10-Q 1 epd10q_063011.htm QUARTERLY REPORT epd10q_063011.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 June 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 845,829,272 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 July 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.

Item 1.  Financial Statements.

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

   
June 30,
   
December 31,
 
ASSETS
 
2011
   
2010
 
Current assets:
           
Cash and cash equivalents
  $ 109.1     $ 65.5  
Restricted cash
    116.2       98.7  
Accounts receivable – trade, net of allowance for doubtful accounts
of $13.8 at June 30, 2011 and $18.4 at December 31, 2010
    4,274.3       3,800.1  
Accounts receivable – related parties
    37.7       36.8  
Inventories
    994.1       1,134.0  
Prepaid and other current assets
    407.1       372.0  
Total current assets
    5,938.5       5,507.1  
Property, plant and equipment, net
    20,798.9       19,332.9  
Investments in unconsolidated affiliates
    2,085.9       2,293.1  
Intangible assets, net of accumulated amortization of $966.5 at
    June 30, 2011 and $932.3 at December 31, 2010
    1,756.6       1,841.7  
Goodwill
    2,107.1       2,107.7  
Other assets
    291.4       278.3  
Total assets
  $ 32,978.4     $ 31,360.8  
                 
LIABILITIES AND EQUITY
               
Current liabilities:
               
Current maturities of debt
  $ 782.3     $ 282.3  
Accounts payable – trade
    770.3       542.0  
Accounts payable – related parties
    183.2       133.1  
Accrued product payables
    4,786.0       4,164.8  
Accrued interest
    271.0       252.9  
Other current liabilities
    566.0       505.1  
Total current liabilities
    7,358.8       5,880.2  
Long-term debt: (see Note 9)
    13,544.7       13,281.2  
Deferred tax liabilities
    80.9       78.0  
Other long-term liabilities
    218.7       220.6  
Commitments and contingencies
               
Equity: (see Note 10)
               
Partners’ equity:
               
Limited partners:
               
Common units (845,835,948 units outstanding at June 30, 2011
and 843,681,572 units outstanding at December 31, 2010)
    11,241.9       11,288.2  
Class B units (4,520,431 units outstanding at June 30, 2011 and
December 31, 2010)
    118.5       118.5  
Accumulated other comprehensive loss
    (106.2 )     (32.5 )
Total  partners’ equity
    11,254.2       11,374.2  
Noncontrolling interest
    521.1       526.6  
Total equity
    11,775.3       11,900.8  
Total liabilities and equity
  $ 32,978.4     $ 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 Six Months
 
   
Ended June 30,
   
Ended June 30,
 
   
2011
   
2010
   
2011
   
2010
 
Revenues:
                       
Third parties
  $ 11,072.3     $ 7,427.4     $ 21,005.9     $ 15,739.5  
Related parties
    144.2       116.0       394.3       348.4  
Total revenues (see Note 11)
    11,216.5       7,543.4       21,400.2       16,087.9  
Costs and expenses:
                               
Operating costs and expenses:
                               
Third parties
    10,140.6       6,676.1       19,252.1       14,324.0  
Related parties
    392.7       298.1       818.3       622.1  
Total operating costs and expenses
    10,533.3       6,974.2       20,070.4       14,946.1  
General and administrative costs:
                               
Third parties
    16.3       16.4       29.2       32.7  
Related parties
    34.1       24.1       59.1       48.1  
Total general and administrative costs
    50.4       40.5       88.3       80.8  
Total costs and expenses (see Note 11)
    10,583.7       7,014.7       20,158.7       15,026.9  
Equity in income of unconsolidated affiliates
    11.1       11.0       27.3       37.6  
Operating income
    643.9       539.7       1,268.8       1,098.6  
Other income (expense):
                               
Interest expense
    (188.3 )     (179.2 )     (372.1 )     (337.1 )
Interest income
    0.3       0.5       0.6       0.7  
Other, net
    --       (0.1 )     0.2       (0.2 )
Total other expense, net
    (188.0 )     (178.8 )     (371.3 )     (336.6 )
Income before provision for income taxes
    455.9       360.9       897.5       762.0  
Provision for income taxes
    (7.4 )     (6.5 )     (14.5 )     (15.2 )
Net income
    448.5       354.4       883.0       746.8  
Net income attributable to noncontrolling interest (see Note 10)
    (14.8 )     (300.3 )     (28.6 )     (622.8 )
Net income attributable to partners
  $ 433.7     $ 54.1     $ 854.4     $ 124.0  
                                 
Allocation of net income attributable to partners:
                               
Limited partners
  $ 433.7     $ 54.1     $ 854.4     $ 124.0  
General partner
  $ --     $ *     $ --     $ *  
                                 
Earnings per unit (see Note 13)
                               
Basic earnings per unit
  $ 0.53     $ 0.26     $ 1.05     $ 0.59  
Diluted earnings per unit
  $ 0.51     $ 0.26     $ 1.00     $ 0.59  















