epdform10q_063009.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, 2009

OR

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

For the transition period from ___  to  ___.

Commission file number:  1-14323

ENTERPRISE PRODUCTS PARTNERS L.P.
(Exact name of Registrant as Specified in Its Charter)

Delaware
76-0568219
(State or Other Jurisdiction of
(I.R.S. Employer Identification No.)
Incorporation or Organization)
 
     
 
1100 Louisiana, 10th Floor
 
 
Houston, Texas  77002
 
 
    (Address of Principal Executive Offices, Including Zip Code)
 
     
 
(713) 381-6500
 
 
(Registrant’s Telephone Number, Including Area Code)
 
     
 


Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ   No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes þ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.         
Large accelerated filer þ
 Accelerated filer o
Non-accelerated filer   o (Do not check if a smaller reporting company)  
                Smaller reporting company o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o   No þ

There were 460,221,747 common units, including 2,907,950 restricted common units, of Enterprise Products Partners L.P. outstanding at August 1, 2009.  These common units trade on the New York Stock Exchange under the ticker symbol “EPD.”
 
 
ENTERPRISE PRODUCTS PARTNERS L.P.
TABLE OF CONTENTS

   
Page No.
 
 
 
 
 
 
   
 
 
 
 
 
       5.  Inventories
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
     
     
 

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
 
2009
   
2008
 
Current assets:
           
Cash and cash equivalents
  $ 65.0     $ 35.4  
Restricted cash
    184.4       203.8  
Accounts and notes receivable – trade, net of allowance for doubtful accounts of $14.7 at June 30, 2009 and $15.1 at December 31, 2008
    1,232.2       1,185.5  
Accounts receivable – related parties
    47.4       61.6  
Inventories (see Note 5)
    965.8       362.8  
Derivative assets (see Note 4)
    229.3       202.8  
Prepaid and other current assets
    144.8       111.8  
Total current assets
    2,868.9       2,163.7  
Property, plant and equipment, net
    13,582.0       13,154.8  
Investments in unconsolidated affiliates
    901.4       949.5  
Intangible assets, net of accumulated amortization of $472.0 at June 30, 2009 and $429.9 at December 31, 2008
    813.5       855.4  
Goodwill
    706.9       706.9  
Deferred tax asset
    1.1       0.4  
Other assets
    148.7       126.8  
Total assets
  $ 19,022.5     $ 17,957.5  
                 
LIABILITIES AND EQUITY
               
Current liabilities:
               
Current maturities of long-term debt
  $ 181.4     $ --  
Accounts payable – trade
    278.2       300.5  
Accounts payable – related parties
    96.0       39.6  
Accrued product payables
    1,526.2       1,142.4  
Accrued interest payable
    169.4       151.9  
Other accrued expenses
    32.3       48.8  
Derivative liabilities (see Note 4)
    337.0       287.2  
Other current liabilities
    191.1       252.7  
Total current liabilities
    2,811.6       2,223.1  
Long-term debt: (see Note 9)
               
Senior debt obligations – principal
    7,950.1       7,813.4  
Junior subordinated notes – principal
    1,232.7       1,232.7  
Other
    41.5       62.3  
Total long-term debt
    9,224.3       9,108.4  
Deferred tax liabilities
    68.8       66.1  
Other long-term liabilities
    98.9       81.3  
Commitments and contingencies
               
Equity: (see Note 10)
               
Enterprise Products Partners L.P. partners’ equity:
               
Limited Partners:
               
Common units (457,313,797 units outstanding at June 30, 2009 and 439,354,731 units outstanding at December 31, 2008)
    6,278.7       6,036.9  
Restricted common units (2,935,450 units outstanding at June 30, 2009 and 2,080,600 units outstanding at December 31, 2008)
    32.1       26.2  
General partner
    128.6       123.6  
Accumulated other comprehensive loss
    (130.9 )     (97.2 )
Total Enterprise Products Partners L.P. partners’ equity
    6,308.5       6,089.5  
Noncontrolling interest
    510.4       389.1  
Total equity
    6,818.9       6,478.6  
Total liabilities and equity
  $ 19,022.5     $ 17,957.5  
 
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,
 
   
2009
   
2008
   
2009
   
2008
 
Revenues:
                       
Third parties
  $ 3,382.8     $ 6,116.9     $ 6,561.4     $ 11,500.7  
Related parties
    125.1       222.8       369.6       523.5  
Total revenues (see Note 11)
    3,507.9       6,339.7       6,931.0       12,024.2  
Costs and expenses:
                               
Operating costs and expenses:
                               
Third parties
    2,925.3       5,824.7       5,756.9       10,959.3  
Related parties
    208.9       135.3       418.6       311.9  
Total operating costs and expenses
    3,134.2       5,960.0       6,175.5       11,271.2  
General and administrative costs:
                               
Third parties
    11.2       10.5       16.4       14.0  
Related parties
    16.6       13.5       34.4       31.2  
Total general and administrative costs
    27.8       24.0       50.8       45.2  
Total costs and expenses
    3,162.0       5,984.0       6,226.3       11,316.4  
Equity in income (loss) of unconsolidated affiliates
    (17.6 )     18.6       (4.2 )     33.2  
Operating income
    328.3       374.3       700.5       741.0  
Other income (expense):
                               
Interest expense
    (126.2 )     (95.8 )     (246.6 )     (187.7 )
Interest income
    0.6       1.0       1.2       2.6  
Other, net
    (0.4 )     (0.3 )     (0.3 )     (1.0 )
Total other expense, net
    (126.0 )     (95.1 )     (245.7 )     (186.1 )
Income before provision for income taxes
    202.3       279.2       454.8       554.9  
Provision for income taxes
    (2.2 )     (6.9 )     (17.4 )     (10.6 )
Net income
    200.1       272.3       437.4       544.3  
Net income attributable to noncontrolling interest
    (13.5 )     (9.0 )     (25.5 )     (21.4 )
Net income attributable to Enterprise Products Partners L.P.
  $ 186.6     $ 263.3     $ 411.9     $ 522.9  
                                 
Net income allocated to:
                               
Limited partners
  $ 147.0     $ 227.7     $ 333.3     $ 452.9  
General partner
  $ 39.6     $ 35.6     $ 78.6     $ 70.0  
                                 
Basic and diluted earnings per unit (see Note 13)
  $ 0.32     $ 0.52     $ 0.73     $ 1.03  
 
See Notes to Unaudited Condensed Consolidated Financial Statements.
 
 
ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED
COMPREHENSIVE INCOME
(Dollars in millions)

   
For the Three Months
   
For the Six Months
 
   
Ended June 30,
   
Ended June 30,
 
   
2009
   
2008
   
2009
   
2008
 
                         
Net income
  $ 200.1     $ 272.3     $ 437.4     $ 544.3  
Other comprehensive income (loss):
                               
Cash flow hedges:
                               
Commodity derivative instrument gains (losses) during period
    (76.6 )     31.1       (138.6 )     119.9  
Reclassification adjustment for (gains) losses included in net income related to commodity derivative instruments
    66.3       (16.9 )     98.5       (12.7 )
Interest rate derivative instrument gains (losses) during period
    15.8       4.2       15.1       (21.8 )
Reclassification adjustment for (gains) losses included in net income related to interest rate derivative instruments
    1.1       (0.8 )     2.0       (2.4 )
Foreign currency derivative gains (losses)
    0.1       (0.1 )     (10.5 )     (1.3 )
Total cash flow hedges
    6.7       17.5       (33.5 )     81.7  
Foreign currency translation adjustment
    1.0       0.5       0.6       0.1  
Change in funded status of pension and postretirement plans, net of tax
    --       --       --       (0.3 )
Total other comprehensive income (loss)
    7.7       18.0       (32.9 )     81.5  
Comprehensive income
    207.8       290.3       404.5       625.8  
Comprehensive income attributable to noncontrolling interest
    (13.7 )     (12.5 )     (26.3 )     (21.1 )
Comprehensive income attributable to Enterprise Products Partners L.P.
  $ 194.1     $ 277.8     $ 378.2     $ 604.7  
 
See Notes to Unaudited Condensed Consolidated Financial Statements.
 
