10-Q 1 epd10q_093011.htm QUARTERLY REPORT epd10q_093011.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

þ  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2011

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 870,641,175 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, 2011.  Our common units trade on the New York Stock Exchange under the ticker symbol “EPD.”
 


 
 
ENTERPRISE PRODUCTS PARTNERS L.P.

   
Page No.
 
 
 
 
 
 
   
 
 
 
 
 
       5.  Inventories
 
 
 
 
 
 
 
 
 
 
 
 
 
     
     












PART I.  FINANCIAL INFORMATION.


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

   
September 30,
   
December 31,
 
ASSETS
 
2011
   
2010
 
Current assets:
           
Cash and cash equivalents
  $ 29.1     $ 65.5  
Restricted cash
    78.6       98.7  
Accounts receivable – trade, net of allowance for doubtful accounts
of $13.4 at September 30, 2011 and $18.4 at December 31, 2010
    4,008.4       3,800.1  
Accounts receivable – related parties
    37.5       36.8  
Inventories
    1,389.3       1,134.0  
Assets held for sale (see Note 6)
    455.1       --  
Prepaid and other current assets
    350.4       372.0  
Total current assets
    6,348.4       5,507.1  
Property, plant and equipment, net
    21,388.1       19,332.9  
Investments in unconsolidated affiliates
    1,908.5       2,293.1  
Intangible assets, net of accumulated amortization of $955.6 at
   September 30, 2011 and $932.3 at December 31, 2010
    1,686.6       1,841.7  
Goodwill
    2,092.3       2,107.7  
Other assets
    300.5       278.3  
Total assets
  $ 33,724.4     $ 31,360.8  
                 
LIABILITIES AND EQUITY
               
Current liabilities:
               
Current maturities of debt
  $ 1,000.0     $ 282.3  
Accounts payable – trade
    820.8       542.0  
Accounts payable – related parties
    212.2       133.1  
Accrued product payables
    4,715.5       4,164.8  
Accrued interest
    183.9       252.9  
Liabilities related to assets held for sale (see Note 6)
    72.2       --  
Other current liabilities
    639.3       505.1  
Total current liabilities
    7,643.9       5,880.2  
Long-term debt (see Note 10)
    14,108.7       13,281.2  
Deferred tax liabilities
    83.8       78.0  
Other long-term liabilities
    336.5       220.6  
Commitments and contingencies
               
Equity: (see Note 11)
               
Partners’ equity:
               
Limited partners:
               
Common units (870,649,071 units outstanding at September 30, 2011
and 843,681,572 units outstanding at December 31, 2010)
    11,657.0       11,288.2  
Class B units (4,520,431 units outstanding at September 30, 2011 and
December 31, 2010)
    118.5       118.5  
Accumulated other comprehensive loss
    (336.8 )     (32.5 )
Total  partners’ equity
    11,438.7       11,374.2  
Noncontrolling interests
    112.8       526.6  
Total equity
    11,551.5       11,900.8  
Total liabilities and equity
  $ 33,724.4     $ 31,360.8  





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,
 
   
2011
   
2010
   
2011
   
2010
 
Revenues:
                       
Third parties
  $ 11,163.2     $ 7,934.1     $ 32,169.1     $ 23,673.6  
Related parties
    163.9       133.7       558.2       482.1  
Total revenues (see Note 12)
    11,327.1       8,067.8       32,727.3       24,155.7  
Costs and expenses:
                               
Operating costs and expenses:
                               
Third parties
    10,146.2       7,117.1       29,398.3       21,441.1  
Related parties
    458.4       343.0       1,276.7       965.1  
Total operating costs and expenses
    10,604.6       7,460.1       30,675.0       22,406.2  
General and administrative costs:
                               
Third parties
    20.0       28.8       49.2       61.5  
Related parties
    30.0       41.3       89.1       89.4  
Total general and administrative costs
    50.0       70.1       138.3       150.9  
Total costs and expenses (see Note 12)
    10,654.6       7,530.2       30,813.3       22,557.1  
Equity in income of unconsolidated affiliates
    8.6       5.6       35.9       43.2  
Operating income
    681.1       543.2       1,949.9       1,641.8  
Other income (expense):
                               
Interest expense
    (189.0 )     (192.0 )     (561.1 )     (529.1 )
Interest income
    0.3       0.9       0.9       1.6  
Other, net
    (1.3 )     0.4       (1.1 )     0.2  
Total other expense, net
    (190.0 )     (190.7 )     (561.3 )     (527.3 )
Income before provision for income taxes
    491.1       352.5       1,388.6       1,114.5  
Provision for income taxes
    (11.6 )     (4.9 )     (26.1 )     (20.1 )
Net income
    479.5       347.6       1,362.5       1,094.4  
Net income attributable to noncontrolling interests (see Note 11)
    (8.1 )     (310.6 )     (36.7 )     (933.4 )
Net income attributable to partners
  $ 471.4     $ 37.0     $ 1,325.8     $ 161.0  
                                 
Allocation of net income attributable to partners:
                               
Limited partners
  $ 471.4     $ 37.0     $ 1,325.8     $ 161.0  
General partner
  $ --     $ *     $ --     $ *  
                                 
Earnings per unit: (see Note 14)
                               
Basic earnings per unit
  $ 0.57     $ 0.18     $ 1.62     $ 0.77  
Diluted earnings per unit
  $ 0.55     $ 0.18     $ 1.55     $ 0.77  















See Notes to Unaudited Condensed Consolidated Financial Statements.
* Amount is negligible.


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,
 
   
2011
   
2010
   
2011
   
2010
 
                         
Net income
  $ 479.5     $ 347.6     $ 1,362.5     $ 1,094.4  
Other comprehensive income (loss):
                               
Cash flow hedges:
                               
Commodity derivative instruments:
                               
Changes in fair value of cash flow hedges
    (6.1 )     (64.1 )     (179.2 )     (31.0 )
Reclassification of gains and losses to net income
    35.1       (25.6 )     178.8       (10.6 )
Interest rate derivative instruments:
                               
Changes in fair value of cash flow hedges
    (260.1 )     (81.6 )     (306.1 )     (168.4 )
Reclassification of losses to net income
    1.6       8.1       4.6       21.4  
Foreign currency derivative instruments:
                               
Changes in fair value of cash flow hedges
    --       0.1       --       (0.1 )
Reclassification of gains to net income
    --       --       --       (0.3 )
Total cash flow hedges
    (229.5 )     (163.1 )     (301.9 )     (189.0 )
Foreign currency translation adjustment
    --       0.5       --       0.3  
Change in funded status of pension and postretirement plans, net of tax
    --       --       (0.6 )     (0.9 )
Proportionate share of other comprehensive income (loss) of
unconsolidated affiliate
    --       11.9       (0.7 )     11.5  
Total other comprehensive loss
    (229.5 )     (150.7 )     (303.2 )     (178.1 )
Comprehensive income
    250.0       196.9       1,059.3       916.3  
Comprehensive income attributable to noncontrolling interests
    (8.1 )     (167.2 )     (36.7 )     (768.0 )
Comprehensive income attributable to partners
  $ 241.9     $ 29.7     $ 1,022.6     $ 148.3  

















 

 






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,
 
   
2011
   
2010
 
Operating activities:
           