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 Six Months
 
   
Ended June 30,
   
Ended June 30,
 
   
2011
   
2010
   
2011
   
2010
 
                         
Net income
  $ 448.5     $ 354.4     $ 883.0     $ 746.8  
Other comprehensive income (loss):
                               
Cash flow hedges:
                               
Commodity derivative instrument gains (losses) during period
    (21.7 )     92.0       (173.1 )     33.1  
Reclassification adjustment for (gains) losses included in net income
related to commodity derivative instruments
    74.8       (1.5 )     143.7       15.0  
Interest rate derivative instrument losses during period
    (60.1 )     (79.3 )     (46.0 )     (86.8 )
Reclassification adjustment for losses included in net income
related to interest rate derivative instruments
    1.5       7.2       3.0       13.3  
Foreign currency derivative losses during period
    --       (0.1 )     --       (0.2 )
Reclassification adjustment for gains included in net income
related to foreign currency derivative instruments
    --       --       --       (0.3 )
Total cash flow hedges
    (5.5 )     18.3       (72.4 )     (25.9 )
Foreign currency translation adjustment
    --       (0.8 )     --       (0.2 )
Change in funded status of pension and postretirement plans, net of tax
    (0.9 )     --       (0.6 )     (0.9 )
Proportionate share of other comprehensive income (loss) of
unconsolidated affiliate
    0.3       (1.4 )     (0.7 )     (0.4 )
Total other comprehensive income (loss)
    (6.1 )     16.1       (73.7 )     (27.4 )
Comprehensive income
    442.4       370.5       809.3       719.4  
Comprehensive income attributable to noncontrolling interest
    (14.8 )     (321.3 )     (28.6 )     (600.8 )
Comprehensive income attributable to partners
  $ 427.6     $ 49.2     $ 780.7     $ 118.6  



























See Notes to Unaudited Condensed Consolidated Financial Statements.


ENTERPRISE PRODUCTS PARTNERS L.P.
(Dollars in millions)

   
For the Six Months
 
   
Ended June 30,
 
   
2011
   
2010
 
Operating activities:
           
Net income
  $ 883.0     $ 746.8  
Adjustments to reconcile net income to net cash
 flows provided by operating activities:
               
Depreciation, amortization and accretion
    484.8       453.5  
Non-cash asset impairment charges
    --       1.5  
Equity in income of unconsolidated affiliates
    (27.3 )     (37.6 )
Distributions received from unconsolidated affiliates
    84.8       101.3  
Operating lease expenses paid by EPCO
    0.3       0.3  
Gains from asset sales and related transactions
    (23.6 )     (5.7 )
Deferred income tax expense
    2.3       1.3  
Changes in fair market value of derivative instruments
    (10.7 )     (4.9 )
Effect of pension settlement recognition
    (0.5 )     (0.2 )
Net effect of changes in operating accounts (see Note 16)
    361.4       (335.9 )
Net cash flows provided by operating activities
    1,754.5       920.4  
Investing activities:
               
Capital expenditures
    (1,716.2 )     (746.8 )
Contributions in aid of construction costs
    6.4       8.7  
Decrease (increase) in restricted cash
    (17.5 )     52.6  
Cash used for business combinations
    --       (1,220.2 )
Investments in unconsolidated affiliates
    (11.8 )     (10.2 )
Proceeds from asset sales and related transactions
    250.5       24.1  
Other investing activities
    (3.6 )     --  
Cash used in investing activities
    (1,492.2 )     (1,891.8 )
Financing activities:
               
Borrowings under debt agreements
    3,791.1       3,593.9  
Repayments of debt
    (3,033.5 )     (2,256.7 )
Debt issuance costs
    (12.8 )     (14.8 )
Cash distributions paid to partners
    (966.5 )     (149.6 )
Cash distributions paid to noncontrolling interest
    (34.8 )     (720.5 )
Cash contributions from noncontrolling interest
    2.6       961.9  
Net cash proceeds from issuance of common units
    45.1       --  
Acquisition of treasury units
    (9.6 )     (3.0 )
Other financing activities
    (0.3 )     1.3  
Cash provided by (used in) financing activities
    (218.7 )     1,412.5  
Effect of exchange rate changes on cash
    --       0.1  
Net change in cash and cash equivalents
    43.6       441.1  
Cash and cash equivalents, January 1
    65.5       55.3  
Cash and cash equivalents, June 30
  $ 109.1     $ 496.5  












See Notes to Unaudited Condensed Consolidated Financial Statements.


ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY
(See Note 10 for Unit History, Accumulated Other Comprehensive Loss and Noncontrolling Interest)
(Dollars in millions)

   
Partners’ Equity
             
   
Limited
 Partners
   
Accumulated
Other
Comprehensive
Loss
   
Noncontrolling
Interest
   
Total
 
Balance, December 31, 2010
  $ 11,406.7     $ (32.5 )   $ 526.6     $ 11,900.8  
Net income
    854.4       --       28.6       883.0  
Operating lease expenses paid by EPCO
    0.3       --       --       0.3  
Cash distributions paid to partners
    (966.5 )     --       --       (966.5 )
Cash distributions paid to noncontrolling interest
    --       --       (34.8 )     (34.8 )
Cash contributions from noncontrolling interest
    --       --       2.6       2.6  
Net cash proceeds from issuance of common units
    45.1       --       --       45.1  
Acquisition of treasury units
    (9.6 )     --       --       (9.6 )
Amortization of equity awards
    25.2       --       0.1       25.3  
Change in value of cash flow hedges
    --       (72.4 )     --       (72.4 )
Proportionate share of other comprehensive loss of
     unconsolidated affiliate
    --       (0.7 )     --       (0.7 )
Other
    4.8       (0.6 )     (2.0 )     2.2  
Balance, June 30, 2011
  $ 11,360.4     $ (106.2 )   $ 521.1     $ 11,775.3  



   
Partners’ Equity
             
   
Limited
 Partners
   
General
 Partner
   
Accumulated
Other
Comprehensive
Loss
   
Noncontrolling
Interest
   
Total
 
Balance, December 31, 2009
  $ 1,972.4     $ *     $ (33.3 )   $ 8,534.0     $ 10,473.1  
Net income
    124.0       *       --       622.8       746.8  
Operating lease expenses paid by EPCO
    --       --       --       0.3       0.3  
Cash distributions paid to partners
    (149.6 )     *       --       --       (149.6 )
Cash distributions paid to noncontrolling interest
    --       --       --       (720.5 )     (720.5 )
Cash contributions from noncontrolling interest
    --       --       --       961.9       961.9  
Acquisition of treasury units
    --       --       --       (3.0 )     (3.0 )
Amortization of equity awards
    1.1       --       --       18.2       19.3  
Change in value of cash flow hedges
    --       --       (5.0 )     (20.9 )     (25.9 )
Proportionate share of other comprehensive loss of
unconsolidated affiliate
    --       --       (0.4 )     --       (0.4 )
Other
    --       --       --       (1.1 )     (1.1 )
Balance, June 30, 2010
  $ 1,947.9     $ *     $ (38.7 )   $ 9,391.7     $ 11,300.9  













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

 
6

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

Except per unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in millions of dollars.

SIGNIFICANT RELATIONSHIPS REFERENCED IN THESE
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unless the context requires otherwise, references to “we,” “us,” “our,” “Enterprise” or “Enterprise Products Partners” are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries.  References to “EPO” mean Enterprise Products Operating LLC, which is a wholly owned subsidiary of Enterprise, and its consolidated subsidiaries, through which Enterprise conducts substantially all of 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; (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 currently directors of EPCO. 

References to “Duncan Energy Partners” mean Duncan Energy Partners L.P. (NYSE: DEP), which is a consolidated subsidiary of EPO.  References to “DEP GP” mean DEP Holdings, LLC, which is the general partner of Duncan Energy Partners and a wholly owned subsidiary of EPO.  On April 28, 2011, we, our general partner, and two of our subsidiaries entered into a definitive merger agreement with Duncan Energy Partners and DEP GP.  See Note 1 for information regarding the proposed merger of Duncan Energy Partners with a subsidiary of Enterprise.

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. (NYSE: ETE) and its consolidated subsidiaries, which include Energy Transfer Partners, L.P. (“ETP”) and Regency Energy Partners LP (“RGNC”).  The general partner of Energy Transfer Equity is LE GP, LLC (“LE GP”).  We own noncontrolling interests in Energy Transfer Equity, which we account for using the equity method of accounting.

 
7

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

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.

Duncan Energy Partners and Energy Transfer Equity electronically file certain documents 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 periodic reports and other information regarding these registrants.
 

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 NYSE under the ticker symbol EPD.  We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO.  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 50,200 miles of onshore and offshore pipelines; 190 million barrels (“MMBbls”) of storage capacity for NGLs, refined products and crude oil; and 27 billion cubic feet (“Bcf”) of natural gas storage capacity. 

Our midstream energy operations include: natural gas gathering, treating, processing, transportation and storage; NGL transportation, fractionation, storage, and import and export terminaling; crude oil and refined products transportation, storage, and terminaling; offshore production platforms; petrochemical transportation and services; and a marine transportation business that operates primarily on the 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 11 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 12 for information regarding the ASA and other related party matters.

Agreement and Plan of Merger with Duncan Energy Partners

On April 28, 2011, we entered into an Agreement and Plan of Merger (the “Duncan Merger Agreement”), by and among Enterprise, Enterprise GP, EPD MergerCo LLC (“Duncan MergerCo,” a Delaware limited liability company and a wholly owned subsidiary of Enterprise), Duncan Energy Partners and DEP GP.  At the effective time of the merger, Duncan MergerCo will merge with and into Duncan Energy Partners, pursuant to the Duncan Merger Agreement, with Duncan Energy Partners surviving the merger as a wholly owned subsidiary of Enterprise (the “Duncan Merger”), and all of the outstanding Duncan Energy Partners common units at the effective time of the merger will be 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.