 
ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in millions)

   
For the Six Months
 
   
Ended June 30,
 
   
2009
   
2008
 
Operating activities:
           
Net income
  $ 437.4     $ 544.3  
Adjustments to reconcile net income to net cash flows provided by operating activities:
               
Depreciation, amortization and accretion
    312.9       274.3  
Equity in (income) loss of unconsolidated affiliates
    4.2       (33.2 )
Distributions received from unconsolidated affiliates
    38.5       56.0  
Operating lease expense paid by EPCO, Inc.
    0.3       1.0  
Gain from asset sales and related transactions
    (0.4 )     (0.8 )
Deferred income tax expense
    1.8       2.5  
Changes in fair market value of derivative instruments
    (11.7 )     9.6  
Effect of pension settlement recognition
    (0.1 )     (0.1 )
Net effect of changes in operating accounts (see Note 16)
    (345.2 )     (156.9 )
Net cash flows provided by operating activities
    437.7       696.7  
Investing activities:
               
Capital expenditures
    (640.0 )     (1,091.2 )
Contributions in aid of construction costs
    10.3       17.8  
Decrease in restricted cash
    19.4       71.0  
Cash used for business combinations
    (23.7 )     --  
Acquisition of intangible assets
    --       (5.1 )
Investments in unconsolidated affiliates
    (12.5 )     (25.0 )
Other proceeds from investing activities
    4.3       0.5  
Cash used in investing activities
    (642.2 )     (1,032.0 )
Financing activities:
               
Borrowings under debt agreements
    2,785.1       3,914.7  
Repayments of debt
    (2,471.2 )     (3,063.0 )
Debt issuance costs
    (5.4 )     (8.6 )
Distributions paid to partners
    (566.4 )     (509.0 )
Distributions paid to noncontrolling interest (see Note 10)
    (27.8 )     (29.1 )
Net proceeds from issuance of common units
    398.8       38.0  
Contributions from noncontrolling interest (see Note 10)
    123.2       --  
Acquisition of treasury units
    --       (0.7 )
Monetization of interest rate derivative instruments
    --       (22.1 )
Cash provided by financing activities
    236.3       320.2  
Effect of exchange rate changes on cash
    (2.2 )     0.1  
Net change in cash and cash equivalents
    31.8       (15.1 )
Cash and cash equivalents, January 1
    35.4       39.7  
Cash and cash equivalents, June 30
  $ 65.0     $ 24.7  
 
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 and Detail of Changes in Limited Partners’ Equity)
(Dollars in millions)

   
Enterprise Products Partners L.P.
             
               
Accumulated
             
               
Other
             
   
Limited
   
General
   
Comprehensive
   
Noncontrolling
       
   
Partners
   
Partner
   
Loss
   
Interest
   
Total
 
Balance, December 31, 2008
  $ 6,063.1     $ 123.6     $ (97.2 )   $ 389.1     $ 6,478.6  
Net income
    333.3       78.6       --       25.5       437.4  
Operating leases paid by EPCO, Inc.
    0.3       --       --       --       0.3  
Cash distributions to partners
    (484.4 )     (81.7 )     --       --       (566.1 )
Unit option reimbursements to EPCO, Inc.
    (0.3 )     --       --       --       (0.3 )
Distributions paid to noncontrolling interest (see Note 10)
    --       --       --       (27.8 )     (27.8 )
Net proceeds from issuance of common units
    390.6       8.0       --       --       398.6  
Proceeds from exercise of unit options
    0.2       --       --       --       0.2  
Contributions from noncontrolling interest (see Note 10)
    --       --       --       122.8       122.8  
Amortization of equity awards
    8.0       0.1       --       --       8.1  
Foreign currency translation adjustment
    --       --       0.6       --       0.6  
Cash flow hedges
    --       --       (34.3 )     0.8       (33.5 )
Balance, June 30, 2009
  $ 6,310.8     $ 128.6     $ (130.9 )   $ 510.4     $ 6,818.9  



   
Enterprise Products Partners L.P.
             
               
Accumulated
             
               
Other
             
   
Limited
   
General
   
Comprehensive
   
Noncontrolling
       
   
Partners
   
Partner
   
Income
   
Interest
   
Total
 
Balance, December 31, 2007
  $ 5,992.9     $ 122.3     $ 19.1     $ 427.8     $ 6,562.1  
Net income
    452.9       70.0       --       21.4       544.3  
Operating leases paid by EPCO, Inc.
    1.0       --       --       --       1.0  
Cash distributions to partners
    (438.8 )     (69.7 )     --       --       (508.5 )
Unit option reimbursements to EPCO, Inc.
    (0.5 )     --       --       --       (0.5 )
Distributions paid to noncontrolling interest (see Note 10)
    --       --       --       (29.1 )     (29.1 )
Net proceeds from issuance of common units
    36.7       0.7       --       --       37.4  
Proceeds from exercise of unit options
    0.6       --       --       --       0.6  
Amortization of equity awards
    5.3       0.1       --       --       5.4  
Acquisition of treasury units
    (0.7 )     --       --       --       (0.7 )
Foreign currency translation adjustment
    --       --       0.1       --       0.1  
Change in funded status of pension and postretirement plans
    --       --       (0.3 )     --       (0.3 )
Cash flow hedges
    --       --       81.9       (0.2 )     81.7  
Balance, June 30, 2008
  $ 6,049.4     $ 123.4     $ 100.8     $ 419.9     $ 6,693.5  
 
See Notes to Unaudited Condensed Consolidated Financial Statements.
 
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.

 
Note 1.  Partnership Organization

Partnership Organization

Enterprise Products Partners L.P. is a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.”  Unless the context requires otherwise, references to “we,” “us,” “our” or “Enterprise Products Partners” are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries.

We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO, Inc. (“EPCO”).  We conduct substantially all of our business through our wholly owned subsidiary, Enterprise Products Operating LLC (“EPO”).  We are owned 98% by our limited partners and 2% by Enterprise Products GP, LLC (our general partner, referred to as “EPGP”).  EPGP is owned 100% by Enterprise GP Holdings L.P. (“Enterprise GP Holdings”), a publicly traded limited partnership, the units of which are listed on the NYSE under the ticker symbol “EPE.”  The general partner of Enterprise GP Holdings is EPE Holdings, LLC (“EPE Holdings”), a wholly owned subsidiary of Dan Duncan LLC, all of the membership interests of which are owned by Dan L. Duncan.  We, EPGP, Enterprise GP Holdings, EPE Holdings and Dan Duncan LLC are affiliates and under the common control of Dan L. Duncan, the Group Co-Chairman and controlling shareholder of EPCO.

References to “TEPPCO” mean TEPPCO Partners, L.P., a publicly traded limited partnership, the common units of which are listed on the NYSE under the ticker symbol “TPP.”  References to “TEPPCO GP” refer to Texas Eastern Products Pipeline Company, LLC, which is the general partner of TEPPCO and is wholly owned by Enterprise GP Holdings.  On June 28, 2009, we and TEPPCO (including TEPPCO GP) entered into definitive agreements to merge.  See Note 12 for additional information regarding the merger agreements.
    
References to “Energy Transfer Equity” mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries.  References to “LE GP” mean LE GP, LLC, which is the general partner of Energy Transfer Equity.  Enterprise GP Holdings owns a noncontrolling interest in both LE GP and Energy Transfer Equity.  Enterprise GP Holdings accounts for its investments in LE GP and Energy Transfer Equity using the equity method of accounting.