Net income
  $ 1,362.5     $ 1,094.4  
Reconciliation of net income to net cash flows provided by operating activities:
               
Depreciation, amortization and accretion
    739.2       709.1  
Non-cash asset impairment charges
    5.2       1.5  
Equity in income of unconsolidated affiliates
    (35.9 )     (43.2 )
Distributions received from unconsolidated affiliates
    122.5       146.0  
Operating lease expenses paid by EPCO
    0.3       0.5  
Gains from asset sales and related transactions
    (25.4 )     (45.4 )
Deferred income tax expense
    5.5       3.7  
Changes in fair market value of derivative instruments
    (6.8 )     (10.8 )
Effect of pension settlement recognition
    (0.5 )     (0.2 )
Net effect of changes in operating accounts (see Note 17)
    61.6       (411.8 )
Net cash flows provided by operating activities
    2,228.2       1,443.8  
Investing activities:
               
Capital expenditures
    (2,792.2 )     (1,405.1 )
Contributions in aid of construction costs
    12.3       13.9  
Decrease in restricted cash
    20.1       37.9  
Cash used for business combinations
    --       (1,233.0 )
Investments in unconsolidated affiliates
    (11.9 )     (6.3 )
Proceeds from asset sales and related transactions (see Note 17)
    440.5       89.6  
Other investing activities
    (7.4 )     1.5  
Cash used in investing activities
    (2,338.6 )     (2,501.5 )
Financing activities:
               
Borrowings under debt agreements
    6,565.1       4,170.3  
Repayments of debt
    (4,989.3 )     (2,816.6 )
Debt issuance costs
    (33.9 )     (14.7 )
Cash distributions paid to partners (see Note 11)
    (1,459.7 )     (227.6 )
Cash distributions paid to noncontrolling interests (see Note 11)
    (52.0 )     (1,099.0 )
Cash contributions from noncontrolling interests (see Note 11)
    4.7       1,034.4  
Net cash proceeds from issuance of common units
    67.1       --  
Acquisition of treasury units in connection with equity-based awards
    (10.1 )     (3.1 )
Other financing activities
    (17.9 )     1.3  
Cash provided by financing activities
    74.0       1,045.0  
Effect of exchange rate changes on cash
    --       0.3  
Net change in cash and cash equivalents
    (36.4 )     (12.7 )
Cash and cash equivalents, January 1
    65.5       55.3  
Cash and cash equivalents, September 30
  $ 29.1     $ 42.9  













See Notes to Unaudited Condensed Consolidated Financial Statements.


ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY
(See Note 11 for Unit History, Accumulated Other Comprehensive Loss and Noncontrolling Interests)
(Dollars in millions)

   
Partners’ Equity
             
   
Limited
 Partners
   
Accumulated
Other
Comprehensive
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  
Operating lease expenses paid by EPCO
    0.3       --       --       0.3  
Cash distributions paid to 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  
Acquisition of treasury units in connection with equity-based awards
    (10.1 )     --       --       (10.1 )
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 )
Proportionate share of other comprehensive loss of unconsolidated affiliate
    --       (0.7 )     --       (0.7 )
Other
    4.7       (0.6 )     (1.6 )     2.5  
Balance, September 30, 2011
  $ 11,775.5     $ (336.8 )   $ 112.8     $ 11,551.5  



   
Partners’ Equity
             
   
Limited
 Partners
   
General
 Partner
   
Accumulated
Other
Comprehensive
Loss
   
Noncontrolling
Interests
   
Total
 
Balance, December 31, 2009
  $ 1,972.4     $ *     $ (33.3 )   $ 8,534.0     $ 10,473.1  
Net income
    161.0       *       --       933.4       1,094.4  
Operating lease expenses paid by EPCO
    --       --       --       0.5       0.5  
Cash distributions paid to partners
    (227.6 )     *       --       --       (227.6 )
Cash distributions paid to noncontrolling interests
    --       --       --       (1,099.0 )     (1,099.0 )
Cash contributions from noncontrolling interests
    --       --       --       1,034.4       1,034.4  
Acquisition of treasury units in connection with
    equity-based awards
    --       --       --       (3.1 )     (3.1 )
Amortization of fair value of equity-based awards
    3.8       --       --       45.9       49.7  
Common units issued in exchange for ownership interests
    in truck transport business
    --       --       --       30.6       30.6  
Cash flow hedges
    --       --       (24.2 )     (164.8 )     (189.0 )
Proportionate share of other comprehensive income of
unconsolidated affiliate
    --       --       11.5       --       11.5  
Other
    --       --       --       (0.6 )     (0.6 )
Balance, September 30, 2010
  $ 1,909.6     $ *     $ (46.0 )   $ 9,311.3     $ 11,174.9  










See Notes to Unaudited Condensed Consolidated Financial Statements.
* Amount is negligible.

 
6

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.

SIGNIFICANT RELATIONSHIPS REFERENCED IN THE
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 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.

On September 3, 2010, Enterprise GP Holdings L.P. (“Holdings”), Enterprise, Enterprise GP, Enterprise Products GP, LLC (“EPGP,” the former general partner of Enterprise) and Enterprise ETE LLC (“Holdings MergerCo,” a Delaware limited liability company and a wholly owned subsidiary of Enterprise) entered into a merger agreement (the “Holdings Merger Agreement”).  On November 22, 2010, the Holdings Merger Agreement was approved by the unitholders of Holdings and the merger of Holdings with and into Holdings MergerCo and related transactions were completed, with Holdings MergerCo surviving such merger (collectively, we refer to these transactions as the “Holdings Merger”).  Enterprise’s membership interests in Holdings MergerCo were subsequently contributed to EPO.  For additional information regarding the Holdings Merger, see Note 1.

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 and one of three managers of Dan Duncan LLC; (ii) Dr. Ralph S. Cunningham, who is also a director and the Chairman of Enterprise GP and one of three managers of Dan Duncan LLC; and (iii) Richard H. Bachmann, who is also a director of Enterprise GP and one of 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 serves as Chairman of EPCO; (ii) Dr. Cunningham, who serves as a Vice Chairman of EPCO; and (iii) Mr. Bachmann, who serves as the President and Chief Executive Officer (“CEO”) of EPCO.  Ms. Williams, Dr. Cunningham and Mr. Bachmann are also directors 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”).  For additional information regarding the Duncan Merger, see Note 1.

References to “TEPPCO” and “TEPPCO GP” mean TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC (which is the general partner of TEPPCO), respectively, prior to their mergers with our subsidiaries on October 26, 2009.  We refer to such related mergers both individually and in the aggregate as the “TEPPCO Merger.” 
   
References to “Energy Transfer Equity” mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include Energy Transfer Partners, L.P. (“ETP”) and

 
7

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

Regency Energy Partners LP.  We own noncontrolling limited partner interests in Energy Transfer Equity, which we account for using the equity method of accounting.  Energy Transfer Equity electronically files reports with the U.S. Securities and Exchange Commission (“SEC”), including annual reports on Form 10-K and quarterly reports on Form 10-Q.  The SEC maintains an Internet website at www.sec.gov that contains the periodic reports and other information regarding this registrant.