On September 7, 2011, Duncan Energy Partners will host a special meeting of its unitholders to consider and vote upon approval of the Duncan Merger Agreement and the Duncan Merger.  The Duncan

 
8

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

Merger Agreement and the Duncan Merger must be approved by the affirmative vote or consent of holders of (i) a majority of the outstanding common units of Duncan Energy Partners and (ii) a majority of the Duncan Energy Partners common units owned by the Duncan Unaffiliated Unitholders (as defined in the Duncan Merger Agreement) that actually vote for or against such approval.  In connection with the Duncan Merger Agreement, we, Duncan Energy Partners and Enterprise GTM Holdings L.P., a Delaware limited partnership and a wholly owned subsidiary of Enterprise (“Enterprise GTM”), entered into a Voting Agreement, dated as of April 28, 2011 (the “Voting Agreement”), pursuant to which Enterprise GTM and Enterprise agreed to vote any of the Duncan Energy Partners common units owned by them or their subsidiaries in favor of the adoption of the Duncan Merger Agreement and the Duncan Merger at any meeting of the Duncan Energy Partners unitholders, including the 33,783,587 Duncan Energy Partners common units currently directly owned by Enterprise GTM (representing approximately 58.5% of the outstanding common units of Duncan Energy Partners).  The Voting Agreement will terminate upon the termination of the Duncan Merger Agreement.

The Duncan Merger Agreement contains customary representations, warranties and covenants by each of the parties.  Completion of the Duncan Merger is conditioned upon, among other things: (i) requisite Duncan Energy Partners unitholder approval of the Duncan Merger Agreement and the Duncan Merger; (ii) applicable regulatory approvals; (iii) the absence of certain legal injunctions or impediments prohibiting the transactions; (iv) the effectiveness of a registration statement on Form S-4 with respect to the issuance by Enterprise of the Enterprise common units in connection with the Duncan Merger (the Form S-4 was declared effective by the SEC on August 1, 2011); (v) the receipt of certain tax opinions; and (vi) approval for the listing of the Enterprise common units issued in connection with the Duncan Merger on the NYSE.

Basis of Presentation

Holdings Merger.  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 general partner 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 during the following periods, if any: 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).

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

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

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 (our 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 interest.  See Note 10 for additional information regarding noncontrolling interests.

The historical limited partner units outstanding and earnings per unit amounts presented in our financial statements have been retroactively presented in connection with the 1.5 to one unit-for-unit exchange that occurred under the Holdings Merger.  See Note 13 for additional information regarding earnings per unit.

Consolidation of Duncan Energy Partners.  For financial reporting purposes, we consolidate the financial statements of Duncan Energy Partners with those of our own and reflect its operations in our business segments.  We control Duncan Energy Partners through our ownership of its general partner. Public ownership of Duncan Energy Partners’ net assets and earnings are presented as a component of noncontrolling interest in our consolidated financial statements.  The borrowings of Duncan Energy Partners are presented as part of our consolidated debt.  However, neither Enterprise Products Partners nor EPO have any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners. Since we consolidate Duncan Energy Partners for financial reporting purposes, the proposed Duncan Merger would not change the basis of presentation of our historical financial statements.


Note 2.  General Accounting Matters

Our results of operations for the three and six months ended June 30, 2011 are not necessarily indicative of results expected for the full year.  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.  Our procedure for determining 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 account 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.  Our allowance also includes estimates for uncollectible natural gas imbalances based on specific identification of accounts.





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

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

   
For the Six Months
 
   
Ended June 30,
 
   
2011
   
2010
 
Balance at beginning of period
  $ 18.4     $ 16.8  
Charged to costs and expenses
    0.6       0.7  
Deductions (1)
    (5.2 )     --  
Balance at end of period
  $ 13.8     $ 17.5  
                 
(1)   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 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 proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.

We accrue an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated.  If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued.  We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when it is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss.  Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed.  See Note 14 for additional information regarding our contingencies.

Derivative Instruments

We use derivative instruments such as swaps, forwards and other contracts 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 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.

We apply the normal purchases/normal sales exception for certain of our derivative instruments, which precludes the recognition of changes in mark-to-market values for these items on our balance sheet or income statement.  Revenues and costs for these transactions are recognized when volumes are physically delivered or received.

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



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

Earnings Per Unit

Earnings per unit is based on the amount of net income attributable to limited partners and the weighted-average number of units outstanding during the period.  See Note 1 for information regarding the retroactive presentation of earnings per unit amounts for the three and six months ended June 30, 2010 in connection with the Holdings Merger.

Estimates

Preparing our financial statements in conformity with GAAP requires management to make estimates and assumptions that affect amounts presented in the financial statements (i.e. assets, liabilities, revenue and expenses) and disclosures about contingent assets and liabilities.  Our actual results could differ from these estimates.  On an ongoing basis, management reviews its estimates based on currently available information.  Any future changes in facts and circumstances may require updated estimates, which, in turn, could have a significant impact on our financial statements.