References to “Employee Partnerships” mean EPE Unit L.P., EPE Unit II, L.P., EPE Unit III, L.P., Enterprise Unit L.P. and EPCO Unit L.P., collectively, all of which are privately-held affiliates of EPCO.

For financial reporting purposes, we consolidate the financial statements of Duncan Energy Partners L.P. (“Duncan Energy Partners”) with those of our own and reflect its operations in our business segments.  We control Duncan Energy Partners through our ownership of its general partner, DEP Holdings, LLC (“DEP GP”).  Also, due to common control of the entities by Dan L. Duncan, the initial consolidated balance sheet of Duncan Energy Partners reflects our historical carrying basis in each of the subsidiaries contributed to Duncan Energy Partners.  Public ownership of Duncan Energy Partners’ net assets and earnings are presented as a component of noncontrolling interest in our consolidated financial statements.  The borrowings of Duncan Energy Partners are presented as part of our consolidated debt; however, neither Enterprise Products Partners L.P. nor EPO have any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners.
 
 
7

 
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
Basis of Presentation

Effective January 1, 2009, we adopted the provisions of Statement of Financial Accounting Standards (“SFAS”) 160 (Accounting Standards Codification (“ASC”) 810), Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51.  SFAS 160 established accounting and reporting standards for noncontrolling interests, which were previously identified as minority interest in our financial statements.  This new standard requires, among other things, that (i) noncontrolling interests be presented as a component of equity on our consolidated balance sheet (i.e., elimination of the “mezzanine” presentation previously used for minority interest); (ii) elimination of minority interest amounts as a deduction in deriving net income or loss and, as a result, that net income or loss be allocated between controlling and noncontrolling interests; and (iii) comprehensive income or loss be allocated between controlling and noncontrolling interest.  Earnings per unit amounts are not affected by these changes.  See Note 10 for additional information regarding noncontrolling interest.

The consolidated financial statements included in this Quarterly Report have been retrospectively adjusted to reflect the changes required by SFAS 160.  As a result, net income reported for the three and six months ended June 30, 2008 in these financial statements is higher than that disclosed previously; however, the allocation of such net income results in our unitholders, general partner and noncontrolling interests (i.e., the former minority interest) receiving the same amounts as they did previously.

Our results of operations for the three and six months ended June 30, 2009 are not necessarily indicative of results expected for the full year.

Essentially all of our assets, liabilities, revenues and expenses are recorded at EPO’s level in our consolidated financial statements.  Enterprise Products Partners L.P. acts as guarantor of certain of EPO’s debt obligations.  See Note 17 for condensed consolidated financial information of EPO.

In our opinion, the accompanying Unaudited Condensed Consolidated Financial Statements include all adjustments consisting of normal recurring accruals necessary for fair presentation.  Although we believe the disclosures in these financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”).  These Unaudited Condensed Consolidated Financial Statements and Notes thereto should be read in conjunction with the Audited Consolidated Financial Statements and Notes thereto included in our Current Report on Form 8-K dated July 8, 2009 (the “Recast Form 8-K”), which retrospectively adjusted portions of our Annual Report on Form 10-K for the year ended December 31, 2008 to reflect our adoption of SFAS 160 and Emerging Issues Task Force (“EITF”) 07-4 (ASC 260), Application of the Two Class Method Under FASB Statement No. 128 to Master Limited Partnerships, and the resulting change in presentation and disclosure requirements.


Note 2.  General Accounting Matters

Estimates

Preparing our financial statements in conformity with GAAP requires management to make estimates and assumptions that affect amounts presented in the financial statements (e.g. assets, liabilities, revenues and expenses) and disclosures about contingent assets and liabilities.  Our actual results could differ from these estimates.  On an ongoing basis, management reviews its estimates based on currently available information.  Changes in facts and circumstances may result in revised estimates.

Fair Value Information

Cash and cash equivalents, accounts receivable, accounts payable and accrued expenses, and other current liabilities are carried at amounts which reasonably approximate their fair values due to their short-
 
 
8

 
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
 
term nature.  The estimated fair values of our fixed rate debt are based on quoted market prices for such debt or debt of similar terms and maturities.  The carrying amounts of our variable rate debt obligations reasonably approximate their fair values due to their variable interest rates.  See Note 4 for fair value information associated with our derivative instruments.  The following table presents the estimated fair values of our financial instruments at the dates indicated:

   
June 30, 2009
   
December 31, 2008
 
   
Carrying
   
Fair
   
Carrying
   
Fair
 
Financial Instruments
 
Value
   
Value
   
Value
   
Value
 
Financial assets:
                       
Cash and cash equivalents, including restricted cash
  $ 249.4     $ 249.4     $ 239.2     $ 239.2  
Accounts receivable
    1,279.6       1,279.6       1,247.1       1,247.1  
Financial liabilities:
                               
Accounts payable and accrued expenses
    2,102.1       2,102.1       1,683.2       1,683.2  
Other current liabilities
    191.1       191.1       252.7       252.7  
Fixed-rate debt (principal amount)
    7,986.7       7,760.9       7,704.3       6,639.0  
Variable-rate debt
    1,377.5       1,377.5       1,341.8       1,341.8  

Recent Accounting Developments

The following information summarizes recently issued accounting guidance since those reported in our Recast Form 8-K that will or may affect our future financial statements.

In April 2009, the Financial Accounting Standards Board (“FASB”) issued new guidance in the form of FASB Staff Positions (“FSPs”) in an effort to clarify certain fair value accounting rules.   FSP FAS 157-4 (ASC 820), Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, establishes a process to determine whether a market is not active and a transaction is not distressed.   FSP FAS 157-4 states that companies should look at several factors and use judgment to ascertain if a formerly active market has become inactive.   When estimating fair value, FSP FAS 157-4 requires companies to place more weight on observable transactions determined to be orderly and less weight on transactions for which there is insufficient information to determine whether the transaction is orderly (entities do not have to incur undue cost and effort in making this determination).   The FASB also issued FSP FAS 107-1 and APB 28-1 (ASC 825), Interim Disclosures About Fair Value of Financial Instruments.  This FSP requires that companies provide qualitative and quantitative information about fair value estimates for all financial instruments not measured on the balance sheet at fair value in each interim report.  Previously, this was only an annual requirement.  We adopted these FSPs on June 30, 2009.  Our adoption of this new guidance did not have a material impact on our financial statements or related disclosures.

In May 2009, the FASB issued SFAS 165 (ASC 855), Subsequent Events, which establishes general standards of accounting for, and disclosure of, events that occur after the balance sheet date but before financial statements are issued or are available to be issued.  SFAS 165 requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date.  We adopted SFAS 165 on June 30, 2009.  Our adoption of this guidance did not have any impact on our financial position, results of operations or cash flows.

In June 2009, the FASB issued SFAS 167 (ASC 810), Amendments to FASB Interpretation No. 46(R), which amended consolidation guidance for variable interest entities (“VIEs”) under FASB Interpretation (“FIN”) No. 46(R) (ASC 810-10), Consolidation of Variable Interest Entities.  VIEs are entities whose equity investors do not have sufficient equity capital at risk such that the entity cannot finance its own activities. When a business has a controlling financial interest in a VIE, the assets, liabilities and profit or loss of that entity must be included in consolidation.  A business enterprise must consolidate a VIE when that enterprise has a variable interest that will cover most of the entity’s expected losses and/or receive most of the entity’s anticipated residual return.  SFAS 167, among other things, eliminates the scope exception for qualifying special-purpose entities, amends certain guidance for determining whether an entity is a VIE, expands the list of events that trigger reconsideration of whether an entity is a VIE, requires a qualitative rather than a quantitative analysis to determine the primary beneficiary of a VIE, requires continuous assessments of whether a company is the primary
 
 
9

 
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
beneficiary of a VIE and requires enhanced disclosures about a company’s involvement with a VIE.  SFAS 167 is effective for us on January 1, 2010.  At June 30, 2009, we did not have any VIEs; therefore, our adoption of this new guidance is not expected to have a material impact on our consolidated financial statements.