References to “Employee Partnerships” mean EPE Unit L.P., EPE Unit II, L.P., EPE Unit III, L.P., Enterprise Unit L.P. and EPCO Unit L.P., collectively, all of which were privately held affiliates of EPCO.  The Employee Partnerships were liquidated in August 2010.  See Note 3 for additional information.
 
 
Note 1.  Partnership Operations, Organization and Basis of Presentation

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 (“NGL”) businesses of EPCO.  We are 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, Canada and the Gulf of Mexico with domestic consumers and international markets.  Our assets include approximately 50,000 miles of onshore and offshore pipelines; 192 million barrels (“MMBbls”) of storage capacity for NGLs, refined products and crude oil; and 27 billion cubic feet (“Bcf”) of total working 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 United States 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.  Our business segments reflect the manner in which these businesses are managed and reviewed by the CEO of our general partner.  See Note 12 for additional information regarding our business segments.

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 and 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 13 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 rate of 1.01 Enterprise common units for each Duncan Energy Partners common unit.  Enterprise issued 24,277,310 of its common units (net of 9 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

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

financial reporting purposes, the Duncan Merger did not change the basis of presentation of our historical financial statements.

Impact of the Holdings Merger on the Basis of Presentation of our
Consolidated Financial Statements

On November 22, 2010, the Holdings Merger Agreement was approved by the unitholders of Holdings and the merger of Holdings with Holdings MergerCo and related transactions were completed, with Holdings MergerCo surviving such merger.  At the effective time of the Holdings Merger, Enterprise GP succeeded as Enterprise’s general partner, and each issued and outstanding unit representing limited partner interests in Holdings was cancelled and converted into the right to receive Enterprise common units based on an exchange ratio of 1.5 Enterprise common units for each Holdings unit.  Enterprise issued an aggregate of 208,813,454 of its common units (net of 23 fractional common units cashed out) as consideration in the Holdings Merger and, immediately after the merger, cancelled 21,563,177 of its common units previously owned by Holdings.

In connection with the Holdings Merger, Enterprise’s partnership agreement was amended and restated to provide for the cancellation of its general partner’s 2% economic interest and incentive distribution rights in Enterprise.  In addition, a privately held affiliate of EPCO agreed to temporarily waive the regular quarterly cash distributions it would otherwise receive from Enterprise with respect to a certain number of Enterprise’s common units (the “Designated Units”) over a five-year period after the merger closing date. The number of Designated Units to which the temporary distribution waiver applies is as follows for distributions to be paid, if any, during the following periods: 30,610,000 during 2011; 26,130,000 during 2012; 23,700,000 during 2013; 22,560,000 during 2014; and 17,690,000 during 2015.

Prior to the Holdings Merger, Enterprise was a consolidated subsidiary of Holdings, which was Enterprise’s parent.  Upon completion of the Holdings Merger, Holdings merged with and into a wholly owned subsidiary of Enterprise.  The Holdings Merger resulted in Holdings being considered the surviving consolidated entity for accounting purposes, while Enterprise is the surviving consolidated entity for legal and reporting purposes.  For accounting purposes, Holdings is deemed the acquirer of the noncontrolling interests in Enterprise that were previously recognized in Holdings’ consolidated financial statements (i.e., the acquisition of Enterprise’s limited partner interests that were owned by parties other than Holdings).  While it was a publicly traded partnership, Holdings (NYSE, ticker symbol “EPE”) electronically filed its annual and quarterly consolidated financial statements with the SEC.  You can access this information at www.sec.gov.

As a result of the Holdings Merger, Enterprise’s consolidated financial and operating results prior to November 22, 2010 have been presented as if it were Holdings from an accounting perspective (i.e., the financial statements of Holdings become the historical financial statements of Enterprise).  The primary differences between Holdings’ and Enterprise’s consolidated results of operations were: (i) general and administrative costs incurred by Holdings and EPGP (Enterprise’s former general partner); (ii) equity in income of Holdings’ noncontrolling ownership interests in Energy Transfer Equity; and (iii) interest expense associated with Holdings’ debt.  In addition, for periods prior to November 22, 2010, the net assets, income, cash distributions and contributions and other amounts attributable to Enterprise’s limited partner interests that were owned by third parties and related parties other than Holdings are presented as a component of noncontrolling interests.  See Note 11 for additional information regarding noncontrolling interests.

Limited partner units outstanding and earnings per unit amounts presented in these consolidated financial statements for periods prior to the Holdings Merger have been retroactively adjusted to reflect the 1.5 to one unit-for-unit exchange that occurred in connection with the Holdings Merger.  See Note 14 for additional information regarding our earnings per unit amounts.




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

Note 2.  General Accounting Matters

Our results of operations for the three and nine months ended September 30, 2011 are not necessarily indicative of results expected for the full year of 2011.  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 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, 2010 (the “2010 Form 10-K”) filed on March 1, 2011.

Allowance for Doubtful Accounts

Our allowance for doubtful accounts is determined based on specific identification and estimates of future uncollectible accounts, including those related to natural gas imbalances.  Our procedure for estimating the allowance for doubtful accounts is based on: (i) historical experience with customers, (ii) the perceived financial stability of customers based on our research and (iii) the levels of credit we grant to customers.  In addition, we may increase the allowance for doubtful accounts in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties.  On a routine basis, we review estimates associated with the allowance for doubtful accounts to ensure that we have recorded sufficient reserves to cover potential losses.

The following table presents our allowance for doubtful accounts activity for the periods presented:

   
For the Nine Months
 
   
Ended September 30,
 
   
2011
   
2010
 
Balance at beginning of period
  $ 18.4     $ 16.8  
Charged to costs and expenses
    0.8       1.3  
Deductions (1)
    (5.8 )     --  
Balance at end of period
  $ 13.4     $ 18.1  
                 
(1)   The 2011 deduction amount 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

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

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 15 for additional information regarding our contingencies.

Derivative Instruments

We use derivative instruments such as swaps, forward contracts and other arrangements to manage price risks associated with inventories, firm commitments, interest rates and certain anticipated transactions.  To qualify for hedge accounting, the item to be hedged must expose us to risk and the related derivative instrument must reduce that exposure and meet specific hedge documentation requirements.  We formally designate a derivative instrument as a hedge and document and assess the effectiveness of the hedge at inception and thereafter on a quarterly basis.

For certain of our derivative instruments, we apply the normal purchase/normal sale exception, which precludes the recognition of changes in mark-to-market values for these derivatives in our consolidated financial statements.  The revenues and expenses associated with these transactions are recognized when volumes are physically delivered or received.

See Note 4 for additional information regarding our derivative instruments and related interest rate and commodity hedging activities.

Earnings Per Unit

Earnings per unit is based on the amount of net income attributable to limited partners and the weighted-average number of limited partner units outstanding during a period.  See Note 14 for additional information regarding our earnings per unit amounts.

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 of fixed and identifiable intangible assets, (ii) impairment testing of fixed and intangible assets (including goodwill), (iii) reserves for environmental matters, (iv) natural gas imbalances, (v) contingencies and (vi) 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.

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.  See Note 4 for fair value information associated with our derivative instruments.

The estimated total fair value of our fixed-rate long-term debt obligations was approximately $15.43 billion and $12.91 billion at September 30, 2011 and December 31, 2010, respectively.  These values are based on quoted market prices for such debt or debt of similar terms and maturities.  The

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

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.  See Note 8 for summarized financial information of our investments accounted for using the equity method.

Liquids Exchange Contracts

In total, our liquids exchange balances were payables of $407.8 million and $144.1 million at September 30, 2011 and December 31, 2010, respectively.  The most significant liquids exchange transactions recorded on our consolidated balance sheet relate to those involving petrochemical volumes. Petrochemical transactions accounted for approximately 84% and 85% of our liquids exchange transactions recorded at September 30, 2011 and December 31, 2010, respectively. Under these agreements, we physically receive volumes of propane/propylene mix (an unprocessed stream), including the risk of loss and legal title to such volumes, from the exchange counterparty.  In turn, we deliver segregated polymer grade propylene and propane (processed streams) back to the customer and charge them a processing or similar fee.  The intent of these exchange transactions is the earning of fee revenue for processing and transporting the propane/propylene mix using our assets.  This arrangement satisfies the commercial, logistical and timing needs of the customer and allows us to operate our plants more effectively.

To the extent that the aggregate volumes we receive under such exchange agreements exceed those we deliver under the agreements during a period (measured as of the end of each reporting period), we recognize a net exchange payable position with the counterparties.  With respect to the petrochemical transactions discussed above, we are typically in a net exchange payable position with our counterparties.  In those limited situations where the aggregate volumes we deliver exceed those we receive during a period (measured as of the end of each reporting period), we recognize a net exchange receivable position with the counterparties.  From an income statement perspective, the only revenue recognized from such exchange agreements is fee revenue.  From a balance sheet perspective, net exchange payables arising from these transactions are valued at market-based prices.  To the extent that we recognize net exchange receivables arising from liquids exchange transactions, such balances are valued at average cost.

Volumetric receivables and payables arising from liquids exchange contracts are typically balanced with movements of products rather than with cash.  When payment or receipt of monetary consideration is required for product differentials and service costs with a counterparty, such items are recognized in our consolidated financial statements on a net basis as either operating revenues or expense, as appropriate.

Recent Accounting Developments

The following recent accounting developments will impact our future consolidated financial statements:

Fair Value Measurements.  In May 2011, the Financial Accounting Standards Board (or “FASB”) issued an accounting standard update that amended previous fair value measurement and disclosure guidance.  These amendments generally involve clarifications on how to measure and disclose fair value amounts recognized in the financial statements.  They also expand the disclosure requirements, particularly for Level 3 fair value measurements, to include a description of the valuation processes used and an analysis of the sensitivity of the fair value measurements to changes in unobservable inputs and the interrelationships between those unobservable inputs, if any.  We will adopt this guidance on January 1, 2012 and apply its requirements prospectively at that time.  We do not believe the adoption of this guidance will have a material impact on our consolidated financial statements.

 Presentation of Other Comprehensive Income.  In June 2011, the FASB issued an accounting standard update that revised the financial statement presentation of other comprehensive income.  The amended guidance requires entities to present components of comprehensive income in either (i) a single continuous statement of comprehensive income or (ii) two separate but consecutive statements (i.e., a

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

statement of income and a statement of comprehensive income, which is our current format).  Although the amended guidance does not change the items that must be reported in other comprehensive income, reclassification adjustments for each component of other comprehensive income would be displayed separately on the statement of income and in other comprehensive income.  In October 2011, the FASB announced its intention to defer the requirement related to the separate presentation of reclassification adjustments.  Based on the current guidance, we do not believe the adoption of this guidance will have a material impact on our consolidated financial statements.

Testing for Goodwill Impairment.  In September 2011, the FASB issued an accounting standard update that provides entities with an option to perform a qualitative assessment to determine whether further impairment testing is necessary.  We will adopt this guidance on January 1, 2012 and apply its requirements prospectively at that time.  We do not believe the adoption of this guidance will have a material impact on our consolidated financial statements.

Restricted Cash

Restricted cash represents amounts held in connection with our commodity derivative instruments portfolio and related physical natural gas, crude oil and NGL purchases.  Additional cash may be restricted to maintain this portfolio as commodity prices fluctuate or deposit requirements change.  At September 30, 2011 and December 31, 2010, our restricted cash amounts were $78.6 million and $98.7 million, respectively.  See Note 4 for information regarding derivative instruments and hedging activities.


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,
 
   
2011
   
2010
   
2011
   
2010
 
Restricted common unit awards
  $ 11.9     $ 9.6     $ 35.4     $ 23.3  
Unit option awards
    0.7       1.0       2.4       2.4  
Other (1)
    0.2       27.9       --       32.6  
Total compensation expense
  $ 12.8     $ 38.5     $ 37.8     $ 58.3  
                                 
(1)   Primarily consists of unit appreciation rights (“UARs”), phantom units and similar awards. Also, the amounts presented for 2010 include awards related to limited partnership interests in the Employee Partnerships, which were liquidated in August 2010.
 

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, 2011, 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”).
 
The 1998 Plan provides for awards of our common units and other rights to our non-employee directors and to employees of EPCO and its affiliates providing services to us.  Awards under the 1998 Plan may be granted in the form of unit options, restricted common units, phantom units and distribution equivalent rights (“DERs”).  Up to 7,000,000 of our common units may be issued as awards under the 1998

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

Plan.  After giving effect to awards granted under the plan through September 30, 2011, a total of 1,488,906 additional common units could be issued.

The 2008 Plan provides for awards of our common units and other rights to our non-employee directors and to consultants and employees of EPCO and its affiliates providing services to us.  Awards under the 2008 Plan may be granted in the form of unit options, restricted common units, phantom units, UARs and DERs.  Up to 10,000,000 of our common units may be issued as awards under the 2008 Plan.  After giving effect to awards granted under the plan through September 30, 2011, a total of 4,737,750 additional common units could be issued.

In connection with the Duncan Merger, the 2010 Duncan Energy Partners L.P. Long-Term Incentive Plan (“2010 Plan”) was terminated.  The 2010 Plan provided for awards to employees, directors or consultants providing services to Duncan Energy Partners.  Awards under the 2010 Plan were granted in the form of restricted common units.  There were no awards outstanding under the 2010 Plan at September 6, 2011 (i.e., immediately prior to the Duncan Merger).  See Note 1 for information regarding the Duncan Merger.

Restricted Common Unit Awards

Restricted common unit awards allow recipients to acquire (at no cost to the recipient apart from service or other conditions) limited partner units once a defined vesting period expires, subject to customary forfeiture provisions.  Restricted common unit awards are denominated in our common units and, prior to the Duncan Merger, those of Duncan Energy Partners depending on the issuer of the award.  Restricted common unit awards issued prior to 2010 generally cliff vest four years from the date of grant.  Beginning with awards issued in 2010, restricted common unit awards are typically subject to graded vesting provisions in which one-fourth of each award vests on the first, second, third and fourth anniversaries of the date of grant.  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.






















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

The following table presents information regarding restricted common unit awards for the periods presented:

   
Number of
Units
   
Weighted-
Average Grant
Date Fair Value
per Unit (1)
 
Enterprise restricted common unit awards:
           
    Restricted common units at December 31, 2010
    3,561,614     $ 29.78  
Granted (2)
    1,381,530     $ 43.63  
Vested
    (886,508 )   $ 31.46  
Forfeited
    (129,899 )   $ 33.51  
    Restricted common units at September 30, 2011
    3,926,737     $ 34.15  
                 
Duncan Energy Partners restricted common unit awards:
               
    Restricted common units at December 31, 2010
    --     $ --  
Granted (3)
    3,666     $ 32.56  
Vested (3)
    (3,666 )   $ 32.56  
    Restricted common units at September 6, 2011
    --     $ --  
                 
(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 2011 was $60.3 million based on a grant date market price of our common units ranging from $40.54 to $43.70 per unit. An estimated annual forfeiture rate of 4.6% was applied to these awards.
(3)   The aggregate grant date fair value of restricted common unit awards issued in 2011 was $0.1 million based on a grant date market price of Duncan Energy Partners’ common units of $32.56 per unit. These awards 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 by the respective issuer.  Since these restricted common units are participating securities, such distributions are included in cash distributions paid to partners (post-Holdings Merger) and cash distributions paid to noncontrolling interests (pre-Holdings Merger) as presented on our Unaudited Condensed Statements of Consolidated Cash Flows.

The following table presents cash distributions paid with respect to our restricted common units and the total intrinsic value of restricted common units that vested during the periods presented:

   
For the Three Months
   
For the Nine Months
 
   
Ended September 30,
   
Ended September 30,
 
   
2011
   
2010
   
2011
   
2010
 
Cash distributions paid to restricted common unit holders
  $ 2.4     $ 2.0     $ 7.2     $ 5.8  
Total intrinsic value of restricted common unit awards vesting during period
  $ 2.3     $ 0.6     $ 37.5     $ 12.0  

For the EPCO group of companies, the unrecognized compensation cost associated with restricted common unit awards was an aggregate $61.3 million at September 30, 2011, of which our allocated share of the cost is currently estimated to be $57.9 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, these unit option awards have a vesting period of four years from the date of grant and expire five years after the date of grant.

 
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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, which incorporates various assumptions including expected life of the option, risk-free interest rates, expected distribution yield of our common units, and expected unit price volatility.  In general, our assumptions regarding the expected life of the options represent the period of time that the options are expected to be outstanding based on an analysis of our historical option activity.  Our selection of risk-free interest rates is based on published yields for U.S. government securities with comparable terms.  The unit price volatility and expected distribution yield assumptions are based on several factors, including an analysis of our common units historical market price and its distribution yield over a period of time equal to the expected life of the option, respectively.  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, 2010
    3,753,420     $ 28.08       3.6     $ --  
Unit options at September 30, 2011
    3,753,420     $ 28.08       2.9     $ 6.7  
Options exercisable at September 30, 2011 (2)
    --               --     $ --  
                                 
(1)   Aggregate intrinsic value reflects fully vested unit options at the date indicated. There were no vested unit options outstanding at December 31, 2010.
(2)   We were committed to issue 3,753,420 of our common units at September 30, 2011 if all outstanding options awarded were exercised. Option awards outstanding at September 30, 2011 include 712,280 awards that vested during the first nine months of 2011. Of the remaining outstanding option awards at September 30, 2011, 736,000, 1,520,140 and 785,000 will vest in 2012, 2013, and 2014, respectively. These unit option awards become exercisable in the calendar year following the year in which they vest.
 

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
September 30,
2010
   
For the Nine
Months
Ended
September 30,
2010
 
Total intrinsic value of unit option awards exercised during period
  $ 7.5     $ 9.7  
Cash received from EPCO in connection with the
exercise of unit option awards
    5.0       6.6  
Unit option-related reimbursements to EPCO
    7.5       9.7  

For the EPCO group of companies, the unrecognized compensation cost associated with unit option awards was an aggregate $4.4 million at September 30, 2011, of which our allocated share of the cost is currently estimated to be $3.9 million.  We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 1.7 years.

Other

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.

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

The following tables present information regarding UARs for the period presented:

UARs at December 31, 2010
    170,104  
Vested
    (17,776 )
Settled or forfeited
    (45,000 )
UARs at September 30, 2011
    107,328  

   
September 30,
2011
   
December 31,
2010
 
Accrued liability for UARs
  $ 0.4     $ 1.0  

At September 30, 2011, 107,328 UARs that had been granted under the 2006 Plan to certain employees of EPCO who work on our behalf were outstanding.  These awards are subject to five-year cliff vesting requirements and are expected to settle in 2012.  The grant date fair value with respect to these UARs is based on a unit price of $37.00 for our common units.  If the employee resigns prior to vesting, the UARs are forfeited.  Equity-based compensation expense associated with UARs was minimal for the three months ended September 30, 2011 and $0.2 million for the three months ended September 30, 2010.  For the nine months ended September 30, 2011 and 2010, equity-based compensation associated with UARs was a credit of $0.6 million and an expense of $0.5 million, respectively.

Limited partnership interests.   EPCO granted its key employees who perform services on behalf of us, EPCO and other affiliated companies, limited partnership interests in the Employee Partnerships, which were privately held affiliates of EPCO.  These partnerships were liquidated in August 2010.  Prior to liquidation, the limited partnership interests entitled each holder to participate in the expected long-term appreciation in value of the equity securities owned by each Employee Partnership.  Each Employee Partnership owned either Enterprise common units or Holdings’ units or a combination of both.  Equity-based compensation expense for the three and nine months ended September 30, 2010 includes $27.5 million and $31.3 million, respectively, of expense associated with these limited partnership interests.


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.  Derivatives are financial instruments whose fair value is determined by changes in a specified benchmark such as interest rates or commodity prices.  Fair value is generally defined as the amount at which a derivative instrument could be exchanged in a current transaction between willing parties, not in a forced sale.  Derivative instruments typically include futures, forward contracts, swaps, options and other instruments with similar characteristics.  Substantially all of our derivatives are used for non-trading activities.

We are required to recognize derivative instruments at fair value as either assets or liabilities on our balance sheet.  While all derivatives are required to be reported at fair value on the balance sheet, changes in fair value of the derivative instruments are reported in different ways, depending on the nature and effectiveness of the hedging activities to which they relate.  After meeting specified conditions, a qualified derivative may be designated as a total or partial hedge of:

§  
Changes in the fair value of a recognized asset or liability, or an unrecognized firm commitment – In a fair value hedge, gains and losses for both the derivative instrument and the hedged item are recognized in income during the period of change.

§  
Variable cash flows of a forecasted transaction – In a cash flow hedge, the effective portion of the hedge is reported in other comprehensive income (loss) and is reclassified into earnings when the forecasted transaction affects earnings.

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

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.  The effective portion of a hedge relationship is the amount by which the derivative instrument exactly offsets the change in fair value of the hedged item during the reporting period.  Conversely, ineffectiveness represents the change in the fair value of the derivative instrument that does not exactly offset the change in the fair value of the hedged item.  Any ineffectiveness associated with a hedge 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 probable of not 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 utilize interest rate swaps, treasury locks and similar derivative instruments to manage our exposure to changes in interest rates charged on borrowings under certain consolidated debt agreements.  This strategy is a component in controlling our overall cost of capital associated with such borrowings.

The following table summarizes our interest rate swap derivative instruments outstanding at September 30, 2011:

Hedged Transaction
Number and Type of
Derivative(s) Employed
Notional
Amount
Period of
Hedge
Rate
Swap
Accounting
Treatment
   Senior Notes C
1 fixed-to-floating swap
$100.0
1/04 to 2/13
6.4% to 2.3%
Fair value hedge
   Senior Notes G
3 fixed-to-floating swaps
$300.0
10/04 to 10/14
5.6% to 1.4%
Fair value hedge
   Senior Notes P
7 fixed-to-floating swaps
$400.0
6/09 to 8/12
4.6% to 2.6%
Fair value hedge
   Senior Notes AA
10 fixed-to-floating swaps
$750.0
1/11 to 2/16
3.2% to 1.2%
Fair value hedge
   Undesignated swaps
6 floating-to-fixed swaps
$600.0
5/10 to 7/14
0.2% to 2.0%
Mark-to-market

As of September 30, 2011, we had six interest rate swap contracts with a notional value of $600.0 million that have not been designated as hedges.   These derivative instruments are accounted for using mark-to-market accounting.  Mark-to-market net losses (a component of consolidated interest expense) attributable to these undesignated swaps were $8.8 million and $19.3 million for the three and nine months ended September 30, 2011, respectively.  In August 2011, two of these undesignated interest rate swaps (with a notional amount of $250 million) expired.

Interest rate swaps exchange the stated interest rate paid on a notional amount of debt for the fixed or floating interest rate stipulated in the derivative instrument.  Interest expense for the three months ended September 30, 2011 and 2010 reflects a decrease of $1.8 million and an increase of $1.3 million, respectively, attributable to interest rate swaps.   For the nine months ended September 30, 2011 and 2010, such swaps resulted in a decrease in interest expense of $9.3 million and $0.9 million, respectively.

The following table summarizes our forward starting interest rate swaps, which hedge the expected underlying benchmark interest rates related to forecasted issuances of debt, outstanding at September 30, 2011:

Hedged Transaction
Number and Type of
Derivatives Employed
Notional
Amount
Expected
Termination
Date
Average Rate
Locked
Accounting
Treatment
Future debt offering
10 forward starting swaps
$500.0
2/12
4.5%
Cash flow hedge
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


 
18

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

In connection with the issuance of Senior Notes during the nine months ended September 30, 2011 (see Note 10), we settled three forward starting swaps and two treasury locks having an aggregate notional amount of $1.47 billion, resulting in losses totaling $23.2 million.  These losses will be amortized to earnings (as an increase in interest expense) using the effective interest method over the forecasted hedged period.

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 agreements, futures contracts, fixed-for-float swaps, basis swaps and options contracts.  The following table summarizes our commodity derivative instruments outstanding at September 30, 2011:

 
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)
24.8 Bcf
n/a
Cash flow hedge
Forecasted sales of NGLs (4)
6.4 MMBbls
n/a
Cash flow hedge
Octane enhancement:
     
Forecasted sales of octane enhancement products
1.0 MMBbls
n/a
Cash flow hedge
Natural gas marketing:
     
Natural gas storage inventory management activities
10.4 Bcf
0.5 Bcf
Fair value hedge
NGL marketing:
     
Forecasted purchases of NGLs and related hydrocarbon products
1.1 MMBbls
n/a
Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products
1.5 MMBbls
n/a
Cash flow hedge
Refined products marketing:
     
Forecasted purchases of refined products
1.5 MMBbls
n/a
Cash flow hedge
Forecasted sales of refined products
1.7 MMBbls
n/a
Cash flow hedge
Crude oil marketing:
     
Forecasted purchases of crude oil
1.0 MMBbls
n/a
Cash flow hedge
Forecasted sales of crude oil
1.3 MMBbls
n/a
Cash flow hedge
Derivatives not designated as hedging instruments:
     
Natural gas risk management activities (5,6)
351.3 Bcf
65.1 Bcf
Mark-to-market
Refined products risk management activities (6)
1.6 MMBbls
n/a
Mark-to-market
Crude oil risk management activities (6)
5.4 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 2012, January 2013 and December 2013, respectively.
(3)   PTR represents the British thermal unit equivalent of the NGLs extracted from natural gas by a processing plant, and includes the natural gas used as plant fuel to extract those liquids, plant flare and other shortages.
(4)   Forecasted sales of NGL volumes under natural gas processing exclude 1.1 MMBbls of additional hedges executed under contracts that have been designated as normal sales agreements.
(5)   Current and long-term volumes include approximately 61.6 Bcf and 1.4 Bcf, respectively, 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.






 
19

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

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 of our expected equity NGL production at fixed prices through March 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.

Certain basis swaps, basis spread options and other derivative instruments not designated as hedging instruments are used to manage market risks associated with anticipated purchases and sales of natural gas necessary to optimize our owned and contractually committed transportation and storage capacity.

There is some uncertainty involved in the timing of these transactions often due to the development of more favorable profit opportunities or when spreads are insufficient to cover variable costs thus reducing the likelihood that the transactions will occur as originally forecasted.  As a result of this timing uncertainty, these derivative instruments do not qualify for hedge accounting even though they are effective at managing the risk exposures of these assets.

The earnings volatility caused by fluctuations in non-cash, mark-to-market earnings cannot be predicted and the impact to earnings could be material.
 
Credit-Risk Related Contingent Features in Derivative Instruments

A limited number of our commodity derivative instruments include provisions related to credit ratings and/or adequate assurance clauses.  A credit rating provision provides for a counterparty to demand immediate full or partial payment to cover a net liability position upon the loss of a stipulated credit rating.  An adequate assurance clause provides for a counterparty to demand immediate full or partial payment to cover a net liability position should reasonable grounds for insecurity arise with respect to contractual performance by either party.  At September 30, 2011, the aggregate fair value of our over-the-counter derivative instruments in a net liability position was $0.4 million.  The maximum potential cash payment under the contracts containing a credit rating contingent feature is $1.4 million.  The potential for derivatives with contingent features to enter a net liability position may change in the future as commodity positions and prices fluctuate. 








 
20

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

Tabular Presentation of Fair Value Amounts, and Gains and Losses on
Derivative Instruments and Related Hedged Items

The following table provides a balance sheet overview of our derivative assets and liabilities at the dates indicated:
 
 
Asset Derivatives
 
Liability Derivatives
 
 
September 30, 2011
 
December 31, 2010
 
September 30, 2011
 
December 31, 2010
 
 
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
  $ 44.3  
Other current
assets
  $ 30.3  
Other current
liabilities
  $ 152.0  
Other current
liabilities
  $ 5.5  
Interest rate derivatives
Other assets
    48.0  
Other assets
    77.8  
Other liabilities
    111.7  
Other liabilities
    26.2  
Total interest rate derivatives
      92.3         108.1         263.7         31.7  
Commodity derivatives
Other current
assets
    49.8  
Other current
assets
    46.3  
Other current
liabilities
    69.4  
Other current
liabilities
    93.0  
Commodity derivatives
Other assets
    0.2  
Other assets
    1.0  
Other liabilities
    --  
Other liabilities
    1.7  
Total commodity derivatives (1)
      50.0         47.3         69.4         94.7  
Total derivatives designated as
   hedging instruments
  $ 142.3       $ 155.4       $ 333.1       $ 126.4  
                                         
Derivatives not designated as hedging instruments
 
Interest rate derivatives
Other current
assets
  $ --  
Other current
assets
  $ --  
Other current
liabilities
  $ 11.2  
Other current
liabilities
  $ 21.0  
Interest rate derivatives
Other assets
    --  
Other assets
    --  
Other liabilities
    12.9  
Other liabilities
    0.9  
Total interest rate derivatives
      --         --         24.1         21.9  
Commodity derivatives
Other current
assets
    29.3  
Other current
assets
    38.6  
Other current
liabilities
    33.2  
Other current
liabilities
    41.2  
Commodity derivatives
Other assets
    6.8  
Other assets
    4.5  
Other liabilities
    2.9  
Other liabilities
    5.4  
Total commodity derivatives
      36.1         43.1         36.1         46.6  
Foreign currency derivatives
Other current
assets
    0.2  
Other current
assets
    0.3  
Other current
liabilities
    --  
Other current
liabilities
    0.1  
Total derivatives not designated as
   hedging instruments
  $ 36.3       $ 43.4       $ 60.2       $ 68.6  
                                         
(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.
 

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 Recognized in
Income on Derivative
 
     
For the Three Months
   
For the Nine Months
 
     
Ended September 30,
   
Ended September 30,
 
     
2011
   
2010
   
2011
   
2010
 
Interest rate derivatives
Interest expense
  $ 23.6     $ 8.1     $ 32.4     $ 27.1  
Commodity derivatives
Revenue
    8.6       6.1       7.3       9.0  
   Total
    $ 32.2     $ 14.2     $ 39.7     $ 36.1  

Derivatives in Fair Value
Hedging Relationships
 
Location
 
Loss Recognized in
Income on Hedged Item
 
     
For the Three Months
   
For the Nine Months
 
     
Ended September 30,
   
Ended September 30,
 
     
2011
   
2010
   
2011
   
2010
 
Interest rate derivatives
Interest expense
  $ (22.5 )   $ (8.6 )   $ (32.2 )   $ (26.8 )
Commodity derivatives
Revenue
    (7.7 )     (7.0 )     (8.8 )     (9.4 )
   Total
    $ (30.2 )   $ (15.6 )   $ (41.0 )   $ (36.2 )


 
21

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

The following tables present the effect of our derivative instruments designated as cash flow hedges on our Unaudited Condensed Statements of Consolidated Comprehensive Income and Consolidated Operations 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,
 
   
2011
   
2010
   
2011
   
2010
 
Interest rate derivatives (1)
  $ (260.1 )   $ (81.6 )   $ (306.1 )   $ (168.4 )
Commodity derivatives – Revenue (2)
    8.8       (44.2 )     (166.0 )     42.2  
Commodity derivatives – Operating costs and expenses
    (14.9 )     (19.9 )     (13.2 )     (73.2 )
Foreign currency derivatives
    --       0.1       --       (0.1 )
Total
  $ (266.2 )   $ (145.6 )   $ (485.3 )   $ (199.5 )
                                 
(1)   The other comprehensive loss recognized for interest rate derivatives for the third quarter of 2011 and year-to-date 2011 is primarily due to the impact of decreases in forward London Interbank Offered Rates (“LIBOR”) on our forward starting interest rate swap portfolio.  The change in fair value of this portfolio between June 30, 2011 and September 30, 2011 accounted for $242.7 million of the quarterly other comprehensive loss.  Any gain or loss ultimately recognized upon settlement of these cash flow hedges would be amortized into earnings as a reduction or increase, respectively, in interest expense over the forecasted hedge period of 10 years.
(2)   The increase in other comprehensive income for the third quarter of 2011 and loss for the year-to-date 2011 is primarily due to the impact of falling and rising prices, respectively, on our crude oil, refined products and NGL derivative instruments designated as cash flow hedges of future physical sales transactions.
 

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,
 
     
2011
   
2010
   
2011
   
2010
 
Interest rate derivatives
Interest expense
  $ (1.6 )   $ (8.1 )   $ (4.6 )   $ (21.4 )
Commodity derivatives
Revenue
    (33.2 )     39.2       (181.7 )     41.7  
Commodity derivatives
Operating costs and expenses
    (1.9 )     (13.6 )     2.9       (31.1 )
Foreign currency derivatives
Other income
    --       --       --       0.3  
   Total
    $ (36.7 )   $ 17.5     $ (183.4 )   $ (10.5 )

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,
 
     
2011
   
2010
   
2011
   
2010
 
Commodity derivatives
Revenue
  $ --     $ --     $ 0.2     $ --  
Commodity derivatives
Operating costs and expenses
    (0.9 )     (0.4 )     (0.9 )     2.5  
   Total
    $ (0.9 )   $ (0.4 )   $ (0.7 )   $ 2.5  

Over the next twelve months, we expect to reclassify $14.3 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 $32.2 million of losses attributable to commodity derivative instruments from accumulated other comprehensive loss to earnings, $10.8 million as an increase in operating costs and expenses and $21.4 million as a decrease in revenue.









 
22

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

The following table presents the effect of our derivative instruments not designated as hedging instruments on our Unaudited Condensed Statements of Consolidated Operations for the periods 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,
 
     
2011
   
2010
   
2011
   
2010
 
Interest rate derivatives
Interest expense
  $ (8.8 )   $ --     $ (19.3 )   $ --  
Commodity derivatives
Revenue
    4.3       17.0       17.6       12.0  
Commodity derivatives
Operating costs and expenses
    --       --       --       (1.5 )
Foreign currency derivatives
Other income
    0.2       0.1       0.2       0.1  
   Total
    $ (4.3 )   $ 17.1     $ (1.5 )   $ 10.6  

Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date.  Our fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk.  Recognized valuation techniques employ inputs such as product prices, operating costs, discount factors and business growth rates.  These inputs may be either readily observable, corroborated by market data or generally unobservable.  In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the extent possible.  Accordingly, we utilize valuation techniques (such as the market approach) that maximize the use of observable inputs and minimize the use of unobservable inputs.

A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements based on the observability of inputs used to estimate such fair values.  The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3).  At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy.

The following table sets forth, by level within the fair value hierarchy, the carrying values of our financial assets and liabilities at the date indicated.  These assets and liabilities are measured on a recurring basis and are classified within the table 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 September 30, 2011
 
   
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:
                       
Interest rate derivatives
  $ --     $ 92.3     $ --     $ 92.3  
Commodity derivatives
    43.9       36.9       5.3       86.1  
Foreign currency derivatives
    --       0.2       --       0.2  
Total
  $ 43.9     $ 129.4     $ 5.3     $ 178.6  
                                 
Financial liabilities:
                               
Interest rate derivatives
  $ --     $ 287.8     $ --     $ 287.8  
Commodity derivatives
    49.6       51.3       4.6       105.5  
Total
  $ 49.6     $ 339.1     $ 4.6     $ 393.3  



 
23

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

The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:

§  
Level 1 fair values are based on quoted prices, which are available in active markets for identical assets or liabilities as of the measurement date.  Active markets are defined as those in which transactions for identical assets or liabilities occur with sufficient frequency so as to provide pricing information on an ongoing basis (e.g., the New York Mercantile Exchange).  Our Level 1 fair values consist of financial assets and liabilities such as exchange-traded commodity derivative instruments.