Fair Value Information

The carrying amounts of cash and cash equivalents (including restricted cash), accounts receivable and accounts payable approximate their fair value.  See Note 4 for fair value information associated with our derivative instruments.

The estimated fair value of our fixed-rate debt obligations was approximately $14.09 billion and $12.91 billion at June 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 carrying amounts of our variable-rate debt obligations reasonably approximate their fair values due to their variable interest rates.

We do not have any long-term investments in debt or equity securities carried at fair value.  See Note 7 for summarized financial information of our investments accounted for using the equity method.

Liquids Exchange Contracts

Our liquids exchange balances were net payables of $212.4 million and $144.1 million at June 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 62% and 85% of our liquids exchange transactions recorded at June 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 our customer and allows us to operate our plants more effectively.

To the extent that the volumes we receive under such exchange agreements exceed those we deliver under the agreements (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 volumes we deliver exceed those we receive (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.

 
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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
                Volumetric receivables and payables arising from exchange transactions 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

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 (“OCI”).  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 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 OCI, reclassification adjustments for each component of OCI will have to be displayed in both net income and OCI.  We will adopt this guidance on January 1, 2012 and apply its presentation requirements retrospectively 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 June 30, 2011 and December 31, 2010, our restricted cash amounts were $116.2 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 Six Months
 
   
Ended June 30,
   
Ended June 30,
 
   
2011
   
2010
   
2011
   
2010
 
Restricted unit awards
  $ 12.1     $ 7.9     $ 23.5     $ 13.7  
Unit option awards
    0.8       0.7       1.7       1.4  
Other (1)
    0.3       2.5       (0.2 )     4.7  
Total compensation expense
  $ 13.2     $ 11.1     $ 25.0     $ 19.8  
                                 
(1)   Primarily consists of unit appreciation rights (“UARs”), phantom units and similar awards. Also, the amounts presented for 2010 consist of awards related to limited partnership interests in the Employee Partnerships.
 

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

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

based on the fair value of the award remeasured at each reporting period.  Liability-classified awards are settled in cash upon vesting.

At June 30, 2011, EPCO’s significant long-term incentive plans applicable to us were the Enterprise Products 1998 Long-Term Incentive Plan (“1998 Plan”), the Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan (“2008 Plan”) and the 2010 Duncan Energy Partners L.P. Long-Term Incentive Plan (“2010 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 Plan.  After giving effect to awards granted under the plan through June 30, 2011, a total of 1,475,190 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 June 30, 2011, a total of 4,706,877 additional common units could be issued.

The 2010 Plan provides for awards to employees, directors or consultants providing services to Duncan Energy Partners.  Awards under the 2010 Plan may be granted in the form of options to purchase Duncan Energy Partners’ common units, restricted common units, UARs, phantom units and DERs.  Up to 500,000 of Duncan Energy Partners’ common units may be issued as awards under the 2010 Plan.  After giving effect to awards granted under the plan through June 30, 2011, a total of 489,986 additional common units could be issued.  The Duncan Merger Agreement contains restrictions on the issuance of additional awards under the 2010 Plan.  See Note 1 for information regarding the proposed merger of Duncan Energy Partners with a subsidiary of Enterprise.

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 may be denominated in our common units or 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 period 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)
    1,359,230     $ 43.68  
Vested
    (828,545 )   $ 31.57  
Forfeited
    (75,857 )   $ 32.67  
    Restricted common units at June 30, 2011
    4,016,442     $ 34.06  
                 
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 June 30, 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 $59.4 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 interest (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 Six Months
 
   
Ended June 30,
   
Ended June 30,
 
   
2011
   
2010
   
2011
   
2010
 
Cash distributions paid to restricted common unit holders
  $ 2.7     $ 2.3     $ 4.8     $ 3.8  
Total intrinsic value of restricted common unit awards vesting during period
    20.5       10.3       35.2       11.4  

For the EPCO group of companies, the unrecognized compensation cost associated with restricted common unit awards was an aggregate $73.5 million at June 30, 2011, of which our allocated share of the cost is currently estimated to be $69.4 million.  We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 2.0 years.

Unit Option Awards

EPCO’s long-term incentive plans provide for the issuance of non-qualified incentive options.  These unit option awards may be denominated in our common units or those of Duncan Energy Partners depending on the issuer of the award.  When issued, the exercise price of each unit option award may be no less than the market price of the underlying security 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 the underlying security, 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 the underlying security’s 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.  As of June 30, 2011, only Enterprise has issued unit option awards.