In June 2009, the FASB also issued SFAS 168 (ASC 105), The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles a replacement of FASB Statement No. 162, which establishes the ASC as the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. The ASC is a reorganization of current GAAP into a topical format that eliminates the current GAAP hierarchy and establishes two levels of guidance  authoritative and nonauthoritative.  All guidance contained in the ASC carries an equal level of authority.  Rules and interpretive releases of the SEC under federal securities laws are also sources of authoritative GAAP for SEC registrants.  SFAS 168 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP.  We will adopt SFAS 168 on September 30, 2009.  Our adoption of this guidance is not expected to have any impact on our financial position, results of operations or cash flows.  References to specific GAAP in our consolidated financial statements after our adoption of SFAS 168 will refer exclusively to the ASC.  We have elected to provide references to the ASC parenthetically in this Quarterly Report.

Restricted Cash

Restricted cash represents amounts held in connection with our commodity derivative instruments portfolio and New York Mercantile Exchange (“NYMEX”) physical natural gas purchases.  Additional cash may be restricted to maintain our positions as commodity prices fluctuate or deposit requirements change.  At June 30, 2009 and December 31, 2008, our restricted cash amounts were $184.4 million and $203.8 million, respectively.  See Note 4 for additional information regarding derivative instruments and hedging activities.

Subsequent Events

We have evaluated subsequent events through August 6, 2009, which is the date our Unaudited Condensed Consolidated Financial Statements and Notes are being issued.


Note 3.  Accounting for Equity Awards

We account for equity awards in accordance with SFAS 123(R) (ASC 505 and 718), Share-Based Payment.  Such awards were not material to our consolidated financial position, results of operations or cash flows for all periods presented.  The amount of equity-based compensation allocable to our businesses was $5.3 million and $3.5 million for the three months ended June 30, 2009 and 2008, respectively.  For the six months ended June 30, 2009 and 2008, the amount of equity-based compensation allocable to our businesses was $8.2 million and $6.3 million, respectively.

Certain key employees of EPCO participate in long-term incentive compensation plans managed by EPCO.  The compensation expense we record related to equity awards is based on an allocation of the total cost of such incentive plans to EPCO.  We record our pro rata share of such costs based on the percentage of time each employee spends on our consolidated business activities.

EPCO 1998 Long-Term Incentive Plan

The EPCO 1998 Long-Term Incentive Plan (“EPCO 1998 Plan”) provides for the issuance of up to 7,000,000 of our common units.  After giving effect to the issuance or forfeiture of option awards and restricted unit awards through June 30, 2009, a total of 301,600 additional common units could be issued under the EPCO 1998 Plan.
 
 
10

 
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
Unit option awards.  The following table presents option activity under the EPCO 1998 Plan for the periods indicated:

               
Weighted-
       
         
Weighted-
   
Average
       
         
Average
   
Remaining
   
Aggregate
 
   
Number of
   
Strike Price
   
Contractual
   
Intrinsic
 
   
Units
   
(dollars/unit)
   
Term (in years)
   
Value (1)
 
Outstanding at December 31, 2008
    2,168,500     $ 26.32              
Granted (2)
    30,000       20.08              
Exercised
    (25,000 )     13.16              
Forfeited
    (365,000 )     26.38              
Outstanding at June 30, 2009
    1,808,500       26.39       4.8     $ 1.5  
Options exercisable at
                               
June 30, 2009
    403,500       21.33       3.9     $ 1.5  
                                 
(1)  Aggregate intrinsic value reflects fully vested unit options at June 30, 2009.
(2)  Aggregate grant date fair value of these unit options issued during 2009 was $0.2 million based on the following assumptions: (i) a grant date market price of our common units of $20.08 per unit; (ii) expected life of options of 5.0 years; (iii) risk-free interest rate of 1.81%; (iv) expected distribution yield on our common units of 10%; and (v) expected unit price volatility on our common units of 72.76%.
 

The total intrinsic value of option awards exercised during the three months ended June 30, 2009 and 2008 was $0.2 million and $0.4 million, respectively.  For the six months ended June 30, 2009 and 2008, the total intrinsic value of option awards exercised was $0.3 million and $0.5 million, respectively.  At June 30, 2009, the estimated total unrecognized compensation cost related to nonvested unit option awards granted under the EPCO 1998 Plan was $1.3 million.  We will recognize our share of these costs in accordance with the EPCO administrative services agreement (the “ASA”) (see Note 12) over a weighted-average period of 2.0 years.

During the six months ended June 30, 2009 and 2008, we received cash of $0.2 million and $0.6 million, respectively, from the exercise of option awards granted under the EPCO 1998 Plan.  Conversely, our option-related reimbursements to EPCO during each of these periods were $0.3 million and $0.5 million, respectively.

Restricted unit awards.  The following table summarizes information regarding our restricted unit awards under the EPCO 1998 Plan for the periods indicated:

         
Weighted-
 
         
Average Grant
 
   
Number of
   
Date Fair Value
 
   
Units
   
per Unit (1)
 
Restricted units at December 31, 2008
    2,080,600        
Granted (2)
    1,011,350     $ 20.63  
Vested
    (12,500 )     27.59  
Forfeited
    (144,000 )     29.41  
Restricted units at June 30, 2009
    2,935,450          
                 
(1)  Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. The weighted-average grant date fair value per unit for forfeited and vested awards is determined before an allowance for forfeitures.
(2)  Aggregate grant date fair value of restricted unit awards issued during 2009 was $20.9 million based on grant date market prices of our common units ranging from $20.08 to $24.92 per unit and an estimated forfeiture rate ranging between 4.6% and 17%.
 

The total fair value of restricted unit awards that vested during the six months ended June 30, 2009 was $0.3 million.  Such amount was immaterial for the three months ended June 30, 2009.  At June 30, 2009, the estimated total unrecognized compensation cost related to nonvested restricted unit awards granted under the EPCO 1998 Plan was $44.2 million.  We expect to recognize our share of this cost over a weighted-average period of 2.5 years in accordance with the ASA.
 
 
11

 
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
 
Phantom unit awards and distribution equivalent rights.  No phantom unit awards or distribution equivalent rights have been issued as of June 30, 2009 under the EPCO 1998 Plan.

Enterprise Products 2008 Long-Term Incentive Plan

The Enterprise Products 2008 Long-Term Incentive Plan (“EPD 2008 LTIP”) provides for the issuance of up to 10,000,000 of our common units.  After giving effect to the issuance or forfeiture of option awards through June 30, 2009, a total of 7,865,000 additional common units could be issued under the EPD 2008 LTIP.

Unit option awards.  The following table presents unit option activity under the EPD 2008 LTIP for the periods indicated:

 
               
Weighted-
 
         
Weighted-
   
Average
 
         
Average
   
Remaining
 
   
Number of
   
Strike Price
   
Contractual
 
   
Units
   
(dollars/unit)
   
Term (in years)
 
Outstanding at December 31, 2008
    795,000     $ 30.93        
Granted (1)
    1,430,000       23.53        
Forfeited
    (90,000 )     30.93        
Outstanding at June 30, 2009 (2)
    2,135,000       25.97       5.2  
                         
(1)  Aggregate grant date fair value of these unit options issued during 2009 was $6.5 million based on the following assumptions: (i) a weighted-average grant date market price of our common units of $23.53 per unit; (ii) weighted-average expected life of options of 4.9 years; (iii) weighted-average risk-free interest rate of 2.14%; (iv) expected weighted-average distribution yield on our common units of 9.37%; (v) expected weighted-average unit price volatility on our common units of 57.11%; and (vi) an estimated forfeiture rate of 17%.
(2)  No unit options were exercisable as of June 30, 2009.
 

