UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 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, 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 o
 
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 895,642,295 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 October 31, 2012.  Our common units trade on the New York Stock Exchange under the ticker symbol "EPD."

ENTERPRISE PRODUCTS PARTNERS L.P.
TABLE OF CONTENTS

 
 
Page No.
 
 
 
 
 
 
 
 
 
 
 
 
 
       5.  Inventories
 
 
 
 
       9.  Debt Obligations
 
 
 
 
 
 
 
 
 
 
 
 
 
 






PART I.  FINANCIAL INFORMATION.

Item 1.  Financial Statements.

ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)

 
  
September 30,
    
December 31,
  
ASSETS
  
2012
    
2011
  
Current assets:
  
   
 
Cash and cash equivalents
  
$
14.5
    
$
19.8
  
Restricted cash
    
18.8
      
38.5
  
Accounts receivable – trade, net of allowance for doubtful accounts of $13.2 at
   September 30, 2012 and $13.4 at December 31, 2011
    
4,389.4
      
4,501.8
  
Accounts receivable – related parties
    
10.4
      
43.5
  
Inventories
    
1,069.2
      
1,111.7
  
Prepaid and other current assets
    
390.8
      
353.4
  
Total current assets
    
5,893.1
      
6,068.7
  
Property, plant and equipment, net
    
24,311.5
      
22,191.6
  
Investments in unconsolidated affiliates
    
1,160.4
      
1,859.6
  
Intangible assets, net of accumulated amortization of $1,022.4 at September 30,
   2012 and $990.4 at December 31, 2011
    
1,596.1
      
1,656.2
  
Goodwill
    
2,092.3
      
2,092.3
  
Other assets
    
224.4
      
256.7
  
Total assets
  
$
35,277.8
    
$
34,125.1
  
 
                
LIABILITIES AND EQUITY
                
Current liabilities:
                
Current maturities of debt
  
$
1,200.0
    
$
500.0
  
Accounts payable – trade
    
798.6
      
773.0
  
Accounts payable – related parties
    
112.6
      
211.6
  
Accrued product payables
    
4,318.5
      
5,047.1
  
Accrued interest
    
188.2
      
288.1
  
Other current liabilities
    
617.9
      
612.6
  
Total current liabilities
    
7,235.8
      
7,432.4
  
Long-term debt (see Note 9)
    
14,747.2
      
14,029.4
  
Deferred tax liabilities
    
20.8
      
91.2
  
Other long-term liabilities
    
216.1
      
352.8
  
Commitments and contingencies (see Note 14)
                
Equity: (see Note 10)
                
Partners' equity:
                
Limited partners:
                
Common units (895,643,795 units outstanding at September 30, 2012
and 881,620,418 units outstanding at December 31, 2011)
    
13,219.4
      
12,346.3
  
Class B units (4,520,431 units outstanding at September 30, 2012
and December 31, 2011)
    
118.5
      
118.5
  
Accumulated other comprehensive loss
    
(388.3
)
    
(351.4
)
Total  partners' equity
    
12,949.6
      
12,113.4
  
Noncontrolling interests
    
108.3
      
105.9
  
Total equity
    
13,057.9
      
12,219.3
  
Total liabilities and equity
  
$
35,277.8
    
$
34,125.1
  







See Notes to Unaudited Condensed Consolidated Financial Statements.
ENTERPRISE PRODUCTS PARTNERS L.P.
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,
  
 
  
2012
    
2011
    
2012
    
2011
  
Revenues:
  
   
   
   
 
Third parties
  
$
10,461.2
    
$
11,163.2
    
$
31,447.1
    
$
32,169.1
  
Related parties
    
7.5
      
163.9
      
63.9
      
558.2
  
Total revenues (see Note 11)
    
10,468.7
      
11,327.1
      
31,511.0
      
32,727.3
  
Costs and expenses:
                                
Operating costs and expenses:
                                
Third parties
    
9,456.6
      
10,146.2
      
28,563.4
      
29,398.3
  
Related parties
    
203.2
      
458.4
      
573.1
      
1,276.7
  
Total operating costs and expenses
    
9,659.8
      
10,604.6
      
29,136.5
      
30,675.0
  
General and administrative costs:
                                
Third parties
    
18.8
      
20.0
      
59.1
      
49.2
  
Related parties
    
22.6
      
30.0
      
71.1
      
89.1
  
Total general and administrative costs
    
41.4
      
50.0
      
130.2
      
138.3
  
Total costs and expenses (see Note 11)
    
9,701.2
      
10,654.6
      
29,266.7
      
30,813.3
  
Equity in income of unconsolidated affiliates
    
21.0
      
8.6
      
42.2
      
35.9
  
Operating income
    
788.5
      
681.1
      
2,286.5
      
1,949.9
  
Other income (expense):
                                
Interest expense
    
(199.7
)
    
(189.0
)
    
(572.8
)
    
(561.1
)
Interest income
    
0.3
      
0.3
      
0.7
      
0.9
  
Other, net (see Note 2)
    
1.2
      
(1.3
)
    
72.7
      
(1.1
)
Total other expense, net
    
(198.2
)
    
(190.0
)
    
(499.4
)
    
(561.3
)
Income before income taxes
    
590.3
      
491.1
      
1,787.1
      
1,388.6
  
Benefit from (provision for) income taxes (see Note 2)
    
(2.4
)
    
(11.6
)
    
23.5
      
(26.1
)
Net income
    
587.9
      
479.5
      
1,810.6
      
1,362.5
  
Net income attributable to noncontrolling interests (see Note 10)
    
(1.1
)
    
(8.1
)
    
(6.2
)
    
(36.7
)
Net income attributable to limited partners
  
$
586.8
    
$
471.4
    
$
1,804.4
    
$
1,325.8
  
 
                                
Earnings per unit: (see Note 13)
                                
Basic earnings per unit
  
$
0.68
    
$
0.57
    
$
2.10
    
$
1.62
  
Diluted earnings per unit
  
$
0.66
    
$
0.55
    
$
2.03
    
$
1.55
  




















See Notes to Unaudited Condensed Consolidated Financial Statements.
ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED
COMPREHENSIVE INCOME
(Dollars in millions)

 
  
For the Three Months
    
For the Nine Months
  
 
  
Ended September 30,
    
Ended September 30,
  
 
  
2012
    
2011
    
2012
    
2011
  
 
  
   
   
   
 
Net income
  
$
587.9
    
$
479.5
    
$
1,810.6
    
$
1,362.5
  
Other comprehensive income (loss):
                                
Cash flow hedges:
                                
Commodity derivative instruments:
                                
Changes in fair value of cash flow hedges
    
(58.5
)
    
(6.1
)
    
(13.1
)
    
(179.2
)
Reclassification of gains and losses to net income
    
0.9
      
35.1
      
37.1
      
178.8
  
Interest rate derivative instruments:
                                
Changes in fair value of cash flow hedges
    
(20.2
)
    
(260.1
)
    
(75.3
)
    
(306.1
)
Reclassification of gains and losses to net income
    
4.5
      
1.6
      
10.9
      
4.6
  
Total cash flow hedges
    
(73.3
)
    
(229.5
)
    
(40.4
)
    
(301.9
)
Change in funded status of pension and postretirement plans, net of tax
    
3.7
      
--
      
2.5
      
(0.6
)
Proportionate share of other comprehensive income (loss) of unconsolidated affiliate
    
--
      
--
      
1.0
      
(0.7
)
Total other comprehensive loss
    
(69.6
)
    
(229.5
)
    
(36.9
)
    
(303.2
)
Comprehensive income
    
518.3
      
250.0
      
1,773.7
      
1,059.3
  
Comprehensive income attributable to noncontrolling interests
    
(1.1
)
    
(8.1
)
    
(6.2
)
    
(36.7
)
Comprehensive income attributable to limited partners
  
$
517.2
    
$
241.9
    
$
1,767.5
    
$
1,022.6
  






























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 Nine Months
  
 
  
Ended September 30,
  
 
  
2012
    
2011
  
Operating activities:
  
   
 
Net income
  
$
1,810.6
    
$
1,362.5
  
Reconciliation of net income to net cash flows provided by operating activities:
                
Depreciation, amortization and accretion
    
817.9
      
739.2
  
Non-cash asset impairment charges
    
57.6
      
5.2
  
Equity in income of unconsolidated affiliates
    
(42.2
)
    
(35.9
)
Distributions received from unconsolidated affiliates
    
67.5
      
122.5
  
Gains related to asset sales (see Note 15)
    
(4.1
)
    
(0.6
)
Gains related to property damage insurance recoveries (see Note 16)
    
(30.0
)
    
--
  
Gains related to sales of Energy Transfer Equity common units (see Note 7)
    
(68.8
)
    
(24.8
)
Deferred income tax expense (benefit)
    
(67.9
)
    
5.5
  
Changes in fair market value of derivative instruments
    
(15.9
)
    
(6.8
)
Net effect of changes in operating accounts (see Note 15)
    
(910.2
)
    
61.6
  
Other operating activities
    
1.3
      
(0.2
)
Net cash flows provided by operating activities
    
1,615.8
      
2,228.2
  
Investing activities:
                
Capital expenditures
    
(2,716.1
)
    
(2,792.2
)
Contributions in aid of construction costs
    
18.2
      
12.3
  
Decrease in restricted cash
    
19.7
      
20.1
  
Investments in unconsolidated affiliates
    
(351.8
)
    
(11.9
)
Proceeds from asset sales (see Note 15)
    
1,137.4
      
440.5
  
Proceeds from property damage insurance recoveries (see Note 16)
    
30.0
      
--
  
Other investing activities
    
(32.4
)
    
(7.4
)
Cash used in investing activities
    
(1,895.0
)
    
(2,338.6
)
Financing activities:
                
Borrowings under debt agreements
    
7,141.4
      
6,565.1
  
Repayments of debt
    
(5,716.0
)
    
(4,989.3
)
Debt issuance costs
    
(20.7
)
    
(33.9
)
Monetization of interest rate derivative instruments (see Note 4)
    
(147.8
)
    
(23.2
)
Cash distributions paid to limited partners (see Note 10)
    
(1,613.4
)
    
(1,459.7
)
Cash distributions paid to noncontrolling interests (see Note 10)
    
(11.3
)
    
(52.0
)
Cash contributions from noncontrolling interests (see Note 10)
    
6.5
      
4.7
  
Net cash proceeds from issuance of common units
    
654.8
      
67.1
  
Other financing activities
    
(19.6
)
    
(4.8
)
Cash provided by financing activities
    
273.9
      
74.0
  
Net change in cash and cash equivalents
    
(5.3
)
    
(36.4
)
Cash and cash equivalents, January 1
    
19.8
      
65.5
  
Cash and cash equivalents, September 30
  
$
14.5
    
$
29.1
  













See Notes to Unaudited Condensed Consolidated Financial Statements.
ENTERPRISE PRODUCTS PARTNERS L.P.
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
    
1,804.4
      
--
      
6.2
      
1,810.6
  
Cash distributions paid to limited partners
    
(1,613.4
)
    
--
      
--
      
(1,613.4
)
Cash distributions paid to noncontrolling interests
    
--
      
--
      
(11.3
)
    
(11.3
)
Cash contributions from noncontrolling interests
    
--
      
--
      
6.5
      
6.5
  
Net cash proceeds from issuance of common units
    
654.8
      
--
      
--
      
654.8
  
Amortization of fair value of equity-based awards
    
45.9
      
--
      
--
      
45.9
  
Cash flow hedges
    
--
      
(40.4
)
    
--
      
(40.4
)
Other
    
(18.6
)
    
3.5
      
1.0
      
(14.1
)
Balance, September 30, 2012
  
$
13,337.9
    
$
(388.3
)
  
$
108.3
    
$
13,057.9
  


 
  
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
    
1,325.8
      
--
      
36.7
      
1,362.5
  
Cash distributions paid to limited partners
    
(1,459.7
)
    
--
      
--
      
(1,459.7
)
Cash distributions paid to noncontrolling interests
    
--
      
--
      
(52.0
)
    
(52.0
)
Cash contributions from noncontrolling interests
    
--
      
--
      
4.7
      
4.7
  
Net cash proceeds from issuance of common units
    
67.1
      
--
      
--
      
67.1
  
Amortization of fair value of equity-based awards
    
37.9
      
--
      
0.1
      
38.0
  
Issuance of common units pursuant to Duncan Merger (see Note 1)
    
402.8
      
(1.1
)
    
(401.7
)
    
--
  
Cash flow hedges
    
--
      
(301.9
)
    
--
      
(301.9
)
Other
    
(5.1
)
    
(1.3
)
    
(1.6
)
    
(8.0
)
Balance, September 30, 2011
  
$
11,775.5
    
$
(336.8
)
  
$
112.8
    
$
11,551.5
  



















See Notes to Unaudited Condensed Consolidated Financial Statements.
6
Table of Contents
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.