§  
Level 2 fair values are based on pricing inputs other than quoted prices in active markets (as reflected in Level 1 fair values) and are either directly or indirectly observable as of the measurement date.  Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies.  Such financial models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, the time value of money, volatility factors, current market and contractual prices for the underlying instruments and other relevant economic measures.  Substantially all of these assumptions (i) are observable in the marketplace throughout the full term of the instrument; (ii) can be derived from observable data; or (iii) are validated by inputs other than quoted prices (e.g., interest rate and yield curves at commonly quoted intervals).  Our Level 2 fair values primarily consist of commodity derivative instruments such as forwards, swaps and other instruments transacted on an exchange or over-the-counter and interest rate derivative instruments.  The fair values of these derivative instruments are based on observable price quotes for similar products and locations.  The fair value of our interest rate derivatives are determined using financial models that incorporate the implied forward London Interbank Offered Rate yield curve for the same period as the future interest rate swap settlements.

§  
Level 3 fair values are based on unobservable inputs.  Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.  Unobservable inputs reflect management’s ideas about the assumptions that market participants would use in pricing an asset or liability (including assumptions about risk).  Unobservable inputs are based on the best information available to us in the circumstances, which might include our internally developed data.  Level 3 inputs are typically used in connection with internally developed valuation methodologies where we make our best estimate of an instrument’s fair value.  Our Level 3 fair values primarily consist of ethane, normal butane and natural gasoline-based contracts with terms greater than one year and certain options used to hedge natural gas storage inventory and transportation capacities.  In addition, we often rely on price quotes from reputable brokers who publish price quotes on certain products and compare these prices to other reputable brokers for the same products in the same markets whenever possible.  These prices, when combined with data from our commodity derivative instruments, are used in our models to determine the fair value of such instruments.

Transfers within the fair value hierarchy routinely occur for certain term contracts as prices and other inputs used for the valuation of future delivery periods become more observable with the passage of time.  Other transfers are made periodically in response to changing market conditions that affect liquidity, price observability and other inputs used in determining valuations.  Based on an assessment completed during the first quarter of 2011, we transferred ethane, normal butane and natural gasoline-based contracts with terms ranging from two months to one year from Level 3 to Level 2.  These transfers were made after a sustained increase in the observability of forward prices for these energy commodity products relative to the date range stated above as demonstrated by narrowing bid/offer spreads, higher transaction volumes and more activity and liquidity for these types of contracts.  With the exception of the transfers noted above, no other transfers were made between fair value levels during the year-to-date period.


 
24

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 Level 3 financial assets and liabilities for the periods presented:

   
For the Nine Months
Ended September 30,
 
   
2011
   
2010
 
Balance, January 1
  $ (25.9 )   $ 5.7  
Total gains (losses) included in:
               
Net income (1)
    (0.5 )     (3.6 )
Other comprehensive income (loss)
    16.2       (8.3 )
Settlements
    0.8       3.6  
Transfers out of Level 3 (2)
    9.8       --  
Balance, March 31
    0.4       (2.6 )
Total gains included in:
               
Net income (1)
    1.9       16.2  
Other comprehensive income (loss)
    --       22.2  
Settlements
    (0.2 )     (16.2 )
Transfers out of Level 3
    --       0.2  
Balance, June 30
    2.1       19.8  
Total gains (losses) included in:
               
Net income (1)
    0.8       18.2  
Other comprehensive income (loss)
    --       (31.4 )
Settlements
    (2.2 )     (16.1 )
Balance, September 30
  $ 0.7     $ (9.5 )
                 
(1)   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. There were $6.4 million and $4.1 million of unrealized gains included in these amounts for the three and nine months ended September 30, 2010, respectively.
(2)   Transfers out of Level 3 into Level 2 were primarily due to the change in observability of forward NGL prices as described above.
 

Nonfinancial Assets and Liabilities

Using appropriate valuation techniques, we reduced the carrying value of certain pipeline assets recorded as property, plant and equipment to fair value based on the present value of expected future cash flows (Level 3), resulting in a nonrecurring fair value adjustment (i.e., a non-cash asset impairment charge) totaling $5.2 million during the nine months ended September 30, 2011.  This impairment charge resulted from the anticipated abandonment of certain pipeline laterals on our TPC Offshore gathering system.

During the nine months ended September 30, 2010, certain pipeline assets recorded as property, plant and equipment were adjusted to fair value based on the present value of expected future cash flows (Level 3), resulting in nonrecurring fair value adjustments totaling $1.5 million.

The non-cash asset impairment charges we recorded during the nine months ended September 30, 2011 and 2010 are a component of operating costs and expenses.













 
25

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

Note 5.  Inventories

Inventories primarily consist of NGLs, petrochemicals and refined products, crude oil and natural gas volumes that are valued at the lower of average cost or market.   We capitalize, as a cost of inventory, shipping and handling charges (e.g., pipeline transportation and storage fees) and other related costs associated with purchased volumes.  As volumes are sold and delivered out of inventory, the cost of these volumes (including freight-in charges that have been capitalized as part of inventory cost) are charged to operating costs and expenses.  Our inventory amounts by product type were as follows at the dates indicated:

   
September 30,
2011
   
December 31,
2010
 
NGLs
  $ 666.7     $ 548.3  
Petrochemicals and refined products
    566.3       399.7  
Crude oil
    103.7       121.1  
Natural gas
    52.6       64.7  
Other
    --       0.2  
Total
  $ 1,389.3     $ 1,134.0  

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.  In general, our inventory levels have increased since December 31, 2010 due to an increase in the average cost of NGLs and seasonal supply and demand fluctuations.

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 September 30,
   
For the Nine Months
Ended September 30,
 
   
2011
   
2010
   
2011
   
2010
 
Cost of sales (1)
  $ 9,787.6     $ 6,814.0     $ 28,397.2     $ 20,499.5  
Lower of cost or market adjustments
    5.1       0.2       6.8       7.1  
(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.
 

















 
26

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

Note 6.  Assets Held for Sale

During September 2011, we committed to a formal plan to sell the equity interests of a wholly owned subsidiary, Crystal Holding L.L.C. (“Crystal”), which owns two underground salt dome natural gas storage facilities and associated pipelines located near Petal and Hattiesburg, Mississippi.  The facilities have a combined 28.8 Bcf of total storage capacity (of which 18.6 Bcf is total working gas capacity) and are owned by Petal Gas Storage, L.L.C. (“Petal”) and Hattiesburg Gas Storage Company (“Hattiesburg”).  At September 30, 2011, the assets and liabilities of Crystal were classified as held for sale and we stopped depreciating and amortizing the Crystal assets. Crystal’s operations are a component of our Onshore Natural Gas Pipelines & Services business segment.

On October 16, 2011, we announced the execution of definitive agreements to sell our ownership interests in Crystal to Boardwalk HP Storage Company, LLC for $550 million in cash.  This transaction is subject to customary regulatory approvals and is expected to close during the fourth quarter of 2011.

The following table presents the major classes of assets and liabilities designated as held for sale on our consolidated balance sheet at September 30, 2011.  With the exception of certain amounts recorded in property, plant and equipment and other assets, the amounts in the table all relate to Crystal.

Assets held for sale:
     
   Current assets
  $ 9.5  
   Property, plant and equipment, net  (1)
    374.8  
   Intangible assets, net
    41.2  
   Goodwill
    14.8  
   Other assets (2)