At June 30, 2009, the estimated total unrecognized compensation cost related to nonvested unit option awards granted under the EPD 2008 LTIP was $7.1 million.  We expect to recognize our share of this cost over a weighted-average period of 3.6 years in accordance with the ASA.

Phantom unit awards.  There were a total of 10,600 phantom units outstanding at June 30, 2009 under the EPD 2008 LTIP.  These awards cliff vest in 2011 and 2012.  At June 30, 2009 and December 31, 2008, we had accrued an immaterial liability for compensation related to these phantom unit awards.

Employee Partnerships

As of June 30, 2009, the estimated total unrecognized compensation cost related to the five Employee Partnerships was $39.9 million.  We will recognize our share of these costs in accordance with the ASA over a weighted-average period of 4.5 years.

DEP GP Unit Appreciation Rights

At June 30, 2009 and December 31, 2008, we had a total of 90,000 outstanding unit appreciation rights (“UARs”) granted to non-employee directors of DEP GP that cliff vest in 2012.  If a director resigns prior to vesting, his UAR awards are forfeited.  At June 30, 2009 and December 31, 2008, we had accrued an immaterial liability for compensation related to these UARs.
 
 
12

 
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
 
Note 4.  Derivative Instruments and Hedging Activities

In the course of our normal business operations, we are exposed to certain risks, including changes in interest rates, commodity prices and, to a limited extent, foreign exchange rates.  In order to manage risks associated with certain identifiable and anticipated transactions, we use derivative instruments.  Derivatives are financial instruments whose fair value is determined by changes in a specified benchmark such as interest rates, commodity prices or currency values.  Typical derivative instruments include futures, forward contracts, swaps and other instruments with similar characteristics.  Substantially all of our derivatives are used for non-trading activities.

SFAS 133 (ASC 815), Accounting for Derivative Instruments and Hedging Activities, requires companies to recognize derivative instruments at fair value as either assets or liabilities on the balance sheet.  While the standard requires that all derivatives be reported at fair value on the balance sheet, changes in fair value of the derivative instruments will be reported in different ways depending on the nature and effectiveness of the hedging activities to which they are related.  After meeting specified conditions, a qualified derivative may be specifically designated as a total or partial hedge of:

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

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

§  
Foreign currency exposure, such as through an unrecognized firm commitment.

An effective hedge is one in which the change in fair value of a derivative instrument can be expected to offset 80% to 125% of changes in the fair value of a hedged item at inception and throughout the life of the hedging relationship.  The effective portion of a hedge is the amount by which the derivative instrument exactly offsets the change in fair value of the hedged item during the reporting period.  Conversely, ineffectiveness represents the change in the fair value of the derivative instrument that does not exactly offset the change in the fair value of the hedged item.  Any ineffectiveness associated with a hedge is recognized in earnings immediately.  Ineffectiveness can be caused by, among other things, changes in the timing of forecasted transactions or a mismatch of terms between the derivative instrument and the hedged item.

On January 1, 2009, we adopted the disclosure requirements of SFAS 161 (ASC 815), Disclosures About Derivative Financial Instruments and Hedging Activities.  SFAS 161 requires enhanced qualitative and quantitative disclosure requirements regarding derivative instruments.  This footnote reflects the new disclosure standard.

Interest Rate Derivative Instruments

We utilize interest rate swaps, treasury locks and similar derivative instruments to manage our exposure to changes in the interest rates of certain consolidated debt agreements.  This strategy is a component in controlling our cost of capital associated with such borrowings.
 
 
13

 
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
 
The following table summarizes our interest rate derivative instruments outstanding at June 30, 2009, all of which were designated as hedging instruments under SFAS 133:

 
Number and Type of
Notional
Period of
Rate
Accounting
Hedged Transaction
Derivative Employed
Amount
Hedge
Swap
Treatment
Enterprise Products Partners:
         
   Senior Notes C
1 fixed-to-floating swap
$100.0
1/04 to 2/13
6.4% to 3.5%
Fair value hedge
   Senior Notes G
3 fixed-to-floating swaps
$300.0
10/04 to 10/14
5.6% to 2.6%
Fair value hedge
   Senior Notes P
6 fixed-to-floating swaps
$350.0
6/09 to 8/12
4.6% to 2.8%
Fair value hedge
Duncan Energy Partners:
         
   Variable-interest rate borrowings
3 floating-to-fixed swaps
$175.0
9/07 to 9/10
0.6% to 4.6%
Cash flow hedge

At times, we may use treasury lock derivative instruments to hedge the underlying U.S. treasury rates related to forecasted issuances of debt.  As cash flow hedges, gains or losses on these instruments are recorded in other comprehensive income and amortized to earnings using the effective interest method over the estimated term of the underlying fixed-rate debt.  In March 2008, we terminated treasury locks having a combined notional amount of $350.0 million.  On April 1, 2008, we terminated additional treasury locks having a notional amount of $250.0 million.  We recognized an aggregate loss of $20.7 million in other comprehensive income during the first quarter of 2008 related to these terminations.  We recognized no losses in other comprehensive income during the second quarter of 2008 in connection with such terminations.

In the first quarter of 2009, we entered into two forward starting interest rate swaps to hedge the underlying benchmark interest payments related to the forecasted issuances of debt.

 
Number and Type of
Notional
Period of
Average Rate
Accounting
Hedged Transaction
Derivative Employed
Amount
Hedge
Locked
Treatment
Enterprise Products Partners:
         
   Future debt offering
1 forward starting swap
$50.0
6/10 to 6/20
3.293%
Cash flow hedge
   Future debt offering
1 forward starting swap
$150.0
2/11 to 2/21
3.4615%
Cash flow hedge

For information regarding consolidated fair value amounts and gains and losses on interest rate derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items” within this Note 4.
 
 
14

 
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
Commodity Derivative Instruments

The prices of natural gas, NGLs and certain petrochemical products are subject to fluctuations in response to changes in supply, demand, general market uncertainty and a variety of additional factors that are beyond our control. In order to manage the price risk associated with such products, we enter into commodity derivative instruments such as forwards, basis swaps and futures contracts.  The following table summarizes our commodity derivative instruments outstanding at June 30, 2009:

 
Volume (1)
Accounting
Derivative Purpose
Current
Long-Term (2)
Treatment
Derivatives designated as hedging instruments under SFAS 133:
     
  Enterprise Products Partners:
     
      Natural gas processing:
     
          Forecasted natural gas purchases for plant thermal reduction (“PTR”) (3)
31.7 Bcf
n/a
Cash flow hedge
          Forecasted NGL sales
2.2 MMBbls
n/a
Cash flow hedge
      Octane enhancement:
     
          Forecasted purchases of natural gas liquids
0.1 MMBbls
n/a
Cash flow hedge
          Natural gas liquids inventory management activities
n/a
0.1 MMBbls
Cash flow hedge
          Forecasted sales of octane enhancement products
1.5 MMBbls
n/a
Cash flow hedge
      Natural gas marketing:
     
          Natural gas storage inventory management activities
7.4 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
5.0 MMBbls
0.8 MMBbls
Cash flow hedge
       
Derivatives not designated as hedging instruments under SFAS 133:
     
   Enterprise Products Partners:
     
      Natural gas risk management activities (4) (5)
296.1 Bcf
10.4 Bcf
Mark-to-market
   Duncan Energy Partners:
     
      Natural gas risk management activities (5)
1.6 Bcf
n/a
Mark-to-market
(1)  Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes.
(2)  The maximum term for derivatives included in the long-term column is December 2012.
(3)  PTR represents the British thermal unit (“Btu”) equivalent of the NGLs extracted from natural gas by a processing plant, and includes the natural gas used as plant fuel to extract those liquids, plant flare and other shortages.  See the discussion below for the primary objective of this strategy.
(4)  Volume includes approximately 32.3 billion cubic feet (“Bcf”) of physical derivative instruments that are predominantly priced as an index plus a premium or minus a discount.
(5)  Reflects the use of derivative instruments to manage risks associated with natural gas transportation, processing and storage assets.