KEY REFERENCES USED IN THESE
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 Texas 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, a Texas corporation, 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. 

In April 2011, we, our general partner, EPD MergerCo LLC ("Duncan MergerCo," 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").  In September 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 "Holdings Merger" mean the merger of Enterprise GP Holdings L.P. with and into a wholly owned subsidiary of ours, with our subsidiary surviving such merger.  The Holdings Merger and related transactions were completed in November 2010.

References to "TEPPCO" mean TEPPCO Partners, L.P. prior to its merger with one of our subsidiaries in October 2009 (the "TEPPCO Merger").

References to "Energy Transfer Equity" mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries.  We sold the remainder of our limited partner interests in Energy Transfer Equity in April 2012 (see Note 7).


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
7
Table of Contents
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, refined products and 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 include approximately 50,700 miles of onshore and offshore pipelines; 190 million barrels ("MMBbls") of storage capacity for NGLs, crude oil, refined products and petrochemicals; and 14 billion cubic feet ("Bcf") of natural gas storage capacity. 

Our integrated midstream energy operations include: natural gas gathering, treating, processing, transportation and storage; NGL transportation, fractionation, storage, and import and export terminals; crude oil and refined products transportation, storage, and terminals; 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 five reportable business segments: (i) NGL Pipelines & Services; (ii) Onshore Natural Gas Pipelines & Services; (iii) Onshore Crude Oil Pipelines & Services; (iv) Offshore Pipelines & Services; and (v) Petrochemical & Refined Products Services.  All activities included in our former sixth reportable business segment, Other Investments, ceased on January 18, 2012, which was the date we discontinued using the equity method to account for our previously held investment in Energy Transfer Equity (see "Liquidation of Investment in Energy Transfer Equity" under Note 7).

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 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.


Note 2.  General Accounting Matters

Our results of operations for the three and nine months ended September 30, 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").
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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

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.

For certain of our physical forward commodity 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 such physical contract transactions are recognized during the period when volumes are physically delivered or received.  Physical forward commodity contracts subject to the exception are evaluated for the probability of future delivery and are periodically back-tested once the forecasted period has passed to determine whether similar forward contracts are probable of physical delivery.

See Note 4 for additional information regarding our derivative instruments and related interest rate and commodity hedging activities.
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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

For the nine months ended September 30, 2012, we recognized a net income tax benefit of $23.5 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 during the first quarter of 2012, partially offset by accruals for the Texas Margin Tax.  The $46.5 million net income tax 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 conversions.

Other Non-Operating Income

The following table presents the components of "Other, net" as presented on our Unaudited Condensed Statements of Consolidated Operations for the periods presented:

 
  
For the Three Months
    
For the Nine Months
  
 
  
Ended September 30,
    
Ended September 30,
  
 
  
2012
    
2011
    
2012
    
2011
  
Gain on sales of available-for-sale equity securities of
   Energy Transfer Equity (1)
  
$
--
    
$
--
    
$
68.8
    
$
--
  
Distribution income from Energy Transfer Equity
    
--
      
--
      
4.1
      
--
  
Other
    
1.2
      
(1.3
)
    
(0.2
)
    
(1.1
)
Total
  
$
1.2
    
$
(1.3
)
  
$
72.7
    
$
(1.1
)
 
                                
(1)   See Note 7 for information regarding the liquidation of our investment in limited partnership units of 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 disclosures related to offsetting assets and liabilities.  We do not believe that adoption of this new guidance will have a material impact on our consolidated financial statements.
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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Note 3. Equity-based Awards

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
    
For the Nine Months
  
 
  
Ended September 30,
    
Ended September 30,
  
 
  
2012
    
2011
    
2012
    
2011
  
Restricted common unit awards
  
$
13.8
    
$
11.9
    
$
44.3
    
$
35.4
  
Unit option awards
    
0.2
      
0.7
      
1.2
      
2.4
  
Other (1)
    
0.2
      
0.2
      
1.6
      
--
  
Total compensation expense
  
$
14.2
    
$
12.8
    
$
47.1
    
$
37.8
  
 
                                
(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 September 30, 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 September 30, 2012, a total of 842,359 and 5,180,780 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. 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 unit awards issued in 2012 generally vest at a rate of 25% per year beginning one year after the grant date. 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.
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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 (2,3)
    
1,556,038
    
$
51.94
  
Vested (3)
    
(1,264,483
)
  
$
34.76
  
Forfeited
    
(225,390
)
  
$
40.05
  
Restricted common units at September 30, 2012
    
3,934,381
    
$
40.72
  
 
                
(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 $80.8 million based on a grant date market price ranging from $51.92 to $53.54 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
    
For the Nine Months
  
 
  
Ended September 30,
    
Ended September 30,
  
 
  
2012
    
2011
    
2012
    
2011
  
Cash distributions paid to restricted common unit holders
  
$
2.5
    
$
2.4
    
$
7.9
    
$
7.2
  
Total intrinsic value of our restricted common unit awards that vested during period
    
1.5
      
2.3
      
64.2
      
37.5
  

For the EPCO group of companies, the unrecognized compensation cost associated with restricted common unit awards was an aggregate $73.0 million at September 30, 2012, of which our allocated share of the cost is currently estimated to be $69.3 million. We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 1.9 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 award may be no less than the market price of our common units on the date of grant. In general, unit option awards 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 option awards 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).
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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The fair value of each unit option award is estimated on the date of grant using a Black-Scholes option pricing model. Compensation expense recorded in connection with unit option awards are based on the grant date fair value, net of an allowance for estimated forfeitures, over the requisite service or vesting period. The following table presents unit option award 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 option awards at December 31, 2011
    
3,753,420
    
$
28.08
      
2.6
    
$
11.1
  
Exercised
    
(712,280
)
  
$
30.76
                  
Forfeited
    
(250,000
)
  
$
27.45
                  
Unit option awards at September 30, 2012
    
2,791,140
    
$
27.45
      
2.2
    
$
16.1
  
Options exercisable at September 30, 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 option awards during the periods presented:

 
  
For the Three Months
    
For the Nine Months
  
 
  
Ended September 30,
    
Ended September 30,
  
 
  
2012
    
2011
    
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 $1.5 million at September 30, 2012, of which our allocated share of the cost is currently estimated to be $1.4 million. We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 0.9 years.