   
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 June 30, 2011
    3,753,420     $ 28.08       3.1     $ 7.3  
Options exercisable at June 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 June 30, 2011 if all outstanding options awarded were exercised. Option awards outstanding at June 30, 2011 include 612,280 awards that vested during the first six months of 2011. Of the remaining outstanding option awards at June 30, 2011, 100,000, 736,000, 1,520,140 and 785,000 will vest in 2011, 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
   
For the Six Months
 
   
Ended June 30,
   
Ended June 30,
 
   
2011
   
2010
   
2011
   
2010
 
Total intrinsic value of unit option awards exercised during period
  $ --     $ 1.3     $ --     $ 2.2  
Cash received from EPCO in connection with the
exercise of unit option awards
    --       1.0       --       1.6  
Unit option-related reimbursements to EPCO
    --       1.3       --       2.2  

For the EPCO group of companies, the unrecognized compensation cost associated with unit option awards was an aggregate $5.0 million at June 30, 2011, of which our allocated share of the cost is currently estimated to be $4.5 million.  We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 1.9 years.






 
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ENTERPRISE PRODUCTS PARTNERS L.P.
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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 the underlying security over the grant date fair value of the award.  UARs are accounted for as liability awards.  All of the UARs outstanding at June 30, 2011 are denominated in Enterprise common units.

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

UARs at December 31, 2010
    170,104  
Vested
    (10,939 )
Settled or forfeited
    (45,000 )
UARs at June 30, 2011
    114,165  

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

At June 30, 2011, 114,165 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 June 30, 2011 and $0.2 million for the three months ended June 30, 2010.  For the six months ended June 30, 2011 and 2010, equity-based compensation expense associated with UARs was a credit of $0.6 million and an expense of $0.3 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 six months ended June 30, 2010 includes $1.9 million and $3.8 million, respectively, of expense associated with these limited partnership interests.





















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

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.

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.










 
18

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

The following table summarizes our interest rate derivative instruments outstanding at June 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 2.7%
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
   Non-Hedged Swaps
2 floating-to-fixed swaps
$250.0
9/07 to 8/11
0.3% to 4.8%
Mark-to-market
   Non-Hedged Swaps
6 floating-to-fixed swaps
$600.0
5/10 to 7/14
0.3% to 2.0%
Mark-to-market

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 June 30, 2011 and 2010 reflects an increase of $2.2 million and a decrease of $0.8 million, respectively, attributable to interest rate swaps.   For the six months ended June 30, 2011 and 2010, such swaps resulted in a decrease in interest expense of $7.5 million and $2.2 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 June 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
5 forward starting swaps
$250.0
8/12
3.9%
Cash flow hedge
Future debt offering
16 forward starting swaps
$1,000.0
3/13
3.7%
Cash flow hedge

In connection with the issuance of Senior Notes AA and BB (see Note 9), we settled three forward starting swaps in January 2011 having a notional amount of $250 million, resulting in a loss of $5.7 million.  This loss will be amortized to earnings (as an increase in interest expense) using the effective interest method over the forecasted hedged period.























 
19

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

Commodity Derivative Instruments

The prices of natural gas, NGLs, crude oil, refined products and certain petrochemical products are subject to fluctuations in response to changes in supply and demand, market conditions and a variety of additional factors that are beyond our control.  In order to manage such price risks, we enter into commodity derivative instruments such as physical forward agreements, futures contracts, fixed-for-float swaps, basis swaps and options contracts.  The following table summarizes our commodity derivative instruments outstanding at June 30, 2011:

 
Volume (1)
Accounting
Derivative Purpose
Current (2)
Long-Term (2)
Treatment
Derivatives designated as hedging instruments:
     
Enterprise:
     
Natural gas processing:
     
Forecasted natural gas purchases for plant thermal reduction (“PTR”) (3)
31.9 Bcf
n/a
Cash flow hedge
Forecasted sales of NGLs (4)
6.6 MMBbls
n/a
Cash flow hedge
Octane enhancement:
     
Forecasted purchases of NGLs
0.1 MMBbls
n/a
Cash flow hedge
Forecasted sales of octane enhancement products
2.0 MMBbls
n/a
Cash flow hedge
Natural gas marketing:
     
Natural gas storage inventory management activities
2.8 Bcf
n/a
Fair value hedge
NGL marketing:
     
Forecasted purchases of NGLs and related hydrocarbon products
2.3 MMBbls
n/a
Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products
2.3 MMBbls
n/a
Cash flow hedge
Refined products marketing:
     
Forecasted purchases of refined products
1.1 MMBbls
n/a
Cash flow hedge
Forecasted sales of refined products
1.2 MMBbls
n/a
Cash flow hedge
Crude oil marketing:
     
Forecasted purchases of crude oil
1.1 MMBbls
n/a
Cash flow hedge
Forecasted sales of crude oil
1.9 MMBbls
n/a
Cash flow hedge
Derivatives not designated as hedging instruments:
     
Enterprise:
     
Natural gas risk management activities (5,6)
385.8 Bcf
69.0 Bcf
Mark-to-market
Refined products risk management activities (6)
3.4 MMBbls
n/a
Mark-to-market
Crude oil risk management activities (6)
5.7 MMBbls
n/a
Mark-to-market
Duncan Energy Partners:
     
Natural gas risk management activities (6)
0.2 Bcf
n/a
Mark-to-market
(1)   Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes.
(2)   The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is June 2012, January 2012 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 1.6 MMBbls of additional hedges executed under contracts that have been designated as normal sales agreements.
(5)   Current and long-term volumes include approximately 75.5 Bcf and 2.8 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.