The table above does not include additional hedges of forecasted NGL sales executed under contracts that have been designated as normal purchase and sale agreements under SFAS 133.   At June 30, 2009, the volume hedged under these contracts was 9.6 million barrels (“MMBbls”).

Certain of our derivative instruments do not meet the hedge accounting requirements of SFAS 133 and are accounted for as economic hedges using mark-to-market accounting.

Our predominant hedging strategy is a program to hedge a portion of our margin from natural gas processing.  The objective of this strategy is to hedge a level of gross margins associated with the NGL forward sales contracts (i.e., NGL sales revenues less actual costs for PTR and the gain or loss on the PTR hedge) by locking in the cost of natural gas used for PTR through the use of commodity derivative instruments.  This program consists of:

§  
the forward sale of a portion of our expected equity NGL production at fixed prices through 2009, and
 
 
15

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
§  
the purchase, using commodity derivative instruments, of the amount of natural gas expected to be consumed as PTR in the production of such equity NGL production.

At June 30, 2009, this program had hedged future estimated gross margins (before plant operating expenses) of $269.8 million on 10.4 MMBbls of forecasted NGL forward sales transactions extending through 2009.

For information regarding consolidated fair value amounts and gains and losses on commodity derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items” within this Note 4.

Foreign Currency Derivative Instruments

We are exposed to foreign currency exchange risk in connection with our NGL marketing activities in Canada.  As a result, we could be adversely affected by fluctuations in currency rates between the U.S. dollar and Canadian dollar.  In order to manage this risk, we may enter into foreign exchange purchase contracts to lock in the exchange rate.  Prior to 2009, these derivative instruments were accounted for using mark-to-market accounting.  Beginning with the first quarter of 2009, these transactions are accounted for as cash flow hedges.

In addition, we were exposed to foreign currency exchange risk in connection with a term loan denominated in Japanese yen (see Note 9).  We entered into this loan agreement in November 2008 and the loan matured in March 2009.  The derivative instrument used to hedge this risk was accounted for as a cash flow hedge and settled upon repayment of the loan.

We had one foreign currency derivative instrument with a notional amount of $1.7 million Canadian outstanding at June 30, 2009.  The fair market value of this instrument was an asset of $0.1 million at June 30, 2009.

For information regarding consolidated fair value amounts and gains and losses on foreign currency derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items” within this Note 4.

Credit-Risk Related Contingent Features in Derivative Instruments

 A limited number of our commodity derivative instruments include provisions related to credit ratings and/or adequate assurance clauses.  A credit rating provision provides for a counterparty to demand immediate full or partial payment to cover a net liability position upon the loss of a stipulated credit rating. An adequate assurance clause provides for a counterparty to demand immediate full or partial payment to cover a net liability position should reasonable grounds for insecurity arise with respect to contractual performance by either party.  At June 30, 2009, the aggregate fair value of our over-the-counter derivative instruments in a net liability position was $8.0 million, of which approximately $7.8 million was subject to a credit rating contingent feature.  If our credit ratings were downgraded to Ba2/BB, approximately $2.8 million would be payable as a margin deposit to the counterparties, and if our credit ratings were downgraded to Ba3/BB- or below, approximately $7.8 million would be payable as a margin deposit to the counterparties.  The potential for derivatives with contingent features to enter a net liability position may change in the future as positions and prices fluctuate.
 
 
16

 
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, 2009
December 31, 2008
June 30, 2009
December 31, 2008
 
Balance Sheet
Fair
Balance Sheet
Fair
Balance Sheet
Fair
Balance Sheet
Fair
 
Location
Value
Location
Value
Location
Value
Location
Value
Derivatives designated as hedging instruments under SFAS 133
Interest rate derivatives
Derivative assets
$ 18.7
Derivative assets
$ 7.8
Derivative liabilities
$ 5.3
Derivative liabilities
$ 5.9
Interest rate derivatives
Other assets
  32.3
Other assets
  39.0
Other liabilities
  4.7
Other liabilities
  3.9
Total interest rate derivatives
    51.0     46.8     10.0     9.8
Commodity derivatives
Derivative assets
  101.8
Derivative assets
  150.5
Derivative liabilities
  228.3
Derivative liabilities
  253.5
Commodity derivatives
Other assets
  0.1
Other assets
  --
Other liabilities
  3.7
Other liabilities
  0.2
Total commodity derivatives (1)
    101.9     150.5     232.0     253.7
Foreign currency derivatives (2)
Derivative assets
  0.1
Derivative assets
  9.3
Derivative liabilities
  --
Derivative liabilities
  --
Total derivatives designated as hedging instruments
  $ 153.0   $ 206.6   $ 242.0   $ 263.5
                         
Derivatives not designated as hedging instruments under SFAS 133
Commodity derivatives
Derivative assets
$ 108.7
Derivative assets
$ 35.2
Derivative liabilities
$ 103.4
Derivative liabilities
$ 27.7
Commodity derivatives
Other assets
  0.2
Other assets
  --
Other liabilities
  0.1
Other liabilities
  --
Total commodity derivatives
    108.9     35.2     103.5     27.7
Foreign currency derivatives
Derivative assets
  --
Derivative assets
  --
Derivative liabilities
  --
Derivative liabilities
  0.1
Total derivatives not designated as hedging instruments
  $ 108.9   $ 35.2   $ 103.5   $ 27.8
                         
(1)  Represent commodity derivative instrument transactions that either have not settled or have settled and not been invoiced. Settled and invoiced transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction.
(2)  Relates to the hedging of our exposure to fluctuations in the foreign currency exchange rate related to our Canadian NGL marketing subsidiary.

The following tables present the effect of our derivative instruments designated as fair value hedges under SFAS 133 on our condensed statements of income for the periods indicated:

Derivatives in SFAS 133
       
Fair Value
   
Gain/(Loss) Recognized in
 
Hedging Relationships
Location
 
Income on Derivative
 
     
For the Three Months
   
For the Six Months
 
     
Ended June 30,
   
Ended June 30,
 
     
2009
   
2008
   
2009
   
2008
 
Interest rate derivatives
Interest expense
  $ (14.9 )   $ (32.5 )   $ (16.2 )   $ (5.9 )
Commodity derivatives
Revenue
    (1.0 )     --       (1.1 )     --  
   Total
    $ (15.9 )   $ (32.5 )   $ (17.3 )   $ (5.9 )
 
 
17

 
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
Derivatives in SFAS 133
       
Fair Value
   
Gain/(Loss) Recognized in
 
Hedging Relationships
Location
 
Income on Hedged Item
 
     
For the Three Months
   
For the Six Months
 
     
Ended June 30,
   
Ended June 30,
 
     
2009
   
2008
   
2009
   
2008
 
Interest rate derivatives
Interest expense
  $ 14.3     $ 32.5     $ 15.6     $ 5.9  
Commodity derivatives
Revenue
    1.0       --       1.1       --  
   Total
    $ 15.3     $ 32.5     $ 16.7     $ 5.9  

The following tables present the effect of our derivative instruments designated as cash flow hedges under SFAS 133 on our condensed statements of income for the periods indicated:

Derivatives in SFAS 133
 
Change in Value
 
Cash Flow
 
Recognized in OCI on
 
Hedging Relationships
 
Derivative (Effective Portion)
 