Unit Appreciation Rights

At December 31, 2011, there were 107,328 UARs outstanding that had been granted under the 2006 Plan. The accrued liability for UARs at December 31, 2011 was $0.5 million. All of these awards vested in May 2012. The accrued liability for UARs in May 2012 (i.e., immediately before vesting) was $1.4 million. While these awards were outstanding, they were accounted for as liability awards.


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.

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 derivative
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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
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 Hedging Activities

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 September 30, 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
  
1/2011 to 2/2016
3.2% to 1.4%
Fair value hedge
   Undesignated swaps
6 floating-to-fixed swaps
  
$
600.0
  
5/2010 to 7/2014
0.5% to 2.0%
Mark-to-market

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.  As fair value hedges, the unamortized portion of these gains are a component of long-term debt (see Note 9) and are being 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 September 30, 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
16 forward starting swaps
  
$
1,000.0
      
3/2013
      
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 amount of $500.0 million, resulting in cash losses totaling $115.3 million.  These losses are reflected in accumulated other comprehensive loss and are being amortized to earnings (as an increase in interest expense) over the forecasted hedge period of ten years using the effective interest method.

In connection with EPO's issuance of Senior Notes FF and Senior Notes GG in August 2012 (see Note 9), we settled seven forward starting swaps having an aggregate notional amount of $350.0 million, resulting in cash losses of $70.2 million.  These losses are reflected in accumulated other comprehensive loss and will be amortized to earnings (as an increase in interest expense) over the forecasted hedged period of ten years using the effective interest method.

Although we incurred cash losses upon settlement of our forward starting swaps in February 2012 and August 2012, we benefited from the exceptionally low interest rate environment during these periods relative to the interest rates in effect at the time we entered into the swaps.
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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
Commodity Hedging Activities

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 September 30, 2012 (volume measures as noted):

 
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") (Bcf) (3)
7.2
n/a
Cash flow hedge
Forecasted sales of NGLs (MMBbls) (4)
0.8
n/a
Cash flow hedge
Octane enhancement:
 
 
 
Forecasted purchases of NGLs (MMBbls)
0.4
0.4
Cash flow hedge
Forecasted sales of octane enhancement products (MMBbls)
2.3
0.5
Cash flow hedge
Natural gas marketing:
 
 
 
Forecasted sales of natural gas (Bcf)
3.1
n/a
Cash flow hedge
Natural gas storage inventory management activities (Bcf)
14.5
n/a
Fair value hedge
NGL marketing:
 
 
 
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)
1.5
n/a
Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)
4.4
0.1
Cash flow hedge
Refined products marketing:
 
 
 
Forecasted purchases of refined products (MMBbls)
0.4
n/a
Cash flow hedge
Forecasted sales of refined products (MMBbls)
0.8
n/a
Cash flow hedge
Crude oil marketing:
 
 
 
Forecasted purchases of crude oil (MMBbls)
4.3
0.4
Cash flow hedge
Forecasted sales of crude oil (MMBbls)
6.2
0.9
Cash flow hedge
Derivatives not designated as hedging instruments:
 
 
 
Natural gas risk management activities (Bcf) (5,6)
164.2
34.5
Mark-to-market
Refined products risk management activities (MMBbls) (6)
1.1
n/a
Mark-to-market
Crude oil risk management activities (MMBbls) (6)
5.1
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, March 2013 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 1.0 MMBbls of additional hedges executed under contracts that have been designated as normal sales agreements.
(5)   Current volumes include 49.3 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 commodity 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 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.
 
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
§
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 and refined products inventory hedging program is to hedge the fair value of natural gas and refined products 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
  
 
September 30, 2012
  
December 31, 2011
  
September 30, 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
  
$
16.0
  
Other current
assets
  
$
43.7
  
Other current
liabilities
  
$
180.5
  
Other current
liabilities
  
$
163.6
  
Interest rate derivatives
Other assets
    
29.1
  
Other assets
    
44.2
  
Other liabilities
    
--
  
Other liabilities
    
127.1
  
Total interest rate derivatives
 
    
45.1
  
 
    
87.9
  
 
    
180.5
  
 
    
290.7
  
Commodity derivatives
Other current
assets
    
59.5
  
Other current
assets
    
20.3
  
Other current
liabilities
    
57.1
  
Other current
liabilities
    
30.3
  
Commodity derivatives
Other assets
    
5.3
  
Other assets
    
--
  
Other liabilities
    
3.5
  
Other liabilities
    
0.2
  
Total commodity derivatives
 
    
64.8
  
 
    
20.3
  
 
    
60.6
  
 
    
30.5
  
Total derivatives designated as hedging instruments
 
  
$
109.9
  
 
  
$
108.2
  
 
  
$
241.1
  
 
  
$
321.2
  
 
 
        
 
        
 
        
 
        
Derivatives not designated as hedging instruments
        
 
        
 
        
 
        
Interest rate derivatives
Other current
assets
  
$
--
  
Other current
assets
  
$
--
  
Other current
liabilities
  
$
12.0
  
Other current
liabilities
  
$
10.1
  
Interest rate derivatives
Other assets
    
--
  
Other assets
    
--
  
Other liabilities
    
7.5
  
Other liabilities
    
10.6
  
Total interest rate derivatives
 
    
--
  
 
    
--
  
 
    
19.5
  
 
    
20.7
  
Commodity derivatives
Other current
assets
    
12.8
  
Other current
assets
    
34.4
  
Other current
liabilities
    
15.7
  
Other current
liabilities
    
32.5
  
Commodity derivatives
Other assets
    
2.1
  
Other assets
    
12.6
  
Other liabilities
    
1.4
  
Other liabilities
    
2.0
  
Total commodity derivatives
 
    
14.9
  
 
    
47.0
  
 
    
17.1
  
 
    
34.5
  
Total derivatives not designated as hedging instruments
 
  
$
14.9
  
 
  
$
47.0
  
 
  
$
36.6
  
 
  
$
55.2
  
 
 
        
 
        
 
        
 
        
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
    
For the Nine Months
  
 
  
  
Ended September 30,
    
Ended September 30,
  
 
 
  
2012
    
2011
    
2012
    
2011
  
Interest rate derivatives
Interest expense
  
$
3.0
    
$
23.6
    
$
6.1
    
$
32.4
  
Commodity derivatives
Revenue
    
(0.4
)
    
8.6
      
(16.1
)
    
7.3
  
   Total
 
  
$
2.6
    
$
32.2
    
$
(10.0
)
  
$
39.7
  
 
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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
Derivatives in Fair Value
Hedging Relationships
 
Location
  
Gain/(Loss) Recognized in
Income on Hedged Item
  
 
  
  
For the Three Months
    
For the Nine Months
  
 
  
  
Ended September 30,
    
Ended September 30,
  
 
 
  
2012
    
2011
    
2012
    
2011
  
Interest rate derivatives
Interest expense
  
$
(2.9
)
  
$
(22.5
)
  
$
(6.3
)
  
$
(32.2
)
Commodity derivatives
Revenue
    
(1.8
)
    
(7.7
)
    
14.5
      
(8.8
)
   Total
 
  
$
(4.7
)
  
$
(30.2
)
  
$
8.2
    
$
(41.0
)

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
    
For the Nine Months
  
 
  
Ended September 30,
    
Ended September 30,
  
 
  
2012
    
2011
    
2012
    
2011
  
Interest rate derivatives
  
$
(20.2
)
  
$
(260.1
)
  
$
(75.3
)
  
$
(306.1
)
Commodity derivatives – Revenue
    
(59.5
)
    
8.8
      
0.7
      
(166.0
)
Commodity derivatives – Operating costs and expenses
    
1.0
      
(14.9
)
    
(13.8
)
    
(13.2
)
   Total
  
$
(78.7
)
  
$
(266.2
)
  
$
(88.4
)
  
$
(485.3
)

Derivatives in Cash Flow
Hedging Relationships
Location
  
Gain/(Loss) Reclassified
from Accumulated Other Comprehensive
Income/(Loss) to Income (Effective Portion)
  
 
  
  
For the Three Months
    
For the Nine Months
  
 
  
  
Ended September 30,
    
Ended September 30,
  
 
 
  
2012
    
2011
    
2012
    
2011
  
Interest rate derivatives
Interest expense
  
$
(4.5
)
  
$
(1.6
)
  
$
(10.9
)
  
$
(4.6
)
Commodity derivatives
Revenue
    
0.3
      
(33.2
)
    
(12.3
)
    
(181.7
)
Commodity derivatives
Operating costs and expenses
    
(1.2
)
    
(1.9
)
    
(24.8
)
    
2.9
  
   Total
 
  
$
(5.4
)
  
$
(36.7
)
  
$
(48.0
)
  
$
(183.4
)

Derivatives in Cash Flow
Hedging Relationships
Location
  
Gain/(Loss) Recognized in Income
on Derivative (Ineffective Portion)
  
 
  
  
For the Three Months
    
For the Nine Months
  
 
  
  
Ended September 30,
    
Ended September 30,
  
 
 
  
2012
    
2011
    
2012
    
2011
  
Commodity derivatives
Revenue
  
$
(1.1
)
  
$
--
    
$
(0.2
)
  
$
0.2
  
Commodity derivatives
Operating costs and expenses
    
0.1
      
(0.9
)
    
0.4
      
(0.9
)
   Total
 
  
$
(1.0
)
  
$
(0.9
)
  
$
0.2
    
$
(0.7
)

Over the next twelve months, we expect to reclassify $30.0 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 $0.9 million of gains attributable to commodity derivative instruments from accumulated other comprehensive income to earnings, $0.1 million as an increase in revenue and $0.8 million as a decrease in operating costs and expenses.
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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 presented:

Derivatives Not Designated
as Hedging Instruments
Location
  
Gain/(Loss) Recognized in
Income on Derivative
  
 
  
  
For the Three Months
    
For the Nine Months
  
 
  
  
Ended September 30,
    
Ended September 30,
  
 
 
  
2012
    
2011
    
2012
    
2011
  
Interest rate derivatives
Interest expense
  
$
(2.2
)
  
$
(8.8
)
  
$
(5.5
)
  
$
(19.3
)
Commodity derivatives
Revenue
    
(3.9
)
    
4.3
      
26.2
      
17.6
  
Commodity derivatives
Operating costs and expenses
    
--
      
--
      
(2.8
)
    
--
  
Foreign currency derivatives
Other income
    
--
      
0.2
      
--
      
0.2
  
   Total
 
  
$
(6.1
)
  
$
(4.3
)
  
$
17.9
    
$
(1.5
)

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 measurement 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 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.

Recurring Fair Value Measurements

The following table sets forth, by level within the fair value hierarchy, the carrying values of our financial assets and liabilities at September 30, 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.

 
  
Fair Value Measurements Using
    
 
 
  
Quoted Prices
    
   
   
 
 
  
in Active
    
Significant
    
   
 
 
  
Markets for
    
Other
    
Significant
    
Carrying
  
 
  
Identical Assets
    
Observable
    
Unobservable
    
Value
  
 
  
and Liabilities
    
Inputs
    
Inputs
    
at September 30,
  
 
  
(Level 1)
    
(Level 2)
    
(Level 3)
    
2012
  
Financial assets:
  
   
   
   
 
Interest rate derivatives
  
$
--
    
$
45.1
    
$
--
    
$
45.1
  
Commodity derivatives
    
22.4
      
44.0
      
13.3
      
79.7
  
Total
  
$
22.4
    
$
89.1
    
$
13.3
    
$
124.8
  
 
                                
Financial liabilities:
                                
Interest rate derivatives
  
$
--
    
$
200.0
    
$
--
    
$
200.0
  
Commodity derivatives
    
32.5
      
41.1
      
4.1
      
77.7
  
Total
  
$
32.5
    
$
241.1
    
$
4.1
    
$
277.7
  
 
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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
The following table sets forth a reconciliation of changes in the overall fair values of our recurring Level 3 financial assets and liabilities for the periods presented:

 
  
  
For the Nine Months
  
 
  
  
Ended September 30,
  
  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
  
Total gains (losses) included in:
 
                
Net income (1)
Revenue
    
(1.3
)
    
1.9
  
Other comprehensive income (loss)
Commodity derivative instruments – changes in fair value of cash flow hedges
    
6.0
      
--
  
Settlements
 
    
(0.7
)
    
(0.2
)
Balance, June 30
 
    
4.9
      
2.1
  
Total gains (losses) included in:
 
                
Net income (1)
Revenue
    
(0.6
)
    
0.8
  
Other comprehensive income (loss)
Commodity derivative instruments – changes in fair value of cash flow hedges
    
3.5
      
--
  
Settlements
 
    
1.4
      
(2.2
)
Balance, September 30
 
  
$
9.2
    
$
0.7
  
 
 
                
(1)   There were $0.8 million of unrealized gains and $1.1 million of unrealized losses included in these amounts for the three and nine months ended September 30, 2012, respectively. There were $0.7 million and $2.5 million of unrealized gains included in these amounts for the three and nine months ended September 30, 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 recurring Level 3 fair value measurements at September 30, 2012:

 
  
Fair Value
  
 
 
   
 
  
Financial
Assets
    
Financial
Liabilities
  
Valuation
Techniques
Unobservable
Input
Range
Commodity derivatives – Propane
  
$
4.2
    
$
0.7
  
Discounted cash flow
Forward prices in excess of 1 year
$0.92-$0.98 /gallon
Commodity derivatives – Normal butane
    
0.4
      
0.7
  
Discounted cash flow
Forward prices in excess of 1 year
$1.49-$1.51 /gallon
Commodity derivatives – Natural gasoline
    
8.4
      
1.5
  
Discounted cash flow
Forward prices in excess of 1 year
$1.97-$2.02/gallon
Commodity derivatives – Crude oil
    
0.2
      
0.9
  
Discounted cash flow
Pricing data relative to quality and
   location attributes of crude oil
$92.19-$92.56 /barrel
Commodity derivatives – Natural gas
    
0.1
      
0.3
  
Discounted cash flow
Forward prices in excess of 3 years
$4.14-$4.39 /MMBtu
   Total
  
$
13.3
    
$
4.1
  
 
 
   

We believe certain forward commodity prices are the most significant unobservable inputs in determining our recurring Level 3 fair value measurements at September 30, 2012.  In general, changes in the price of the underlying commodity increases or decreases the fair value of a commodity derivative 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 the forward commodity price curves used to estimate the fair values of
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
our Level 3 commodity derivatives.  These forward curves incorporate published indexes, market quotes and other observable inputs to the extent available.

Nonrecurring Fair Value Measurements

The following table presents information regarding certain long-lived assets measured at fair value on a nonrecurring basis for the nine months ended September 30, 2012.

 
  
 
    
Fair Value Measurements Using
    
 
 
  
   
Quoted Prices
    
Significant
    
   
 
 
  
Carrying
    
in Active
    
Other
    
Significant
    
 
 
  
Value at
    
Markets for
    
Observable
    
Unobservable
    
Total Non-Cash
  
 
  
September 30,
    
Identical Assets
    
Inputs
    
Inputs
    
Impairment
  
 
  
2012
    
(Level 1)
    
(Level 2)
    
(Level 3)
    
Loss
  
Impairment of long-lived assets  held and used
  
$
2.2
    
$
--
    
$
--
    
$
2.2
    
$
2.6
  
Impairment of long-lived assets disposed of by sale
    
--
      
--
      
--
      
--
      
0.3
  
Impairment of long-lived assets disposed of
   other than by sale
    
--
      
--
      
--
      
--
      
54.7
  
Total
                                  
$
57.6
  

Operating income for the three and nine months ended September 30, 2012 includes $43.1 million and $57.6 million, respectively, of non-cash asset impairment charges attributable to the following:

§
Long-lived assets held and used (pipeline terminal assets classified as property, plant and equipment) having a carrying amount of $4.8 million were written down to their estimated fair value of $2.2 million during the third quarter of 2012, resulting in non-cash asset impairment charges of $2.6 million.

§
Long-lived assets held for sale (primarily marine transportation assets) having a carrying amount of $0.8 million were written down to their fair value of $0.5 million during the first quarter of 2012, resulting in non-cash asset impairment charges of $0.3 million.  These assets were sold in the second quarter of 2012.

§
Property, plant and equipment taken out of service and intangible assets having no future value were written off resulting in additional non-cash asset impairment charges of $40.5 million and $54.7 million for three and nine months ending September 30, 2012, respectively. Of these amounts, $29.2 million relates to the planned abandonment in 2013 of certain natural gas pipeline segments associated with our Texas Intrastate System.   This charge was recorded during the third quarter of 2012.  The remaining charges generally relate to plant closures and other pipeline abandonments.

During the three and nine months ended September 30, 2011, certain assets included in property, plant and equipment having no future value and a combined carrying amount of $5.2 million were written-off, resulting in non-cash asset impairment charges for the respective periods.

As presented in the preceding table, our estimated fair values are based on the present value of expected future cash flows (Level 3).  Forecast data and other assumptions supporting the fair value of long-lived assets being tested for impairment are based on the nonfinancial assets' highest and best use, which includes estimated probabilities where multiple cash flow outcomes are possible.  Such probability weights are generally obtained from business management personnel having oversight responsibilities for the assets being tested.  Key commercial assumptions (e.g., anticipated operating margins, throughput or processing volume growth rates and timing of cash flows) that represent Level 3 unobservable inputs and test results are reviewed and certified by members of senior management.
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
Other Fair Value Information

The carrying amounts of cash and cash equivalents (including restricted cash balances), accounts receivable and accounts payable approximate their fair values based on their short-term nature.  The estimated total fair value of our fixed-rate debt obligations was $18.0 billion and $15.76 billion at September 30, 2012 and December 31, 2011, respectively.  The aggregate carrying value of these debt obligations was $15.83 billion and $14.33 billion at September 30, 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.


Note 5.  Inventories

Our available-for-sale inventory amounts by product type were as follows at the dates indicated:

 
  
September 30,
2012
    
December 31,
2011
  
NGLs
  
$
702.5
    
$
563.6
  
Petrochemicals and refined products
    
246.9
      
443.4
  
Crude oil
    
57.5
      
39.2
  
Natural gas
    
62.3
      
65.5
  
Total
  
$
1,069.2
    
$
1,111.7
  

In those instances where we take ownership of inventory volumes through percent-of-liquids contracts and similar arrangements (as opposed to outright purchases from third parties for cash), 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 available-for-sale 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 presents our total cost of sales amounts and lower of cost or market adjustments for the periods indicated:

 
  
For the Three Months
Ended September 30,
    
For the Nine Months
Ended September 30,
  
 
  
2012
    
2011
    
2012
    
2011
  
Cost of sales (1)
  
$
8,794.0
    
$
9,787.6
    
$
26,655.0
    
$
28,397.2
  
Lower of cost or market adjustments
    
2.2
      
5.1
      
16.1
      
6.8
  
(1)   Cost of sales is a component of "Operating costs and expenses," as presented on our Unaudited Condensed Statements of Consolidated Operations. Period-to-period fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.
  