 
20

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 December 2011, 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 June 30, 2011, the aggregate fair value of our over-the-counter derivative instruments in a net liability position was $0.2 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. 








 
21

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
 
 
June 30, 2011
 
December 31, 2010
 
June 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
  $ 51.1  
Other current
assets
  $ 30.3  
Other current liabilities
  $ 42.4  
Other current 
 liabilities
  $ 5.5  
Interest rate derivatives
Other assets
    49.4  
Other assets
    77.8  
Other liabilities
    6.1  
Other liabilities
    26.2  
Total interest rate derivatives
      100.5         108.1         48.5         31.7  
Commodity derivatives
Other current
assets
    46.6  
Other current
assets
    46.3  
Other current
  liabilities
    108.8  
Other current liabilities
    93.0  
Commodity derivatives
Other assets
    --  
Other assets
    1.0  
Other liabilities
    --  
Other liabilities
    1.7  
Total commodity derivatives (1)
      46.6         47.3         108.8         94.7  
Total derivatives designated as
   hedging instruments
    $ 147.1       $ 155.4       $ 157.3       $ 126.4  
                                         
Derivatives not designated as hedging instruments
 
Interest rate derivatives
Other current
assets
  $ --  
Other current
assets
  $ --  
Other current 
 liabilities
  $ 15.7  
Other current liabilities
  $ 21.0  
Interest rate derivatives
Other assets
    --  
Other assets
    --  
Other liabilities
    6.0  
Other liabilities
    0.9  
Total interest rate derivatives
      --         --         21.7         21.9  
Commodity derivatives
Other current
assets
    36.4  
Other current 
 assets
    38.6  
Other current 
 liabilities
    40.6  
Other current liabilities
    41.2  
Commodity derivatives
Other assets
    4.5  
Other assets
    4.5  
Other liabilities
    2.1  
Other liabilities
    5.4  
Total commodity derivatives
      40.9         43.1         42.7         46.6  
Foreign currency derivatives
Other assets
    --  
Other assets
    0.3  
Other liabilities
    --  
Other liabilities
    0.1  
Total derivatives not designated as
   hedging instruments
    $ 40.9       $ 43.4       $ 64.4       $ 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/(Loss) Recognized in
Income on Derivative
 
     
For the Three Months
   
For the Six Months
 
     
Ended June 30,
   
Ended June 30,
 
     
2011
   
2010
   
2011
   
2010
 
Interest rate derivatives
Interest expense
  $ 21.1     $ 11.6     $ 8.8     $ 19.0  
Commodity derivatives
Revenue
    (1.6 )     4.7       (1.3 )     2.9  
   Total
    $ 19.5     $ 16.3     $ 7.5     $ 21.9  

Derivatives in Fair Value
Hedging Relationships
 
Location
 
Gain/(Loss) Recognized in
Income on Hedged Item
 
     
For the Three Months
   
For the Six Months
 
     
Ended June 30,
   
Ended June 30,
 
     
2011
   
2010
   
2011
   
2010
 
Interest rate derivatives
Interest expense
  $ (21.0 )   $ (10.8 )   $ (9.7 )   $ (18.2 )
Commodity derivatives
Revenue
    0.2       (4.3 )     (1.1 )     (2.4 )
   Total
    $ (20.8 )   $ (15.1 )   $ (10.8 )   $ (20.6 )


 
22

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 Six Months
 
   
Ended June 30,
   
Ended June 30,
 
   
2011
   
2010
   
2011
   
2010
 
Interest rate derivatives
  $ (60.1 )   $ (79.3 )   $ (46.0 )   $ (86.8 )
Commodity derivatives – Revenue (1)
    (19.4 )     93.5       (174.8 )     86.4  
Commodity derivatives – Operating costs
   and expenses
    (2.3 )     (1.5 )     1.7       (53.3 )
Foreign currency derivatives
    --       (0.1 )     --       (0.2 )
   Total
  $ (81.8 )   $ 12.6     $ (219.1 )   $ (53.9 )
                                 
(1)   The increase in other comprehensive loss during 2011 is primarily due to the impact of rising crude oil, refined products and NGL prices on our 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 Six Months
 
     
Ended June 30,
   
Ended June 30,
 
     
2011
   
2010
   
2011
   
2010
 
Interest rate derivatives
Interest expense
  $ (1.5 )   $ (7.2 )   $ (3.0 )   $ (13.3 )
Commodity derivatives
Revenue
    (79.3 )     18.3       (148.5 )     2.5  
Commodity derivatives
Operating costs and expenses
    4.5       (16.8 )     4.8       (17.5 )
Foreign currency derivatives
Other income
    --       --       --       0.3  
   Total
    $ (76.3 )   $ (5.7 )   $ (146.7 )   $ (28.0 )

