinued using the equity method to account for our investment in Energy Transfer Equity common units and began accounting for them as available-for-sale equity securities. As a result, we no longer have any excess cost amounts associated with this investment.
|
|
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table presents our amortization of excess cost amounts by business segment for the periods presented:
| |
|
For the Three Months
|
|
| |
|
Ended March 31,
|
|
| |
|
2012
|
|
|
2011
|
|
|
NGL Pipelines & Services
|
|
$ |
0.2 |
|
|
$ |
0.3 |
|
|
Onshore Crude Oil Pipelines & Services
|
|
|
0.2 |
|
|
|
0.2 |
|
|
Offshore Pipelines & Services
|
|
|
0.3 |
|
|
|
0.3 |
|
|
Petrochemical & Refined Products Services
|
|
|
0.1 |
|
|
|
-- |
|
|
Other Investments (1)
|
|
|
0.3 |
|
|
|
9.1 |
|
|
Total
|
|
$ |
1.1 |
|
|
$ |
9.9 |
|
| |
|
|
|
|
|
|
|
|
|
(1) Reflects amortization of excess cost amounts related to our investment in Energy Transfer Equity through January 18, 2012. We ceased using the equity method to account for this investment on January 18, 2012.
|
|
In April 2012, we, along with Anadarko Petroleum Corporation and DCP Midstream, LLC formed a new joint venture, Front Range Pipeline LLC (“Front Range”), to design and construct a new NGL pipeline that will originate in the Denver-Julesburg Basin (the “DJ Basin”) in Weld County, Colorado and extend approximately 435 miles to Skellytown in Carson County, Texas. Each party holds a one-third ownership interest in the joint venture. The Front Range Pipeline, with connections to our Mid-America Pipeline System and the Texas Express Pipeline, is expected to provide producers in the DJ Basin with access to the Gulf Coast, the largest NGL market in the U.S. Depending on shipper interest in a binding open commitment period that commenced in April 2012, initial capacity on the Front Range Pipeline is expected to be approximately 150 MBPD, which can be readily expanded to approximately 230 MBPD. We will construct and operate the pipeline, which is expected to begin service in the fourth quarter of 2013.
Summarized Income Statement Information of Unconsolidated Affiliates
The following table presents unaudited income statement information (on a 100% basis) of our unconsolidated affiliates, aggregated by the business segments to which they relate, for the periods presented:
| |
|
Summarized Income Statement Information for the Three Months Ended
|
|
| |
|
March 31, 2012
|
|
|
March 31, 2011
|
|
| |
|
|
|
|
Operating
|
|
|
Net
|
|
|
|
|
|
Operating
|
|
|
Net
|
|
| |
|
Revenues
|
|
|
Income (Loss)
|
|
|
Income (Loss)
|
|
|
Revenues
|
|
|
Income (Loss)
|
|
|
Income (Loss)
|
|
|
NGL Pipelines & Services
|
|
$ |
110.9 |
|
|
$ |
27.0 |
|
|
$ |
27.0 |
|
|
$ |
100.1 |
|
|
$ |
23.4 |
|
|
$ |
23.4 |
|
|
Onshore Natural Gas Pipelines & Services
|
|
|
30.9 |
|
|
|
2.6 |
|
|
|
2.6 |
|
|
|
35.5 |
|
|
|
2.6 |
|
|
|
2.6 |
|
|
Onshore Crude Oil Pipelines & Services
|
|
|
12.3 |
|
|
|
0.8 |
|
|
|
0.8 |
|
|
|
11.2 |
|
|
|
0.5 |
|
|
|
0.5 |
|
|
Offshore Pipelines & Services
|
|
|
41.1 |
|
|
|
19.1 |
|
|
|
18.4 |
|
|
|
46.3 |
|
|
|
18.9 |
|
|
|
18.7 |
|
|
Petrochemical & Refined Products Services
|
|
|
5.4 |
|
|
|
(9.4 |
) |
|
|
(11.4 |
) |
|
|
10.1 |
|
|
|
(7.0 |
) |
|
|
(9.2 |
) |
|
Other Investments (1)
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
1,989.1 |
|
|
|
364.2 |
|
|
|
88.6 |
|
|
(1) On January 18, 2012, we discontinued using the equity method to account for our investment in Energy Transfer Equity common units. As such, income statement data for Energy Transfer Equity is not presented for the three months ended March 31, 2012. For the three months ended March 31, 2011, net income for Energy Transfer Equity represents net income attributable to their partners.
|
|
The credit agreements of Poseidon and Centennial restrict their ability to pay cash dividends if a default or event of default (as defined in each credit agreement) has occurred and is continuing at the time such payments are scheduled to be paid. These businesses were in compliance with the terms of their credit agreements at March 31, 2012.
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 8. Intangible Assets and Goodwill
Identifiable Intangible Assets
The following table summarizes our intangible assets by business segment at the dates indicated:
| |
|
March 31, 2012
|
|
|
December 31, 2011
|
|
| |
|
Gross
Value
|
|
|
Accum.
Amort.
|
|
|
Carrying
Value
|
|
|
Gross
Value
|
|
|
Accum.
Amort.
|
|
|
Carrying
Value
|
|
|
NGL Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer relationship intangibles
|
|
$ |
340.8 |
|
|
$ |
(133.0 |
) |
|
$ |
207.8 |
|
|
$ |
340.8 |
|
|
$ |
(128.2 |
) |
|
$ |
212.6 |
|
|
Contract-based intangibles
|
|
|
284.7 |
|
|
|
(142.4 |
) |
|
|
142.3 |
|
|
|
298.4 |
|
|
|
(169.7 |
) |
|
|
128.7 |
|
|
Segment total
|
|
|
625.5 |
|
|
|
(275.4 |
) |
|
|
350.1 |
|
|
|
639.2 |
|
|
|
(297.9 |
) |
|
|
341.3 |
|
|
Onshore Natural Gas Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer relationship intangibles
|
|
|
1,163.6 |
|
|
|
(220.2 |
) |
|
|
943.4 |
|
|
|
1,163.6 |
|
|
|
(209.7 |
) |
|
|
953.9 |
|
|
Contract-based intangibles
|
|
|
466.1 |
|
|
|
(296.2 |
) |
|
|
169.9 |
|
|
|
464.8 |
|
|
|
(290.9 |
) |
|
|
173.9 |
|
|
Segment total
|
|
|
1,629.7 |
|
|
|
(516.4 |
) |
|
|
1,113.3 |
|
|
|
1,628.4 |
|
|
|
(500.6 |
) |
|
|
1,127.8 |
|
|
Onshore Crude Oil Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer relationship intangibles
|
|
|
9.7 |
|
|
|
(4.3 |
) |
|
|
5.4 |
|
|
|
9.7 |
|
|
|
(4.1 |
) |
|
|
5.6 |
|
|
Contract-based intangibles
|
|
|
0.4 |
|
|
|
(0.2 |
) |
|
|
0.2 |
|
|
|
0.4 |
|
|
|
(0.2 |
) |
|
|
0.2 |
|
|
Segment total
|
|
|