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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
    
September 30,
2012
    
December 31,
2011
  
Plants, pipelines and facilities (1)
   3-45 (6)
 
  
$
24,789.0
    
$
22,354.4
  
Underground and other storage facilities (2)
   5-40 (7)
 
    
1,512.3
      
1,388.6
  
Platforms and facilities (3)
   20-31      
638.9
      
637.5
  
Transportation equipment (4)
   3-10      
167.8
      
151.5
  
Marine vessels (5)
   15-30      
677.1
      
615.9
  
Land
            
146.1
      
136.1
  
Construction in progress
            
2,293.4
      
2,145.6
  
Total
            
30,224.6
      
27,429.6
  
Less accumulated depreciation
            
5,913.1
      
5,238.0
  
Property, plant and equipment, net
          
$
24,311.5
    
$
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 September 30,
    
For the Nine Months
Ended September 30,
  
 
  
2012
    
2011
    
2012
    
2011
  
Depreciation expense (1)
  
$
228.3
    
$
195.0
    
$
662.3
    
$
571.3
  
Capitalized interest (2)
    
26.3
      
33.1
      
86.4
      
75.1
  
(1)   Depreciation expense is a component of "Costs and expenses" as presented on our Unaudited Condensed Statements of Consolidated Operations.
(2)   We capitalize interest cost incurred on funds used to construct property, plant and equipment. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset's estimated useful life as a component of depreciation expense. Capitalized interest reduces interest expense during the period it is recorded.
  

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.  When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related long-lived asset.  Over time, the ARO liability is accreted to its present value (through accretion expense) and the capitalized amount is depreciated over the remaining useful life of the related long-term asset.   Property, plant and equipment at September 30, 2012 and December 31, 2011 includes $41.2 million and $37.7 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset.
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
The following table summarizes changes in our ARO liability balance during the nine months ended September 30, 2012:

ARO liability balance, December 31, 2011
  
$
112.0
  
Liabilities incurred during period
    
1.7
  
Liabilities settled during period
    
(21.2
)
Revisions in estimated cash flows
    
11.3
  
Accretion expense
    
4.1
  
ARO liability balance, September 30, 2012
  
$
107.9
  

The following table presents our forecast of accretion expense for the periods indicated:

Remainder
 of 2012
    
2013
    
2014
    
2015
    
2016
  
$
1.5
    
$
6.2
    
$
6.6
    
$
6.3
    
$
6.6
  
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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED 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
September 30,
2012
    
September 30,
2012
    
December 31,
2011
  
NGL Pipelines & Services:
  
   
   
 
Venice Energy Service Company, L.L.C.
   13.1%
 
  
$
31.9
    
$
35.5
  
K/D/S Promix, L.L.C.
   50%
 
    
41.6
      
40.7
  
Baton Rouge Fractionators LLC
   32.2%
 
    
19.9
      
21.0
  
Skelly-Belvieu Pipeline Company, L.L.C.
   50%
 
    
37.9
      
35.0
  
Texas Express Pipeline LLC ("Texas Express")
   35%
 
    
79.9
      
13.9
  
Texas Express Gathering LLC ("TEG") (1)
   45%
 
    
18.6
      
--
  
Front Range Pipeline LLC ("Front Range")
   33.3%
 
    
12.1
      
--
  
Onshore Natural Gas Pipelines & Services:
                        
Evangeline (2)
   --      
--
      
4.4
  
White River Hub, LLC
   50%
 
    
25.2
      
25.7
  
Onshore Crude Oil Pipelines & Services:
                        
Seaway Crude Pipeline LLC
   50%
 
    
254.6
      
170.7
  
Eagle Ford Pipeline LLC ("Eagle Ford Crude Oil Pipeline")
   50%
 
    
117.1
      
--
  
Offshore Pipelines & Services:
                        
Poseidon Oil Pipeline Company, L.L.C. ("Poseidon")
   36%
 
    
48.3
      
55.4
  
Cameron Highway Oil Pipeline Company
   50%
 
    
217.3
      
222.8
  
Deepwater Gateway, L.L.C.
   50%
 
    
90.8
      
94.6
  
Neptune Pipeline Company, L.L.C.
   25.7%
 
    
48.1
      
51.1
  
Southeast Keathley Canyon Pipeline Company L.L.C.
   50%
 
    
57.5
      
1.0
  
Petrochemical & Refined Products Services:
                        
Baton Rouge Propylene Concentrator, LLC
   30%
 
    
8.2
      
9.5
  
Centennial Pipeline LLC ("Centennial")
   50%
 
    
48.4
      
51.8
  
Other (3)
  
Various
      
3.0
      
3.4
  
Other Investments:
                        
Energy Transfer Equity (4)
   --      
--
      
1,023.1
  
Total
          
$
1,160.4
    
$
1,859.6
  
 
                        
(1)   In April 2012, we, along with Enbridge Midcoast Energy, LP ("Enbridge") and WGR Asset Holding Company LLC formed a new joint venture, TEG, to design and construct two NGL gathering systems to complement the Texas Express Pipeline. Enbridge will construct and operate the systems, which are expected to begin service in the second quarter of 2013.
(2)   In June 2012, we acquired the remaining ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp. (collectively "Evangeline") and they became wholly owned subsidiaries of ours.
(3)   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.
(4)   We ceased using the equity method to account for our investment in Energy Transfer Equity limited partner units effective January 18, 2012 and began accounting for them as available-for-sale securities. We completed the sale of the remaining Energy Transfer Equity units in April 2012 (see below).
  