Derivatives in Cash Flow
Hedging Relationships
Location
 
Gain Recognized in Income on
Derivative (Ineffective Portion)
 
     
For the Three Months
   
For the Six Months
 
     
Ended June 30,
   
Ended June 30,
 
     
2011
   
2010
   
2011
   
2010
 
Commodity derivatives
Revenue
  $ 0.3     $ --     $ 0.2     $ --  
Commodity derivatives
Operating costs and expenses
    --       3.5       --       2.9  
   Total
    $ 0.3     $ 3.5     $ 0.2     $ 2.9  

Over the next twelve months, we expect to reclassify $7.9 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 $61.2 million of losses attributable to commodity derivative instruments from accumulated other comprehensive loss to earnings, $29.4 million as an increase in operating costs and expenses and $31.8 million as a decrease in revenue.

The following table presents the effect of our derivative instruments not designated as hedging instruments on our Unaudited Condensed Statements of Consolidated Operations for the periods presented:

Derivatives Not Designated
as Hedging Instruments
Location
 
Gain/(Loss) Recognized in
Income on Derivative
 
     
For the Three Months
   
For the Six Months
 
     
Ended June 30,
   
Ended June 30,
 
     
2011
   
2010
   
2011
   
2010
 
Interest rate derivatives
Interest expense
  $ (11.9 )   $ --     $ (10.5 )   $ --  
Commodity derivatives
Revenue
    9.5       (8.9 )     13.3       (5.0 )
Commodity derivatives
Operating costs and expenses
    --       --       --       (1.5 )
   Total
    $ (2.4 )   $ (8.9 )   $ 2.8     $ (6.5 )


 
23

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

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 June 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
  $ --     $ 100.5     $ --     $ 100.5  
Commodity derivatives
    31.9       49.0       6.6       87.5  
Total
  $ 31.9     $ 149.5     $ 6.6     $ 188.0  
                                 
Financial liabilities:
                               
Interest rate derivatives
  $ --     $ 70.2     $ --     $ 70.2  
Commodity derivatives
    66.2       80.8       4.5       151.5  
Total
  $ 66.2     $ 151.0     $ 4.5     $ 221.7  

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

 
24

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

  
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 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.


















 
25

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 Six Months
Ended June 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  
                 
(1)   There were $2.0 million and $1.8 million of unrealized gains included in these amounts for the three and six months ended June 30, 2011, respectively. There were $2.8 million and $2.3 million of unrealized losses included in these amounts for the three and six months ended June 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

During the six months ended June 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 (i.e., non-cash asset impairment charges) totaling $1.5 million.  The non-cash asset impairment charges we recorded during the six months ended June 30, 2010 are a component of operating costs and expenses.


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:

   
June 30,
2011
   
December 31,
2010
 
NGLs
  $ 500.8     $ 548.3  
Petrochemicals and refined products
    344.3       399.7  
Crude oil
    92.2       121.1  
Natural gas
    56.3       64.7  
Other
    0.5       0.2  
    $ 994.1     $ 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,

 
26

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

our inventory levels have decreased since December 31, 2010 due to seasonal supply and demand fluctuations.

Due to fluctuating commodity prices, we recognize lower of cost or market (“LCM”) 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 LCM adjustments for the periods presented:

   
For the Three Months
Ended June 30,
   
For the Six Months
Ended June 30,
 
   
2011
   
2010
   
2011
   
2010
 
Cost of sales (1)
  $ 9,790.3     $ 6,343.2     $ 18,609.6     $ 13,685.5  
Lower of cost or market adjustments
    0.5       1.2       1.7       6.9  
(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.
 


Note 6.  Property, Plant and Equipment

Our property, plant and equipment values and related accumulated depreciation balances were as follows at the dates indicated:

   
Estimated
Useful Life
in Years
   
June 30,
2011
   
December 31,
2010
 
Plants, pipelines and facilities (1)
  3-45 (6)      $ 19,814.8     $ 19,388.4  
Underground and other storage facilities (2)
  5-40 (7)       1,538.9       1,477.8  
Platforms and facilities (3)
  20-31       637.5       637.5  
Transportation equipment (4)
  3-10       125.4       119.1  
Marine vessels (5)
  15-30       574.6       560.0  
Land
            130.1       123.4  
Construction in progress
            2,923.1       1,607.2  
Total
            25,744.4       23,913.4  
Less accumulated depreciation
            4,945.5       4,580.5  
Property, plant and equipment, net
          $ 20,798.9     $ 19,332.9  
                         
(1)   Plants and pipelines include processing plants; NGL, natural gas, crude oil and petrochemical and refined products pipelines; terminal loading and unloading facilities; office furniture and equipment; buildings; laboratory and shop equipment and related assets.
(2)