   
For the Three Months
   
For the Six Months
 
   
Ended June 30,
   
Ended June 30,
 
   
2009
   
2008
   
2009
   
2008
 
Interest rate derivatives
  $ 15.8     $ 4.2     $ 15.1     $ (21.8 )
Commodity derivatives – Revenue
    75.8       (14.4 )     65.8       (4.9 )
Commodity derivatives – Operating costs and expenses
    (152.4 )     45.5       (204.4 )     124.8  
Foreign currency derivatives
    0.1       (0.1 )     (10.5 )     (1.3 )
   Total
  $ (60.7 )   $ 35.2     $ (134.0 )   $ 96.8  

Derivatives in SFAS 133
Location of Gain/(Loss)
 
Amount of Gain/(Loss)
 
Cash Flow
Reclassified from AOCI
 
Reclassified from AOCI
 
Hedging Relationships
into Income (Effective Portion)
 
to Income (Effective Portion)
 
     
For the Three Months
   
For the Six Months
 
     
Ended June 30,
   
Ended June 30,
 
     
2009
   
2008
   
2009
   
2008
 
Interest rate derivatives
Interest expense
  $ (1.1 )   $ 0.8     $ (2.0 )   $ 2.4  
Commodity derivatives
Revenue
    4.4       (3.1 )     19.7       (6.1 )
Commodity derivatives
Operating costs and expenses
    (70.7 )     20.0       (118.2 )     18.8  
   Total
    $ (67.4 )   $ 17.7     $ (100.5 )   $ 15.1  

 
Location of Gain/(Loss)
 
Amount of Gain/(Loss)
 
Derivatives in SFAS 133
Recognized in Income
 
Recognized in Income on
 
Cash Flow
on Ineffective Portion
 
Ineffective Portion of
 
Hedging Relationships
of Derivative
 
Derivative
 
     
For the Three Months
   
For the Six Months
 
     
Ended June 30,
   
Ended June 30,
 
     
2009
   
2008
   
2009
   
2008
 
Commodity derivatives
Revenue
  $ (0.7 )   $ (0.5 )   $ (0.7 )   $ --  
Commodity derivatives
Operating costs and expenses
    (0.2 )     0.5       (1.3 )     2.8  
   Total
    $ (0.9 )   $ --     $ (2.0 )   $ 2.8  

Over the next twelve months, we expect to reclassify $4.4 million of accumulated other comprehensive loss (“AOCI”) attributable to interest rate derivative instruments to earnings as an increase to interest expense. Likewise, we expect to reclassify $150.2 million of AOCI attributable to commodity derivative instruments to earnings, $120.6 million as an increase in operating costs and expenses and $29.6 million as a reduction in revenues.
 
 
18

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
The following table presents the effect of our derivative instruments not designated as hedging instruments under SFAS 133 on our condensed statements of income for the periods indicated:

Derivatives Not
       
Designated as SFAS 133
   
Gain/(Loss) Recognized in
 
Hedging Instruments
Location
 
Income on Derivative
 
     
For the Three Months
   
For the Six Months
 
     
Ended June 30,
   
Ended June 30,
 
     
2009
   
2008
   
2009
   
2008
 
Commodity derivatives (1)
Revenue
  $ 7.2     $ (4.2 )   $ 31.9     $ (2.9 )
Commodity derivatives
Operating costs and expenses
    --       (5.3 )     --       (9.0 )
Foreign currency derivatives
Other income
    --       --       (0.1 )     --  
   Total
    $ 7.2     $ (9.5 )   $ 31.8     $ (11.9 )
                                   
(1)  Amounts for the three and six months ended June 30, 2009 include $2.7 million and $2.9 million of gains on derivatives that were excluded from fair value hedging relationships, respectively.
 

SFAS 157 – Fair Value Measurements

SFAS 157 (ASC 820) defines fair value 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.

SFAS 157 established a three-tier hierarchy that classifies fair value amounts recognized or disclosed in the financial statements based on the observability of inputs used to estimate such fair values.  The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy.  The characteristics of fair value amounts classified within each level of the SFAS 157 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 NYMEX).  Our Level 1 fair values primarily consist of financial assets and liabilities such as exchange-traded commodity financial instruments.

§  
Level 2 fair values are based on pricing inputs other than quoted prices in active markets (as reflected in Level 1 fair values) and are either directly or indirectly observable as of the measurement date.  Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies.  Such financial models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, the time value of money, volatility factors, current market and contractual prices for the underlying instruments and other relevant economic measures.  Substantially all of these assumptions are (i) observable in the marketplace throughout the full term of the instrument, (ii) can be derived from observable data or (iii) are validated by inputs other than quoted prices (e.g., interest rate and yield curves at commonly quoted intervals).  Our Level 2 fair values primarily consist of commodity financial instruments such as forwards, swaps and other instruments transacted on an exchange or over the counter.  The fair values of these derivatives are based on
 
 
19

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
observable price quotes for similar products and locations.  The value of our interest rate derivatives are valued by using appropriate financial models with the implied forward LIBOR yield curve for the same period as the future interest swap settlements.
 
§  
Level 3 fair values are based on unobservable inputs.  Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.  Unobservable inputs reflect the reporting entity’s own ideas about the assumptions that market participants would use in pricing an asset or liability (including assumptions about risk).  Unobservable inputs are based on the best information available in the circumstances, which might include the reporting entity’s internally developed data.  The reporting entity must not ignore information about market participant assumptions that is reasonably available without undue cost and effort.  Level 3 inputs are typically used in connection with internally developed valuation methodologies where management makes its best estimate of an instrument’s fair value.  Our Level 3 fair values largely consist of ethane and normal butane-based contracts with a range of two to twelve months in term.  We rely on broker quotes for these products due to the forward markets for these products being less liquid.

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities measured on a recurring basis at June 30, 2009.  These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.

   
Level 1
   
Level 2
   
Level 3
   
Total
 
Financial assets:
                       
Interest rate derivative instruments
  $ --     $ 51.0     $ --     $ 51.0  
Commodity derivative instruments
    12.7       179.0       19.1       210.8  
Foreign currency derivatives
    --       0.1       --       0.1  
Total
  $ 12.7     $ 230.1     $ 19.1     $ 261.9  
                                 
Financial liabilities:
                               
Interest rate derivative instruments
  $ --     $ 10.0     $ --     $ 10.0  
Commodity derivative instruments
    58.2       269.0       8.3       335.5  
Total
  $ 58.2     $ 279.0     $ 8.3     $ 345.5  
 
 
20

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
The following table sets forth a reconciliation of changes in the fair value of our Level 3 financial assets and liabilities for the periods presented:

   
For the Six Months
 
   
Ended June 30,
 
   
2009
   
2008
 
Balance, January 1
  $ 32.6     $ (4.6 )
Total gains (losses) included in:
               
Net income (1)
    12.5       (2.3 )
Other comprehensive income (loss)
    1.5       2.4  
Purchases, issuances, settlements
    (12.5 )     1.9  
Balance, March 31
    34.1       (2.6 )
Total gains (losses) included in:
               
Net income (1)
    7.7       0.3  
Other comprehensive income (loss)
    (23.1 )     (2.4 )
Purchases, issuances, settlements
    (7.7 )     0.1  
Transfers out of Level 3
    (0.2 )     --  
Balance, June 30
  $ 10.8     $ (4.6 )
                 
(1)  There were $0.1 million of unrealized gains and $0.2 million of unrealized losses included in these amounts for the three and six months ended June 30, 2009, respectively. For the three and six months ended June 30, 2008, there were no unrealized gains or losses included in these amounts.
 

We adopted the provisions of SFAS 157 that apply to nonfinancial assets and liabilities on January 1, 2009.  Our adoption of this guidance had no impact on our financial position, results of operations or cash flows.  Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances (for example, when there is evidence of impairment).  There were no fair value adjustments for such assets or liabilities reflected in our consolidated financial statements for the three and six months ended June 30, 2009.