 
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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
The following table presents our equity in income (loss) of unconsolidated affiliates by business segment for the periods presented:

 
  
For the Three Months
Ended September 30,
    
For the Nine Months
Ended September 30,
  
 
  
2012
    
2011
    
2012
    
2011
  
NGL Pipelines & Services
  
$
3.0
    
$
4.3
    
$
12.0
    
$
16.4
  
Onshore Natural Gas Pipelines & Services
    
0.9
      
1.4
      
3.5
      
4.1
  
Onshore Crude Oil Pipelines & Services
    
16.5
      
(1.0
)
    
20.6
      
(3.1
)
Offshore Pipelines & Services
    
6.8
      
5.4
      
17.8
      
20.3
  
Petrochemical & Refined Products Services
    
(6.2
)
    
(3.8
)
    
(14.1
)
    
(13.1
)
Other Investments (1)
    
--
      
2.3
      
2.4
      
11.3
  
Total
  
$
21.0
    
$
8.6
    
$
42.2
    
$
35.9
  
 
                                   
(1)   With respect to the nine months ended September 30, 2012, the amount presented reflects our 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:

 
  
September 30,
2012
    
December 31,
2011
  
NGL Pipelines & Services
  
$
24.0
    
$
24.7
  
Onshore Crude Oil Pipelines & Services
    
18.7
      
19.2
  
Offshore Pipelines & Services
    
13.9
      
14.8
  
Petrochemical & Refined Products Services
    
2.8
      
2.9
  
Other Investments (1)
    
--
      
1,119.0
  
Total
  
$
59.4
    
$
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 this investment as an available-for-sale security. As a result, we no longer recognized any excess cost amounts associated with this investment.
  

The following table presents our amortization of excess cost amounts by business segment for the periods presented:

 
  
For the Three Months
Ended September 30,
    
For the Nine Months
Ended September 30,
  
 
  
2012
    
2011
    
2012
    
2011
  
NGL Pipelines & Services
  
$
0.2
    
$
0.3
    
$
0.7
    
$
0.8
  
Onshore Crude Oil Pipelines & Services
    
0.2
      
0.1
      
0.5
      
0.5
  
Offshore Pipelines & Services
    
0.3
      
0.3
      
0.9
      
0.9
  
Petrochemical & Refined Products Services
    
--
      
0.1
      
0.1
      
0.1
  
Other Investments (1)
    
--
      
7.1
      
0.3
      
24.6
  
Total
  
$
0.7
    
$
7.9
    
$
2.5
    
$
26.9
  
 
                                
(1)   Reflects amortization of excess cost amounts related to our investment in Energy Transfer Equity from January 1, 2012 through January 18, 2012, which is the date we ceased using the equity method to account for this investment.
  
 
Liquidation of Investment in Energy Transfer Equity

The Other Investments segment included our noncontrolling ownership interest in Energy Transfer Equity, which was accounted for using the equity method until January 18, 2012.  Since our ownership interest in Energy Transfer Equity exceeded 3% throughout calendar year 2011, we accounted for our investment in Energy Transfer Equity using the equity method and included gains from the sale of this investment in operating income.  During the nine months ended September 30, 2011, we sold 8,564,136 Energy Transfer Equity common units for net cash proceeds of $333.5 million and recorded gains of $24.8 million from these sales.  At December 31, 2011, we owned 29,303,514 common units of Energy Transfer Equity.
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
On January 18, 2012, we sold 22,762,636 of these common units in a private transaction, which generated cash proceeds of $825.1 million. As a result of the January 18 transaction, our ownership interest in Energy Transfer Equity was reduced below 3%, and we discontinued using the equity method to account for this investment and began accounting for it as an investment in available-for-sale equity securities.  The remaining 6,540,878 units were sold systematically through April 27, 2012 and generated additional total cash proceeds of $270.2 million.  In the aggregate, the liquidation of this investment during 2012 resulted in $68.8 million of gains that are presented as a component of other income.

All activities included in our former sixth reportable business segment, Other Investments, ceased on January 18, 2012, which was the date we discontinued using the equity method to account for our investment in Energy Transfer Equity.  See Note 11 for additional information regarding our business segments.

Formation of Front Range Joint Venture

In April 2012, we, along with WGR Asset Holding Company LLC, an affiliate of Anadarko Petroleum Corporation, and DCP Midstream Front Range LLC formed a new joint venture, 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 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, will provide producers in the DJ Basin with access to the Gulf Coast, the largest NGL market in the U.S.  Initial capacity on the Front Range Pipeline will be 150 MBPD, which can be readily expanded to 230 MBPD.  We will construct and operate the pipeline, which is expected to begin service in the fourth quarter of 2013.
 
Formation of Eagle Ford Crude Oil Pipeline Joint Venture with Plains

In August 2012, we announced the formation of a 50/50 joint venture, Eagle Ford Pipeline LLC, with Plains All American Pipeline, L.P. ("Plains") to provide crude oil pipeline services to producers in South Texas. The arrangement provides for Enterprise and Plains to consolidate certain segments of previously announced pipeline projects servicing the Eagle Ford Shale supply basin.  The joint venture pipeline system is supported by long-term commitments from producers totaling up to 210 MBPD of crude oil.  This joint venture is expected to provide shippers with increased market flexibility and enable Enterprise and Plains to optimize their respective capital investments in the area.

The joint venture will include a 140-mile crude oil and condensate line extending from Gardendale, Texas in LaSalle County to Three Rivers, Texas in Live Oak County and continuing on to Corpus Christi, Texas, and a newly constructed 35-mile pipeline segment from Three Rivers to our Lyssy, Texas station in Wilson County.  The system, which is currently under construction, is expected to have a capacity of 350 MBPD and will include a marine terminal facility at Corpus Christi and 1.8 MMBbls of operational storage capacity across the system.  Segments of the new pipeline system are expected to be placed into service in the second quarter of 2013, with the balance of the system expected to be placed into service in the first quarter of 2014.  Plains will serve as operator of the joint venture's pipeline system.

At Lyssy, the joint venture pipeline will interconnect with the Eagle Ford expansion of our South Texas Crude Oil Pipeline System, which commenced operations in June 2012.  Our South Texas Crude Oil Pipeline System is not part of the new joint venture's pipeline system.
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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
Summarized Income Statement Information of Unconsolidated Affiliates

The following table presents unaudited income statement information (on a 100% basis for the periods presented) of our unconsolidated affiliates, aggregated by the business segments to which they relate:

 
  
Summarized Income Statement Information for the Three Months Ended
  
 
  
September 30, 2012
    
September 30, 2011
  
 
  
Revenues
    
Operating
Income (Loss)
    
Net
Income (Loss)