Note 5.  Inventories

Our inventory amounts were as follows at the dates indicated:
 
   
June 30,
   
December 31,
 
   
2009
   
2008
 
   Working inventory (1)
  $ 438.8     $ 200.4  
   Forward sales inventory (2)
    527.0       162.4  
      Total inventory
  $ 965.8     $ 362.8  
                 
(1)  Working inventory is comprised of inventories of natural gas, NGLs and certain petrochemical products that are either available-for-sale or used in providing services.
(2)  Forward sales inventory consists of identified NGL and natural gas volumes dedicated to the fulfillment of forward sales contracts. As a result of energy market conditions, we significantly increased our physical inventory purchases and related forward physical sales commitments during 2009. Of the $527.0 million in forward sales inventory at June 30, 2009, approximately $432.0 million relates to forward sales NGL volumes. In general, the significant increase in volumes dedicated to forward physical sales contracts improves the overall utilization and profitability of our fee-based assets. The cash invested in forward sales NGL inventories is expected to be recovered within the next twelve months, with approximately $163.4 million realized by December 31, 2009.
 
 
Our inventory values reflect payments for product purchases, freight charges associated with such purchase volumes, terminal and storage fees, vessel inspection costs, demurrage charges and other related costs.  We value our inventories at the lower of average cost or market.
 
 
21

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
Operating costs and expenses, as presented on our Unaudited Condensed Statements of Consolidated Operations, include cost of sales amounts related to the sale of inventories.  Our costs of sales amounts were $2.70 billion and $5.51 billion for the three months ended June 30, 2009 and 2008, respectively.  For the six months ended June 30, 2009 and 2008, our costs of sales amounts were $5.33 billion and $10.41 billion, respectively.  The decrease in cost of sales period-to-period is primarily due to lower energy commodity prices associated with our marketing activities.

Due to fluctuating commodity prices, we recognize lower of average cost or market (“LCM”) adjustments when the carrying value of our available-for-sale inventories exceed their net realizable value.  These non-cash charges are a component of cost of sales in the period they are recognized, and reflected in operating costs and expenses as presented on our Unaudited Condensed Statements of Consolidated Operations.  For the three months ended June 30, 2009 and 2008, we recognized LCM adjustments of $0.3 million and $0.7 million, respectively.  We recognized LCM adjustments of $6.0 million and $4.8 million for the six months ended June 30, 2009 and 2008, respectively.


Note 6.  Property, Plant and Equipment

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

   
Estimated
             
   
Useful Life
   
June 30,
   
December 31,
 
   
in Years
   
2009
   
2008
 
Plants and pipelines (1)
    3-45 (5)     $ 13,863.8     $ 12,296.3  
Underground and other storage facilities (2)
    5-35 (6)       930.8       900.7  
Platforms and facilities (3)
    20-31       637.5       634.8  
Transportation equipment (4)
    3-10       39.3       38.7  
Land
            59.0       54.6  
Construction in progress
            669.8       1,604.7  
    Total
            16,200.2       15,529.8  
Less accumulated depreciation
            2,618.2       2,375.0  
    Property, plant and equipment, net
          $ 13,582.0     $ 13,154.8  
                         
(1)  Plants and pipelines include processing plants; NGL, petrochemical, oil and natural gas pipelines; terminal loading and unloading facilities; office furniture and equipment; buildings; laboratory and shop equipment; and related assets.
(2)  Underground and other storage facilities include underground product storage caverns; storage tanks; water wells; and related assets.
(3)  Platforms and facilities include offshore platforms and related facilities and other associated assets.
(4)  Transportation equipment includes vehicles and similar assets used in our operations.
(5)  In general, the estimated useful lives of major components of this category are as follows: processing plants, 20-35 years; pipelines, 18-45 years (with some equipment at 5 years); terminal facilities, 10-35 years; office furniture and equipment, 3-20 years; buildings, 20-35 years; and laboratory and shop equipment, 5-35 years.
(6)  In general, the estimated useful lives of major components of this category are as follows: underground storage facilities, 20-35 years (with some components at 5 years); storage tanks, 10-35 years; and water wells, 25-35 years (with some components at 5 years).
 

The following table summarizes our depreciation expense and capitalized interest amounts for the periods indicated:

   
For the Three Months
   
For the Six Months
 
   
Ended June 30,
   
Ended June 30,
 
   
2009
   
2008
   
2009
   
2008
 
Depreciation expense (1)
  $ 130.5     $ 114.0     $ 255.5     $ 223.8  
Capitalized interest (2)
    5.6       17.6       17.7       35.7  
                                 
(1)  Depreciation expense is a component of costs and expenses as presented in our Unaudited Condensed Statements of Consolidated Operations.
(2)  Capitalized interest increases the carrying value of the associated asset and reduces interest expense during the period it is recorded.
 
 
 
22

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
In May 2009, we acquired certain rail and truck terminal facilities located in Mont Belvieu, Texas from Martin Midstream Partners L.P. (“Martin”).  Cash consideration paid for this business combination was $23.7 million, all of which was recorded as additions to property, plant and equipment.

On a pro forma consolidated basis, our revenues, costs and expenses, operating income, net income and earnings per unit amounts would not have differed materially from those we actually reported for the three and six months ended June 30, 2009 and 2008 due to the immaterial nature of our 2009 business combination transaction.

Asset Retirement Obligations

Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of certain tangible long-lived assets that result from acquisitions, construction, development and/or normal operations.  The following table presents information regarding our AROs since December 31, 2008.

ARO liability balance, December 31, 2008
  $ 37.7  
   Liabilities incurred
    0.4  
   Liabilities settled
    (11.1 )
   Revisions in estimated cash flows
    21.3  
   Accretion expense
    1.1  
ARO liability balance, June 30, 2009
  $ 49.4  

The increase in our ARO liability balance during 2009 primarily reflects revised estimates of the cost to comply with regulatory abandonment obligations associated with our facilities offshore in the Gulf of Mexico.  We incurred $11.1 million of costs through June 30, 2009 as a result of ARO settlement activities associated with certain pipeline laterals and a platform located in the Gulf of Mexico.

Property, plant and equipment at June 30, 2009 and December 31, 2008 includes $24.9 million and $9.9 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset.  Based on information currently available, we estimate that accretion expense will approximate $1.7 million for the last six months of 2009, $3.4 million for each of 2010 and 2011, $3.7 million for 2012 and $4.0 million for 2013.
 
 
23

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
 
Note 7.  Investments in Unconsolidated Affiliates

We own interests in a number of related businesses that are accounted for using the equity method of accounting.  Our investments in unconsolidated affiliates are grouped according to the business segment to which they relate.  See Note 11 for a general discussion of our business segments.  The following table shows our investments in unconsolidated affiliates at the dates indicated.

   
Ownership
       
   
Percentage at
       
   
June 30,
   
June 30,
   
December 31,
 
   
2009
   
2009
   
2008
 
NGL Pipelines & Services:
                 
Venice Energy Service Company, L.L.C.
    13.1%     $ 31.6     $ 37.7  
K/D/S Promix, L.L.C. (“Promix”)
    50%       47.8       46.4  
Baton Rouge Fractionators LLC
    32.2%       23.3       24.1  
Skelly-Belvieu Pipeline Company, L.L.C. (“Skelly-Belvieu”)
    49%       37.0       36.0  
Onshore Natural Gas Pipelines & Services:
                       
Jonah Gas Gathering Company (“Jonah”)
    19.4%       250.4       258.1  
Evangeline (1)
    49.5%       5.0       4.5  
White River Hub, LLC
    50%       27.2       21.4  
Offshore Pipelines & Services: