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ENERGY TRANSFER PARTNERS 10-Q 2010

Documents found in this filing:

  1. 10-Q
  2. Ex-31.1
  3. Ex-31.2
  4. Ex-32.1
  5. Ex-32.2
  6. Ex-32.2
Form 10-Q
Table of Contents

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

 

x

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

For the quarterly period ended                September 30, 2010        

or

 

¨

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

Commission file number 1-11727

ENERGY TRANSFER PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

 

Delaware   73-1493906
(state or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)

3738 Oak Lawn Avenue, Dallas, Texas 75219

(Address of principal executive offices and zip code)

(214) 981-0700

(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        x        No        ¨

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        x         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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer        x

  Accelerated filer        ¨  

Non-accelerated filer          ¨

  Smaller reporting company        ¨  

(Do not check if a smaller reporting company)

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes        ¨         No        x

At November 3, 2010, the registrant had units outstanding as follows:

Energy Transfer Partners, L.P. 191,599,549 Common Units


Table of Contents

 

FORM 10-Q

INDEX TO FINANCIAL STATEMENTS

Energy Transfer Partners, L.P. and Subsidiaries

 

PART I — FINANCIAL INFORMATION

  

ITEM 1. FINANCIAL STATEMENTS (Unaudited)

  

Condensed Consolidated Balance Sheets – September 30, 2010 and December 31, 2009

     1   

Condensed Consolidated Statements of Operations – Three and Nine Months Ended September 30, 2010 and 2009

     3   

Condensed Consolidated Statements of Comprehensive Income – Three and Nine Months Ended September 30, 2010 and 2009

     4   

Condensed Consolidated Statement of Partners’ Capital – Nine Months Ended September 30, 2010

     5   

Condensed Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2010 and 2009

     6   

Notes to Condensed Consolidated Financial Statements

     7   

ITEM 2.

  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS      31   

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     45   

ITEM 4. CONTROLS AND PROCEDURES

     47   
PART II — OTHER INFORMATION   

ITEM 1. LEGAL PROCEEDINGS

     48   

ITEM 1A. RISK FACTORS

     48   

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

     49   

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

     50   

ITEM 4. [RESERVED]

  

ITEM 5. OTHER INFORMATION

     50   

ITEM 6. EXHIBITS

     50   

SIGNATURE

    

53

  

 

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Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Partners, L.P. (“Energy Transfer Partners” or “the Partnership”) in periodic press releases and some oral statements of Energy Transfer Partners, officials during presentations about the Partnership, include certain “forward-looking” statements. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect” “continue,” “estimate,” “forecast,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Partnership believes such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such expectations will prove to be correct.

Actual results may differ materially from any results projected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Part II Other Information – Item 1A. Risk Factors” in this Quarterly Report on Form 10-Q and our Quarterly Reports on Form 10-Q for the quarters ended March 31 and June 30, 2010, as well as “Part I – Item 1A. Risk Factors” in the Partnership’s Report on Form 10-K for the year ended December 31, 2009 filed with the Securities and Exchange Commission (“SEC”) on February 24, 2010.

Definitions

The following is a list of certain acronyms and terms generally used in the energy industry and throughout this document:

 

 

/d

  

per day

 

Bbls

  

barrels

 

Btu

  

British thermal unit, an energy measurement. A therm factor is used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy used

 

Capacity

  

capacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels

 

Dth

  

million British thermal units (“dekatherm”)

 

Mcf

  

thousand cubic feet

 

MMBtu

  

million British thermal units

 

MMcf

  

million cubic feet

 

Bcf

  

billion cubic feet

 

NGL

  

natural gas liquid, such as propane, butane and natural gasoline

 

Tcf

  

trillion cubic feet

 

LIBOR

  

London Interbank Offered Rate

 

NYMEX

  

New York Mercantile Exchange

 

Reservoir

  

a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs

 

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Table of Contents

 

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(unaudited)

 

     September 30,
2010
    December 31,
2009
 

ASSETS

    

CURRENT ASSETS:

    

Cash and cash equivalents

   $ 77,700      $ 68,183   

Marketable securities

     2,270        6,055   

Accounts receivable, net of allowance for doubtful accounts of $6,382 and $6,338 as of September 30, 2010 and December 31, 2009, respectively

     400,665        566,522   

Accounts receivable from related companies

     45,774        57,369   

Inventories

     277,073        389,954   

Exchanges receivable

     18,473        23,136   

Price risk management assets

     5,740        12,371   

Other current assets

     121,605        148,373   
                

Total current assets

     949,300        1,271,963   

PROPERTY, PLANT AND EQUIPMENT

     10,763,239        9,649,405   

ACCUMULATED DEPRECIATION

     (1,203,104     (979,158
                
     9,560,135        8,670,247   

ADVANCES TO AND INVESTMENTS IN AFFILIATES

     7,863        663,298   

LONG-TERM PRICE RISK MANAGEMENT ASSETS

     201          

GOODWILL

     772,825        745,505   

INTANGIBLES AND OTHER ASSETS, net

     424,007        383,959   
                

Total assets

   $ 11,714,331      $ 11,734,972   
                

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(unaudited)

 

     September 30,
2010
     December 31,
2009
 

LIABILITIES AND PARTNERS’ CAPITAL

     

CURRENT LIABILITIES:

     

Accounts payable

   $ 275,406       $ 358,997   

Accounts payable to related companies

     11,777         38,842   

Exchanges payable

     11,200         19,203   

Price risk management liabilities

     25         442   

Accrued and other current liabilities

     491,067         365,168   

Current maturities of long-term debt

     35,182         40,887   
                 

Total current liabilities

     824,657         823,539   

LONG-TERM DEBT, less current maturities

     6,004,646         6,176,918   

LONG-TERM PRICE MANAGEMENT LIABILITIES

     13,164           

OTHER NON-CURRENT LIABILITIES

     138,727         134,807   

COMMITMENTS AND CONTINGENCIES (Note 13)

     

PARTNERS’ CAPITAL:

     

General Partner

     174,497         174,884   

Limited Partners:

     

Common Unitholders (191,578,586 and 179,274,747 units authorized, issued and outstanding at September 30, 2010 and December 31, 2009, respectively)

     4,514,214         4,418,017   

Class E Unitholders (8,853,832 units authorized, issued and outstanding – held by subsidiary and reported as treasury units)

               

Accumulated other comprehensive income

     44,426         6,807   
                 

Total partners’ capital

     4,733,137         4,599,708   
                 

Total liabilities and partners’ capital

   $ 11,714,331       $ 11,734,972   
                 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit data)

(unaudited)

 

     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
     2010     2009     2010     2009  

REVENUES:

        

Natural gas operations

   $ 1,082,866      $ 943,975      $ 3,435,521      $ 3,004,163   

Retail propane

     183,786        162,224        914,372        829,901   

Other

     23,992        23,397        80,438        77,449   
                                

Total revenues

     1,290,644        1,129,596        4,430,331        3,911,513   
                                

COSTS AND EXPENSES:

        

Cost of products sold – natural gas operations

     666,022        591,797        2,232,867        1,865,914   

Cost of products sold – retail propane

     104,533        80,232        519,796        378,524   

Cost of products sold – other

     6,856        6,119        20,470        18,842   

Operating expenses

     174,740        158,883        515,021        517,337   

Depreciation and amortization

     85,612        81,684        252,765        230,461   

Selling, general and administrative

     44,734        33,534        137,743        143,015   
                                

Total costs and expenses

     1,082,497        952,249        3,678,662        3,154,093   
                                

OPERATING INCOME

     208,147        177,347        751,669        757,420   

OTHER INCOME (EXPENSE):

        

Interest expense, net of interest capitalized

     (101,241     (101,503     (309,217     (284,228

Equity in earnings of affiliates

     595        9,581        10,848        11,751   

Gains (losses) on disposal of assets

     281        (1,088     (198     (1,333

Gains (losses) on non-hedged interest rate derivatives

     (11,963     (18,241     (11,963     32,327   

Allowance for equity funds used during construction

     12,432        30        18,039        18,618   

Impairment of investment in affiliate

                   (52,620       

Other, net

     1,129        3,433        (3,731     4,400   
                                

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)

     109,380        69,559        402,827        538,955   

Income tax expense (benefit)

     1,993        (2,897     12,486        8,594   
                                

NET INCOME

     107,387        72,456        390,341        530,361   

GENERAL PARTNER’S INTEREST IN NET INCOME

     97,046        88,927        287,644        266,396   
                                

LIMITED PARTNERS’ INTEREST IN NET INCOME (LOSS)

   $ 10,341      $ (16,471   $ 102,697      $ 263,965   
                                

BASIC NET INCOME (LOSS) PER LIMITED PARTNER UNIT

   $ 0.05      $ (0.10   $ 0.54      $ 1.60   
                                

BASIC AVERAGE NUMBER OF UNITS OUTSTANDING

     185,247,021        168,815,563        186,761,917        164,183,538   
                                

DILUTED NET INCOME (LOSS) PER LIMITED PARTNER UNIT

   $ 0.05      $ (0.10   $ 0.53      $ 1.59   
                                

DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING

     186,214,685        168,815,563        187,708,683        164,886,492   
                                

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in thousands)

(unaudited)

 

     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
     2010     2009     2010     2009  

Net income

   $ 107,387      $ 72,456      $   390,341      $   530,361   

Other comprehensive income (loss), net of tax:

        

Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges

     (5,388     871        (18,006     (8,822

Change in value of derivative instruments accounted for as cash flow hedges

     34,776        (15,150     59,410        (15,200

Change in value of available-for-sale securities

     (732     3,049        (3,785     6,757   
                                
     28,656        (11,230     37,619        (17,265
                                

Comprehensive income

   $ 136,043      $ 61,226      $   427,960      $   513,096   
                                

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2010

(Dollars in thousands)

(unaudited)

 

     General
Partner
    Limited
Partner
Common
Unitholders
    Accumulated
Other
Comprehensive
Income
     Total  

Balance, December 31, 2009

   $ 174,884      $ 4,418,017      $ 6,807       $ 4,599,708   

Redemption of units in connection with MEP Transaction (See Note 8)

     (3,700     (608,340             (612,040

Distributions to partners

     (293,282     (501,506             (794,788

Units issued for cash

            1,086,991                1,086,991   

Capital contribution from General Partner (payment of contributions receivable)

     8,932                       8,932   

Distributions on unvested unit awards

            (3,398             (3,398

Tax effect of remedial income allocation from tax amortization of goodwill

            (2,552             (2,552

Non-cash unit-based compensation expense, net of units tendered by employees for tax withholdings

            21,386                21,386   

Non-cash executive compensation

     19        919                938   

Other comprehensive income

                   37,619         37,619   

Net income

     287,644        102,697                390,341   
                                 

Balance, September 30, 2010

   $ 174,497      $ 4,514,214      $ 44,426       $ 4,733,137   
                                 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

(unaudited)

 

     Nine Months Ended
September  30,
 
     2010     2009  

NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES

   $ 1,102,896      $ 796,017   
                

CASH FLOWS FROM INVESTING ACTIVITIES:

    

Cash paid for acquisitions, net of cash acquired

     (156,388     (6,244

Capital expenditures (excluding allowance for equity funds used during construction)

     (1,036,903     (703,461

Contributions in aid of construction costs

     12,048        5,251   

Advances to affiliates, net of repayments

     (6,046     (534,500

Proceeds from the sale of assets

     13,742        13,235   
                

Net cash used in investing activities

     (1,173,547     (1,225,719
                

CASH FLOWS FROM FINANCING ACTIVITIES:

    

Proceeds from borrowings

     809,949        2,287,035   

Principal payments on debt

     (1,007,617     (1,768,079

Net proceeds from issuance of Limited Partner units

     1,086,991        578,924   

Capital contribution from General Partner

     8,932        3,354   

Distributions to partners

     (794,788     (705,736

Redemption of units

     (23,299       

Debt issuance costs

            (7,639
                

Net cash provided by financing activities

     80,168        387,859   
                

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

     9,517        (41,843

CASH AND CASH EQUIVALENTS, beginning of period

     68,183        91,902   
                

CASH AND CASH EQUIVALENTS, end of period

   $ 77,700      $ 50,059   
                

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Tabular dollar amounts, except per unit data, are in thousands)

(unaudited)

 

1.

OPERATIONS AND ORGANIZATION:

The accompanying condensed consolidated balance sheet as of December 31, 2009, which has been derived from audited financial statements, and the unaudited interim financial statements and notes thereto of Energy Transfer Partners, L.P., and its subsidiaries (“Energy Transfer Partners,” the “Partnership,” “we” or “ETP”) as of September 30, 2010 and for the three and nine months ended September 30, 2010 and 2009, have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim consolidated financial information and pursuant to the rules and regulations of the SEC. Accordingly, they do not include all the information and footnotes required by GAAP for complete consolidated financial statements. However, management believes that the disclosures made are adequate to make the information not misleading. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year due to the seasonal nature of the Partnership’s operations, maintenance activities and the impact of forward natural gas prices and differentials on certain derivative financial instruments that are accounted for using mark-to-market accounting. Management has evaluated subsequent events through the date the financial statements were issued.

In the opinion of management, all adjustments (all of which are normal and recurring) have been made that are necessary to fairly state the consolidated financial position of Energy Transfer Partners, and its subsidiaries as of September 30, 2010, and the Partnership’s results of operations and cash flows for the three and nine months ended September 30, 2010 and 2009. The unaudited interim condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto of Energy Transfer Partners presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009, as filed with the SEC on February 24, 2010.

Certain prior period amounts have been reclassified to conform to the 2010 presentation. These reclassifications had no impact on net income or total partners’ capital.

We are managed by our general partner, Energy Transfer Partners GP, L.P. (our “General Partner” or “ETP GP”), which is in turn managed by its general partner, Energy Transfer Partners, L.L.C. (“ETP LLC”). Energy Transfer Equity, L.P., a publicly traded master limited partnership (“ETE”), owns ETP LLC, the general partner of our General Partner. The condensed consolidated financial statements of the Partnership presented herein include our operating subsidiaries described below.

Business Operations

In order to simplify the obligations of Energy Transfer Partners, under the laws of several jurisdictions in which we conduct business, our activities are primarily conducted through our operating subsidiaries (collectively the “Operating Companies”) as follows:

 

   

La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company (“ETC OLP”), a Texas limited partnership engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico, Utah and Colorado. Our intrastate transportation and storage operations primarily focus on transporting natural gas through our Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System. Our midstream operations focus on the gathering, compression, treating, conditioning and processing of natural gas, primarily on or through our Southeast Texas System and North Texas System, and marketing activities. We also own and operate natural gas gathering pipelines and conditioning facilities in the Piceance-Uinta Basin of Colorado and Utah.

 

   

Energy Transfer Interstate Holdings, LLC (“ET Interstate”), a Delaware limited liability company with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales. ET Interstate is the parent company of:

 

   

Transwestern Pipeline Company, LLC (“Transwestern”), a Delaware limited liability company engaged in interstate transportation of natural gas. Interstate revenues consist primarily of fees earned from natural gas transportation services and operational gas sales.

 

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ETC Fayetteville Express Pipeline, LLC (“ETC FEP”), a Delaware limited liability company formed to engage in interstate transportation of natural gas.

 

   

ETC Tiger Pipeline, LLC (“ETC Tiger”), a Delaware limited liability company formed to engage in interstate transportation of natural gas.

 

   

ETC Compression, LLC (“ETC Compression”), a Delaware limited liability company engaged in natural gas compression services and related equipment sales.

 

   

Heritage Operating, L.P. (“HOLP”), a Delaware limited partnership primarily engaged in retail propane operations. Our retail propane operations focus on sales of propane and propane-related products and services. The retail propane customer base includes residential, commercial, industrial and agricultural customers.

 

   

Titan Energy Partners, L.P. (“Titan”), a Delaware limited partnership also engaged in retail propane operations.

 

2.

ESTIMATES:

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.

Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, allowances for doubtful accounts, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, estimates related to our unit-based compensation plans, deferred taxes, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.

 

3.

ACQUISITIONS:

In March 2010, we purchased a natural gas gathering company, which provides dehydration, treating, redelivery and compression services on a 120-mile pipeline system in the Haynesville Shale for approximately $150.0 million in cash, excluding certain adjustments as defined in the purchase agreement. In connection with this transaction, we recorded customer contracts of $68.2 million and goodwill of $27.3 million. See further discussion at Note 6.

 

4.

CASH, CASH EQUIVALENTS AND SUPPLEMENTAL CASH FLOW INFORMATION:

Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value.

We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

 

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Net cash provided by operating activities is comprised of the following:

 

     Nine Months Ended
September 30,
 
     2010     2009  

Net income

   $ 390,341      $ 530,361   

Reconciliation of net income to net cash provided by operating activities:

    

Impairment of investment in affiliate

     52,620          

Proceeds from termination of interest rate derivatives

     26,495          

Depreciation and amortization

     252,765        230,461   

Amortization of finance costs charged to interest

     7,216        6,386   

Non-cash unit-based compensation expense

     21,422        20,942   

Non-cash executive compensation expense

     938        938   

Deferred income taxes

     4,492        3,663   

Losses on disposal of assets

     198        1,333   

Allowance for equity funds used during construction

     (18,039     (18,618

Distributions on unvested awards

     (3,398     (2,072

Distributions in excess of (less than) equity in earnings of affiliates, net

     20,765        (5,696

Other non-cash

     2,427        4,033   

Changes in operating assets and liabilities, net of effects of acquisitions:

    

Accounts receivable

     166,064        235,239   

Accounts receivable from related companies

     11,596        (17,882

Inventories

     113,568        51,249   

Exchanges receivable

     4,663        29,775   

Other current assets

     26,796        (10,573

Intangibles and other assets

     4,560        (1,977

Accounts payable

     (86,291     (109,479

Accounts payable to related companies

     (7,253     (27,150

Exchanges payable

     (8,003     (32,236

Accrued and other current liabilities

     58,925        8,582   

Other non-current liabilities

     (600     669   

Price risk management assets and liabilities, net

     60,629        (101,931
                

Net cash provided by operating activities

   $ 1,102,896      $ 796,017   
                

Non-cash investing and financing activities are as follows:

 

     Nine Months Ended
September 30,
 
     2010      2009  

NON-CASH INVESTING ACTIVITIES:

     

Accrued capital expenditures

   $ 55,013       $ 64,530   
                 

Transfer of MEP joint venture interest in exchange for redemption of Common Units

   $ 588,741       $   
                 

NON-CASH FINANCING ACTIVITIES:

     

Capital contributions receivable from general partner

   $       $ 8,932   
                 

Long-term debt assumed and non-compete agreement notes payable issued in acquisitions

   $ 618       $ 17,113   
                 

 

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5.

INVENTORIES:

Inventories consisted of the following:

 

     September 30,
2010
     December 31,
2009
 

Natural gas and NGLs, excluding propane

   $ 94,514       $ 157,103   

Propane

     57,018         66,686   

Appliances, parts and fittings and other

     125,541         166,165   
                 

Total inventories

   $   277,073       $ 389,954   
                 

We utilize commodity derivatives to manage price volatility associated with our natural gas inventory and designate certain of these derivatives as fair value hedges for accounting purposes. Changes in fair value of the designated hedged inventory have been recorded in inventory on our condensed consolidated balance sheets and cost of products sold in our condensed consolidated statements of operations.

 

6.

GOODWILL, INTANGIBLES AND OTHER ASSETS:

A net increase in goodwill of $27.3 million was recorded during the nine months ended September 30, 2010, primarily due to the acquisition of the natural gas gathering company referenced in Note 3. This additional goodwill is expected to be deductible for tax purposes. In addition, we recorded customer contracts of $68.2 million with useful lives of 46 years.

Components and useful lives of intangibles and other assets were as follows:

 

     September 30, 2010     December 31, 2009  
     Gross Carrying
Amount
     Accumulated
Amortization
    Gross Carrying
Amount
     Accumulated
Amortization
 

Amortizable intangible assets:

          

Customer relationships, contracts and agreements (3 to 46 years)

   $ 244,808       $ (70,624   $ 176,858       $ (58,761

Noncompete agreements (3 to 15 years)

     21,592         (11,965     24,139         (12,415

Patents (9 years)

     750         (97     750         (35

Other (10 to 15 years)

     1,320         (466     478         (397
                                  

Total amortizable intangible assets

     268,470         (83,152     202,225         (71,608

Non-amortizable intangible assets – Trademarks

     76,086                75,825           
                                  

Total intangible assets

     344,556         (83,152     278,050         (71,608

Other assets:

          

Financing costs (3 to 30 years)

     67,795         (30,401     68,597         (24,774

Regulatory assets

     107,233         (13,476     101,879         (9,501

Other

     31,452                41,316           
                                  

Total intangibles and other assets

   $ 551,036       $ (127,029   $ 489,842       $ (105,883
                                  

 

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Aggregate amortization expense of intangibles and other assets was as follows:

 

     Three Months Ended
September 30,
     Nine Months Ended
September 30,
 
     2010      2009      2010      2009  

Reported in depreciation and amortization

   $ 5,124       $ 6,243       $ 15,418       $ 15,935   
                                   

Reported in interest expense

   $ 2,159       $ 2,125       $ 6,489       $ 6,051   
                                   

Estimated aggregate amortization expense for the next five years is as follows:

 

Years Ending December 31:

      

2011

   $   26,916   

2012

     23,330   

2013

     17,899   

2014

     16,890   

2015

     14,566   

We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review goodwill and non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate. Our annual impairment test is performed as of August 31 for reporting units within our intrastate transportation and storage, midstream and retail propane operations. We have not completed our annual impairment tests for 2010 and have not recorded any impairments related to amortizable intangible assets during the nine months ended September 30, 2010.

 

7.

FAIR VALUE MEASUREMENTS:

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Price risk management assets and liabilities are recorded at fair value. Based on the estimated borrowing rates currently available to us and our subsidiaries for long-term loans with similar terms and average maturities, the aggregate fair value and carrying amount of long-term debt at September 30, 2010 was $6.94 billion and $6.04 billion, respectively. At December 31, 2009, the aggregate fair value and carrying amount of long-term debt was $6.75 billion and $6.22 billion, respectively.

We have marketable securities, commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value in our condensed consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider over-the-counter (“OTC”) commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 since we use a LIBOR curve based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements and discount the future cash flows accordingly, including the effects of credit risk. Level 3 inputs are unobservable. We currently do not have any recurring fair value measurements that are considered Level 3 valuations.

 

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The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of September 30, 2010 and December 31, 2009 based on inputs used to derive their fair values:

 

           Fair Value Measurements at
September 30, 2010 Using
 
     Fair Value
Total
    Quoted Prices
in Active
Markets for
Identical Assets
and Liabilities
(Level 1)
    Significant
Observable
Inputs
(Level 2)
 

Assets:

      

Marketable securities

   $ 2,270      $ 2,270      $   

Interest rate derivatives

     201               201   

Commodity derivatives:

      

Natural Gas:

      

Fixed Swaps/Futures

     37,047        36,992        55   

Options – Puts

     29,025               29,025   

Propane – Forwards/Swaps

     5,685               5,685   
                        

Total commodity derivatives

     71,757        36,992        34,765   
                        

Total Assets

   $ 74,228      $ 39,262      $ 34,966   
                        

Liabilities:

      

Interest rate derivatives

   $ (13,164   $      $ (13,164

Commodity derivatives:

      

Natural Gas:

      

Basic Swaps IFERC/NYMEX

     (1,153     (1,153       

Swing Swaps IFERC

     (938     (913     (25

Options – Calls

     (1,576            (1,576
                        

Total commodity derivatives

     (3,667     (2,066     (1,601
                        

Total Liabilities

   $ (16,831   $ (2,066   $ (14,765
                        
           Fair Value Measurements at
December 31, 2009 Using
 
     Fair Value
Total
    Quoted Prices
in Active
Markets for
Identical Assets
and Liabilities
(Level 1)
    Significant
Observable
Inputs
(Level 2)
 

Assets:

      

Marketable securities

   $ 6,055      $ 6,055      $   

Commodity derivatives

     32,479        20,090        12,389   

Liabilities:

      

Commodity derivatives

     (8,016     (7,574     (442
                        

Total

   $ 30,518      $ 18,571      $ 11,947   
                        

In conjunction with the MEP Transaction, we adjusted the investment in MEP to fair value based on the present value of the expected future cash flows (Level 3), resulting in a nonrecurring fair value adjustment of $52.6 million. Substantially all of our investment was transferred to ETE. See Note 8.

 

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8.

INVESTMENTS IN AFFILIATES:

Midcontinent Express Pipeline LLC

On May 26, 2010, we completed the transfer of the membership interests in ETC Midcontinent Express Pipeline III, L.L.C. (“ETC MEP III”) to ETE pursuant to the Redemption and Exchange Agreement between us and ETE, dated as of May 10, 2010 (the “MEP Transaction”). ETC MEP III owns a 49.9% membership interest in Midcontinent Express Pipeline LLC (“MEP”), our joint venture with Kinder Morgan Energy Partners, L.P. (“KMP”) that owns and operates the Midcontinent Express Pipeline. In exchange for the membership interests in ETC MEP III, we redeemed 12,273,830 ETP common units that were previously owned by ETE. We also paid $23.3 million to ETE upon closing of the MEP Transaction for adjustments related to capital expenditures and working capital changes of MEP. Subsequent to September 30, 2010, we received a cash closing adjustment of $8.2 million from ETE. ETE has an option that cannot be exercised until May 27, 2011, to acquire the membership interests in ETC Midcontinent Express Pipeline II, L.L.C. (“ETC MEP II”). ETC MEP II owns a 0.1% membership interest in MEP. In conjunction with this transfer of our interest in ETC MEP III, we recorded a non-cash charge of approximately $52.6 million during the three months ended June 30, 2010 to reduce the carrying value of our interest in ETC MEP III to its estimated fair value.

As part of the MEP Transaction, on May 26, 2010, ETE completed the contribution of the membership interests in ETC MEP III and the assignment of its rights under the option to acquire the membership interests in ETC MEP II to a subsidiary of Regency Energy Partners LP (“Regency”) in exchange for 26,266,791 Regency common units. In addition, ETE acquired a 100% equity interest in the general partner entities of Regency from an affiliate of GE Energy Financial Services, Inc.

We continue to guarantee 50% of MEP’s obligations under MEP’s $175.4 million senior revolving credit facility, with the remaining 50% of MEP’s obligations guaranteed by KMP. Regency has agreed to indemnify us for any costs related to the guaranty of payments under this facility. See Note 13.

Fayetteville Express Pipeline LLC

We are party to an agreement with KMP for a 50/50 joint development of the Fayetteville Express pipeline, an approximately 185-mile natural gas pipeline that will originate in Conway County, Arkansas, continue eastward through White County, Arkansas and terminate at an interconnect with Trunkline Gas Company in Panola County, Mississippi. In December 2009, Fayetteville Express Pipeline LLC (“FEP”), the entity formed to construct, own and operate this pipeline, received Federal Energy Regulatory Commission (“FERC”) approval of its application for authority to construct and operate this pipeline. In July 2010, FERC granted a rehearing of the December 2009 order and allowed FEP to include in its initial rate proposed allowance for funds used during construction that accrued prior to filing its application. The pipeline began interim service in October 2010 and is expected to be fully operational in December 2010. Upon completion of all facilities, the pipeline is expected to have an initial capacity of 2.0 Bcf/d. As of September 30, 2010, FEP has secured binding commitments for a minimum of 10 years for transportation of approximately 1.85 Bcf/d. The new pipeline will interconnect with Natural Gas Pipeline Company of America (“NGPL”) in White County, Arkansas, Texas Gas Transmission in Coahoma County, Mississippi and ANR Pipeline Company in Quitman County, Mississippi. NGPL is operated and partially owned by Kinder Morgan, Inc. Kinder Morgan, Inc. owns the general partner of KMP.

 

9.

NET INCOME (LOSS) PER LIMITED PARTNER UNIT:

Our net income (loss) for partners’ capital and statement of operations presentation purposes is allocated to the General Partner and Limited Partners in accordance with their respective partnership percentages, after giving effect to priority income allocations for incentive distributions, if any, to our General Partner, the holder of the incentive distribution rights (“IDRs”) pursuant to our partnership agreement, which are declared and paid following the close of each quarter. Earnings in excess of distributions are allocated to the General Partner and Limited Partners based on their respective ownership interests.

 

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A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:

 

    Three Months Ended
September  30,
    Nine Months Ended
September  30,
 
    2010     2009     2010     2009  

Net income

  $ 107,387      $ 72,456      $ 390,341      $ 530,361   

General Partner’s interest in net income

    97,046        88,927        287,644        266,396   
                               

Limited Partners’ interest in net income (loss)

    10,341        (16,471     102,697        263,965   

Additional earnings allocated from General Partner

    161        185        790        185   

Distributions on employee unit awards, net of allocation to General Partner

    (1,142     (668     (3,451     (2,017
                               

Net income (loss) available to Limited Partners

  $ 9,360      $ (16,954   $ 100,036      $ 262,133   
                               

Weighted average Limited Partner units – basic

    185,247,021        168,815,563        186,761,917        164,183,538   
                               

Basic net income (loss) per Limited Partner unit

  $ 0.05      $ (0.10   $ 0.54      $ 1.60   
                               

Weighted average Limited Partner units

    185,247,021        168,815,563        186,761,917        164,183,538   

Dilutive effect of unvested Unit Awards

    967,664               946,766        702,954   
                               

Weighted average Limited Partner units, assuming dilutive effect of unvested Unit Awards

    186,214,685        168,815,563        187,708,683        164,886,492   
                               

Diluted net income (loss) per Limited Partner unit

  $ 0.05      $ (0.10   $ 0.53      $ 1.59   
                               

Based on the declared distribution rate of $0.89375 per Common Unit, distributions paid for the three months ended September 30, 2009, were $249.5 million in total, which exceeded net income for the period by $177.0 million. Accordingly, the distributions paid to the General Partner, including incentive distributions, further exceeded the net income for the three months ended September 30, 2009, and as a result, a net loss was allocated to the Limited Partners for the period.

 

10.

DEBT OBLIGATIONS:

Revolving Credit Facilities

ETP Credit Facility

We maintain a revolving credit facility (the “ETP Credit Facility”) that provides for $2.0 billion of revolving credit capacity that is expandable to $3.0 billion (subject to obtaining the approval of the administrative agent and securing lender commitments for the increased borrowing capacity). The ETP Credit Facility matures on July 20, 2012, unless we elect the option of one-year extensions (subject to the approval of each such extension by the lenders holding a majority of the aggregate lending commitments). Amounts borrowed under the ETP Credit Facility bear interest, at our option, at a Eurodollar rate plus an applicable margin or a base rate. The base rate used to calculate interest on base rate loans will be calculated using the greater of a prime rate or a federal funds effective rate plus 0.50%. The applicable margin for Eurodollar loans ranges from 0.30% to 0.70% based upon ETP’s credit rating and is currently 0.55% (0.60% if facility usage exceeds 50%). The commitment fee payable on the unused portion of the ETP Credit Facility varies based on our credit rating with a maximum fee of 0.125%. The fee is 0.11% based on our current rating.

 

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As of September 30, 2010, there were no outstanding borrowings under the ETP Credit Facility. Taking into account letters of credit of approximately $22.4 million, the amount available for future borrowings was $1.98 billion.

HOLP Credit Facility

HOLP has a $75.0 million Senior Revolving Facility (the “HOLP Credit Facility”) available to HOLP through June 30, 2011, which may be expanded to $150.0 million. Amounts borrowed under the HOLP Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The commitment fee payable on the unused portion of the facility varies based on the Leverage Ratio, as defined in the credit agreement for the HOLP Credit Facility, with a maximum fee of 0.50%. The agreement includes provisions that may require contingent prepayments in the event of dispositions, loss of assets, merger or change of control. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts of HOLP and the capital stock of HOLP’s subsidiaries secure the HOLP Credit Facility. At September 30, 2010, the HOLP credit facility had no outstanding balance in revolving credit loans and outstanding letters of credit of $0.5 million. The amount available for borrowing as of September 30, 2010 was $74.5 million.

Covenants Related to Our Credit Agreements

We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements at September 30, 2010.

 

11.

PARTNERS’ CAPITAL:

Common Units Issued

The change in Common Units during the nine months ended September 30, 2010 was as follows:

 

     Number of
Units
 

Balance, December 31, 2009

     179,274,747   

Common Units issued in connection with public offerings

     20,700,000   

Common Units issued in connection with the Equity Distribution Agreement

     3,842,283   

Issuance of Common Units under equity incentive plans

     35,386   

Redemption of units in connection with MEP Transaction (See Note 8)

     (12,273,830
        

Balance, September 30, 2010

     191,578,586   
        

In January 2010, we issued 9,775,000 Common Units through a public offering for net proceeds of $423.6 million. In August 2010, we issued 10,925,000 Common Units through a public offering for net proceeds of $489.4 million. The proceeds from these offerings were used primarily to repay borrowings under the ETP Credit Facility and to fund capital expenditures related to pipeline projects.

On August 26, 2009, we entered into an Equity Distribution Agreement with UBS Securities LLC (“UBS”). Pursuant to this agreement, we may offer and sell from time to time through UBS, as our sales agent, Common Units having an aggregate value of up to $300.0 million. Sales of the units will be made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between us and UBS. Under the terms of this agreement, we may also sell Common Units to UBS as principal for its own account at a price agreed upon at the time of sale. Any sale of Common Units to UBS as principal would be pursuant to the terms of a separate agreement between us and UBS. During the nine months ended September 30, 2010, we issued 3,842,283 of our Common Units pursuant to this agreement. The proceeds of approximately $174.1 million, net of commissions, were used for general partnership purposes. Approximately $40.6 million of our Common Units remain available to be issued under the agreement based on trades initiated through September 30, 2010.

 

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Quarterly Distributions of Available Cash

Distributions paid by us are summarized as follows:

 

Quarter Ended

  

Record Date

  

Payment Date

   Distributions Per
Common Unit
 

December 31, 2009

   February 8, 2010    February 15, 2010    $ 0.89375   

March 31, 2010

   May 7, 2010    May 17, 2010      0.89375   

June 30, 2010

   August 9, 2010    August 16, 2010      0.89375   

On October 28, 2010, ETP declared a cash distribution for the three months ended September 30, 2010 of $0.89375 per Common Unit, or $3.575 annualized. This distribution will be paid on November 15, 2010 to Unitholders of record at the close of business on November 8, 2010.

The total amounts of distributions declared during the nine months ended September 30, 2010 and 2009 were as follows (all from Available Cash from our operating surplus and are shown in the period with respect to which they relate):

 

     Nine Months Ended
September 30,
 
     2010      2009  

Limited Partners:

     

Common Units

   $ 503,582       $ 460,132   

Class E Units

     9,363         9,363   

General Partner Interest

     14,634         14,626   

Incentive Distribution Rights

     279,823         256,530   
                 

Total distributions declared

   $ 807,402       $ 740,651   
                 

Accumulated Other Comprehensive Income

The following table presents the components of accumulated other comprehensive income (“AOCI”), net of tax:

 

     September 30,
2010
     December 31,
2009
 

Net gains on commodity related hedges

   $ 43,270       $ 1,991   

Net losses on interest rate hedges

             (125

Unrealized gains on available-for-sale securities

     1,156         4,941   
                 

Total AOCI, net of tax

   $ 44,426       $ 6,807   
                 

 

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12.

INCOME TAXES:

The components of the federal and state income tax expense (benefit) of our taxable subsidiaries are summarized as follows:

 

     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
     2010     2009     2010     2009  

Current expense (benefit):

        

Federal

   $ (3,794   $ (88   $ (877   $ (5,195

State

     1,450        3,231        8,871        10,126   
                                

Total

     (2,344     3,143        7,994        4,931   
                                

Deferred expense (benefit):

        

Federal

     4,357        (5,670     4,778        3,472   

State

     (20     (370     (286     191   
                                

Total

     4,337        (6,040     4,492        3,663   
                                

Total income tax expense (benefit)

   $ 1,993      $ (2,897   $ 12,486      $ 8,594   
                                

Effective tax rate

     1.82     (4.16 )%      3.10     1.59
                                

The effective tax rate differs from the statutory rate due primarily to Partnership earnings that are not subject to federal and state income taxes at the Partnership level.

 

13.

REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

Regulatory Matters

In August 2009, we filed an application for FERC authority to construct and operate the Tiger pipeline. The application was approved in April 2010 and construction began in June 2010. Subject to regulatory approvals, we expect initial service on the Tiger pipeline to commence in the fourth quarter of 2010. In February 2010, we announced a 400 MMcf/d expansion of the Tiger pipeline. In June 2010, we filed an application for FERC authority to construct, own and operate that expansion, which remains under review before the FERC.

On September 29, 2006, Transwestern filed revised tariff sheets under Section 4(e) of the Natural Gas Act (“NGA”) proposing a general rate increase to be effective on November 1, 2006. In April 2007, the FERC approved a Stipulation and Agreement of Settlement that resolved the primary components of the rate case. Transwestern’s tariff rates and fuel rates are now final for the period of the settlement. Transwestern is required to file a new rate case no later than October 1, 2011.

Guarantees

MEP Guarantee

We have guaranteed 50% of the obligations of MEP under its senior revolving credit facility (the “MEP Facility”), with the remaining 50% of MEP Facility obligations guaranteed by KMP. Effective in May 2010, the commitment amount was reduced to $175.4 million due to lower usage and anticipated capital contributions. Although we transferred substantially all of our interest in MEP on May 26, 2010, as discussed above in Note 8, we will continue to guarantee 50% of MEP’s obligations under this facility through the maturity of the facility in February 2011. Regency has agreed to indemnify us for any costs related to the guarantee of payments under this facility.

Subject to certain exceptions, our guarantee may be proportionately increased or decreased if our ownership percentage in MEP increases or decreases. The MEP Facility is unsecured and matures on February 28, 2011. Amounts borrowed under the MEP Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The commitment fee payable on the unused portion of the MEP Facility varies based on both our credit rating and

 

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that of KMP, with a maximum fee of 0.15%. The MEP Facility contains covenants that limit (subject to certain exceptions) MEP’s ability to grant liens, incur indebtedness, engage in transactions with affiliates, enter into restrictive agreements, enter into mergers, or dispose of substantially all of its assets.

As of September 30, 2010, MEP had $82.2 million of outstanding borrowings and $33.3 million of letters of credit issued under the MEP Facility. Our contingent obligations with respect to our 50% guarantee of MEP’s outstanding borrowings and letters of credit were $41.1 million and $16.6 million, respectively, as of September 30, 2010. The weighted average interest rate on the total amount outstanding as of September 30, 2010 was 0.9%.

FEP Guarantee

On November 13, 2009, FEP entered into a credit agreement that provides for a $1.1 billion senior revolving credit facility (the “FEP Facility”). We have guaranteed 50% of the obligations of FEP under the FEP Facility, with the remaining 50% of FEP Facility obligations guaranteed by KMP. Subject to certain exceptions, our guarantee may be proportionately increased or decreased if our ownership percentage in FEP increases or decreases. The FEP Facility is available through May 11, 2012 and amounts borrowed under the FEP Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The commitment fee payable on the unused portion of the FEP Facility varies based on both our credit rating and that of KMP, with a maximum fee of 1.0%.

As of September 30, 2010, FEP had $847.0 million of outstanding borrowings issued under the FEP Facility and our contingent obligation with respect to our 50% guarantee of FEP’s outstanding borrowings was $423.5 million as of September 30, 2010. The weighted average interest rate on the total amount outstanding as of September 30, 2010 was 3.3%.

Commitments

In the normal course of our business, we purchase, process and sell natural gas pursuant to long-term contracts. In addition, we enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We have also entered into several propane purchase and supply commitments, which are typically one year agreements with varying terms as to quantities, prices and expiration dates. We also have a contract to purchase not less than 90.0 million gallons of propane per year that expires in 2015. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on our financial position or results of operations.

We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2034. Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled approximately $5.0 million and $6.0 million for the three months ended September 30, 2010 and 2009, respectively. For the nine months ended September 30, 2010 and 2009, rental expense for operating leases totaled approximately $16.3 million and $17.5 million, respectively.

Our propane operations have an agreement with a subsidiary of Enterprise GP Holdings L.P. (see Note 15) to supply a portion of our propane requirements. The agreement expired in March 2010; however, our propane operations executed a five year extension as of April 2010. The extension will continue until March 2015 and includes an option to extend the agreement for an additional year.

We have commitments to make capital contributions to our joint ventures. For the joint ventures that we currently have interests in, we expect that future capital contributions will be between $10 million and $15 million, which we expect to contribute primarily during the last three months of 2010.

Litigation and Contingencies

We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and propane are flammable, combustible gases. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.

 

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FERC and Related Matters. On July 26, 2007, the FERC issued to us an Order to Show Cause and Notice of Proposed Penalties (the “Order and Notice”) that contains allegations that we violated FERC rules and regulations. The FERC alleged that we engaged in manipulative or improper trading activities in the Houston Ship Channel, primarily on two dates during the fall of 2005 following the occurrence of Hurricanes Katrina and Rita, as well as on eight other occasions from December 2003 through August 2005, in order to benefit financially from our commodities derivatives positions and from certain of our index-priced physical gas purchases in the Houston Ship Channel. The FERC alleged that during these periods we violated the FERC’s then-effective Market Behavior Rule 2, an anti-market manipulation rule promulgated by the FERC under authority of the NGA. The FERC alleged that we violated this rule by artificially suppressing prices that were included in the Platts Inside FERC Houston Ship Channel index, published by McGraw-Hill Companies, on which the pricing of many physical natural gas contracts and financial derivatives are based. The FERC also alleged that one of our intrastate pipelines violated various FERC regulations by, among other things, granting undue preferences in favor of an affiliate. In its Order and Notice, the FERC specified that it was seeking $69.9 million in disgorgement of profits, plus interest, and $82.0 million in civil penalties relating to these market manipulation claims. In February 2008, the FERC’s Enforcement Staff also recommended that the FERC pursue market manipulation claims related to ETP’s trading activities in October 2005 for November 2005 monthly deliveries, a period not previously covered by the FERC’s allegations in the Order and Notice, and that ETP be assessed an additional civil penalty of $25.0 million and be required to disgorge approximately $7.3 million of alleged unjust profits related to this additional month.

On August 26, 2009, we entered into a settlement agreement with the FERC’s Enforcement Staff with respect to the pending FERC claims against us and, on September 21, 2009, the FERC approved the settlement agreement without modification. The agreement resolves all outstanding FERC claims against us and provides that we make a $5.0 million payment to the federal government and establish a $25.0 million fund for the purpose of settling related third-party claims based on or arising out of the market manipulation allegation against us by those third parties that elect to make a claim against this fund, including existing litigation claims as well as any new claims that may be asserted against this fund. Pursuant to the settlement agreement, the FERC made no findings of fact or conclusions of law. In addition, the settlement agreement specifies that by executing the settlement agreement we do not admit or concede to the FERC or any third party any actual or potential fault, wrongdoing or liability in connection with our alleged conduct related to the FERC claims. The settlement agreement also requires us to maintain specified compliance programs and to conduct independent annual audits of such programs for a two-year period.

In September 2009, the FERC appointed an administrative law judge, or ALJ, to establish a process of potential claimants to make claims against the $25.0 million fund, to determine the validity of any such claims and to make a recommendation to the FERC relating to the application of this fund to any potential claimants. Pursuant to the process established by the ALJ, a number of parties submitted claims against this fund and, subsequent thereto, the ALJ made various determinations with respect to the validity of these claims, solely for purposes of participation in this fund allocation process, and the methodology for making payments from the fund to claimants. In June 2010, each claimant that had been allocated a payment amount from the fund by the ALJ was required to make a determination as to whether to accept the ALJ’s recommended payment amount from the fund, and all such claimants accepted their allocated payment amounts. In connection with accepting the allocated payment amount, each such claimant was required to waive and release all claims against ETP related to this matter.

In addition to the claims that were settled pursuant to the ALJ fund allocation process discussed above, ETP was a party in three legal proceedings that asserted contract and tort claims relating to alleged manipulation of natural gas prices at the Houston Ship Channel and the Waha Hub in West Texas, as well as the natural gas price indices related to these markets and the Permian Basin natural gas price index during the period from December 2003 through December 2006. In all three of these legal proceedings, we have received favorable rulings at the lower court and appellate court levels that have resulted in the dismissal of all claims made in these proceedings, and no further appeals or motions for rehearing may be pursued by the plaintiffs in these proceedings except with respect to one proceeding as to which the plaintiffs may seek review at the U.S. Supreme Court, which action we believe is unlikely to occur.

We are expensing the legal fees, consultants’ fees and other expenses relating to these matters in the periods in which such costs are incurred. We record accruals for litigation and other contingencies whenever required by applicable accounting standards. Based on the terms of the settlement agreement with the FERC described above, we made the $5.0 million payment and established the $25.0 million fund in October 2009. The after-tax impact of the settlement was less than $30.0 million due to tax benefits resulting from the portion of the payment that is used to satisfy third party claims.

 

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Houston Pipeline Cushion Gas Litigation. At the time of the HPL System acquisition, AEP Energy Services Gas Holding Company II, L.L.C., HPL Consolidation LP and its subsidiaries (the “HPL Entities”), their parent companies and American Electric Power Corporation (“AEP”), were defendants in litigation with Bank of America (“B of A”) that related to AEP’s acquisition of HPL in the Enron bankruptcy and B of A’s financing of cushion gas stored in the Bammel storage facility (“Cushion Gas”). This litigation is referred to as the “Cushion Gas Litigation.” In 2004, ETC OLP (a subsidiary of ETP) acquired the HPL Entities from AEP, at which time AEP agreed to indemnify ETC OLP and the HPL Entities for any damages arising from the Cushion Gas Litigation and the loss of use of the Cushion Gas, up to a maximum of the amount paid by ETC OLP for the HPL Entities and the working gas inventory (approximately $1.00 billion in the aggregate). The Cushion Gas Litigation Agreement terminates upon final resolution of the Cushion Gas Litigation. In addition, under the terms of the Purchase and Sale Agreement, AEP retained control of additional matters relating to ongoing litigation and environmental remediation and agreed to bear the costs of or indemnify ETC OLP and the HPL Entities for the costs related to such matters. On December 18, 2007, the United States District Court for the Southern District of New York held that B of A is entitled to receive monetary damages from AEP and the HPL Entities of approximately $347.3 million less the monetary amount B of A would have incurred to remove 55 Bcf of natural gas from the Bammel storage facility. Based on the indemnification provisions of the Cushion Gas Litigation Agreement, ETP expects that it will be indemnified for any monetary damages awarded to B of A under this court decision.

Other Matters. In addition to those matters described above, we or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable, can be estimated and is not covered by insurance, we make an accrual for the matter. For matters that are covered by insurance, we accrue the related deductible. As of September 30, 2010 and December 31, 2009, accruals of approximately $10.4 million and $11.1 million, respectively, were recorded related to deductibles. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

The outcome of these matters cannot be predicted with certainty and it is possible that the outcome of a particular matter will result in the payment of an amount in excess of the amount accrued for the matter. As our accrual amounts are non-cash, any cash payment of an amount in resolution of a particular matter would likely be made from cash from operations or borrowings. If cash payments to resolve a particular matter substantially exceed our accrual for such matter, we may experience a material adverse impact on our results of operations, cash available for distribution and our liquidity.

No amounts have been recorded in our September 30, 2010 or December 31, 2009 consolidated balance sheets for our contingencies and current litigation matters, other than accruals related to environmental matters and deductibles.

Environmental Matters

Our operations are subject to extensive federal, state and local environmental and safety laws and regulations that can require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the natural gas pipeline, gathering, treating, compressing, blending and processing business. As a result, there can be no assurance that significant costs and liabilities will not be incurred. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the issuance of injunctions and the filing of federally authorized citizen suits. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs and liabilities. Accordingly, we have adopted policies, practices and procedures in the areas of pollution control, product safety, occupational safety and health, and the handling, storage, use, and disposal of hazardous materials to prevent and minimize material environmental or other damage, and to limit the

 

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financial liability, which could result from such events. However, the risk of environmental or other damage is inherent in the transporting, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products, as it is with other entities engaged in similar businesses.

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in clean-up technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.

As of September 30, 2010 and December 31, 2009, accruals on an undiscounted basis of $12.3 million and $12.6 million, respectively, were recorded in our condensed consolidated balance sheets as accrued and other current liabilities and other non-current liabilities related to environmental matters.

Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for clean-up costs.

Transwestern conducts soil and groundwater remediation at a number of its facilities. Some of the clean-up activities include remediation of several compressor sites on the Transwestern system for historical contamination associated with polychlorinated biphenyls (“PCBs”) and the costs of this work are not eligible for recovery in rates. The total accrued future estimated cost of remediation activities expected to continue through 2018 is $8.3 million, which is included in the aggregate environmental accruals. Transwestern received FERC approval for rate recovery of projected soil and groundwater remediation costs not related to PCBs effective April 1, 2007.

Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing potential PCBs. Future costs cannot be reasonably estimated because remediation activities are undertaken as potential claims are made by customers and former customers. However, such future costs are not expected to have a material impact on our financial position, results of operations or cash flows.

Environmental regulations were recently modified for the U.S. Environmental Protection Agency’s (the “EPA”) Spill Prevention, Control and Countermeasures program. We are currently reviewing the impact to our operations and expect to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures. Costs associated with tank integrity testing and resulting corrective actions cannot be reasonably estimated at this time, but we believe such costs will not have a material adverse effect on our financial position, results of operations or cash flows.

Petroleum-based contamination or environmental wastes are known to be located on or adjacent to six sites on which HOLP presently has, or formerly had, retail propane operations. These sites were evaluated at the time of their acquisition. In all cases, remediation operations have been or will be undertaken by others, and in all six cases, HOLP obtained indemnification rights for expenses associated with any remediation from the former owners or related entities. We have not been named as a potentially responsible party at any of these sites, nor have our operations contributed to the environmental issues at these sites. Accordingly, no amounts have been recorded in our September 30, 2010 or December 31, 2009 consolidated balance sheets. Based on information currently available to us, such projects are not expected to have a material adverse effect on our financial condition or results of operations.

By March 2013, the Texas Commission on Environmental Quality is required to develop another plan to address the recent change in the ozone standard from 0.08 parts per million, or ppm, to 0.075 ppm and the EPA recently proposed lowering the standard even further, to somewhere in between 0.06 and 0.07 ppm. These efforts may result in the adoption of new regulations that may require additional nitrogen oxide emissions reductions.

Our pipeline operations are subject to regulation by the U.S. Department of Transportation (“DOT”) under the Pipeline Hazardous Materials Safety Administration (“PHMSA”), pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure

 

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testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. For the three months ended September 30, 2010 and 2009, $5.8 million and $9.3 million, respectively, of capital costs and $3.9 million and $3.6 million, respectively, of operating and maintenance costs have been incurred for pipeline integrity testing. For the nine months ended September 30, 2010 and 2009, $10.8 million and $24.6 million, respectively, of capital costs and $10.2 million and $12.6 million, respectively, of operating and maintenance costs have been incurred for pipeline integrity testing. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines.

Our operations are also subject to the requirements of the federal Occupational Safety and Health Act, also known as OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

National Fire Protection Association Pamphlets No. 54 and No. 58, which establish rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted as the industry standard in all of the states in which we operate. In some states, these laws are administered by state agencies, and in others, they are administered on a municipal level. With respect to the transportation of propane by truck, we are subject to regulations governing the transportation of hazardous materials under the Federal Motor Carrier Safety Act, administered by the DOT. We conduct ongoing training programs to help ensure that our operations are in compliance with applicable regulations. We believe that the procedures currently in effect at all of our facilities for the handling, storage and distribution of propane are consistent with industry standards and are in substantial compliance with applicable laws and regulations.

 

14.

PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

We are exposed to market risks related to the volatility of natural gas, NGL and propane prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in the consolidated balance sheets. In general, we use derivatives to eliminate market exposure and price risk within our segments as follows:

 

   

Derivatives are utilized in our midstream segment in order to mitigate price volatility in our marketing activities and manage fixed price exposure incurred from contractual obligations.

 

   

We use derivative financial instruments in connection with our natural gas inventory at the Bammel storage facility by purchasing physical natural gas and then selling financial contracts at a price sufficient to cover its carrying costs and provide a gross profit margin. We also use derivatives in our intrastate transportation and storage and interstate segments to hedge the sales price of retention and operational gas sales and hedge location price differentials related to the transportation of natural gas.

 

   

Our propane segment permits customers to guarantee the propane delivery price for the next heating season. As we execute fixed sales price contracts with our customers, we may enter into propane futures contracts to fix the purchase price related to these sales contracts, thereby locking in a gross profit margin. Additionally, we may use propane futures contracts to secure the purchase price of our propane inventory for a percentage of our anticipated propane sales.

We inject and hold natural gas in our Bammel storage facility to take advantage of contango markets, when the price of natural gas is higher in the future than the current spot price. We use financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, we lock in a margin by purchasing gas in the spot market or off peak season and entering a financial contract to lock in the sale price. If we designate the related financial contract as a fair value hedge for accounting purposes, we value the hedged natural gas inventory at current spot market prices along with the financial derivative we use to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges and the physical

 

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inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. Unrealized margins represent the unrealized gains or losses from our derivative instruments using mark-to-market accounting, with changes in the fair value of our derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot price and forward natural gas prices. If the spread narrows between the physical and financial prices, we will record unrealized gains or lower unrealized losses. If the spread widens, we will record unrealized losses or lower unrealized gains. Typically, as we enter the winter months, the spread converges so that we recognize in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdrawal of natural gas.

We are also exposed to market risk on natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation segment. We use financial derivatives to hedge the sales price of this gas, including futures, swaps and options. Certain contracts that qualify for hedge accounting are designated as cash flow hedges of the forecasted sale of natural gas. The change in value, to the extent the contracts are effective, remains in accumulated other comprehensive income until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.

We attempt to maintain balanced positions in our marketing activities to protect ourselves from the volatility in the energy commodities markets; however, net unbalanced positions can exist. Long-term physical contracts are tied to index prices. System gas, which is also tied to index prices, is expected to provide most of the gas required by our long-term physical contracts. When third-party gas is required to supply long-term contracts, a hedge is put in place to protect the margin on the contract. Financial contracts, which are not tied to physical delivery, are expected to be offset with financial contracts to balance our positions. To the extent open commodity positions exist, fluctuating commodity prices can impact our financial position and results of operations, either favorably or unfavorably.

The following table details the outstanding commodity-related derivatives:

 

     September 30, 2010      December 31, 2009  
     Notional
Volume
    Maturity      Notional
Volume
    Maturity  

Mark-to-Market Derivatives

         

Natural Gas:

         

Basis Swaps IFERC/NYMEX (MMBtu)

     (33,870,000     2010-2011         72,325,000        2010-2011   

Swing Swaps IFERC (MMBtu)

     11,735,000        2010-2011         (38,935,000     2010   

Fixed Swaps/Futures (MMBtu)

     (250,000     2010-2011         4,852,500        2010-2011   

Options – Puts (MMBtu)

     440,000        2010-2011         2,640,000        2010   

Options – Calls (MMBtu)

     (3,440,000     2010-2011         (2,640,000     2010   

Propane:

         

Forwards/Swaps (Gallons)

                    6,090,000        2010   

Fair Value Hedging Derivatives

         

Natural Gas:

         

Basis Swaps IFERC/NYMEX (MMBtu)

     (10,060,000     2010-2011         (22,625,000     2010   

Fixed Swaps/Futures (MMBtu)

     (20,160,000     2010-2011         (27,300,000     2010   

Hedged Item – Inventory (MMBtu)

     20,160,000        2010         27,300,000        2010   

Cash Flow Hedging Derivatives

         

Natural Gas:

         

Basis Swaps IFERC/NYMEX (MMBtu)

     (4,445,000     2010-2011         (13,225,000     2010   

Fixed Swaps/Futures (MMBtu)

     (7,265,000     2010-2011         (22,800,000     2010   

Options – Puts (MMBtu)

     22,680,000        2011-2012                  

Options – Calls (MMBtu)

     (22,680,000     2011-2012                  

Propane:

         

Forwards/Swaps (Gallons)

     58,086,000        2010-2011         20,538,000        2010   

 

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We expect gains of $36.6 million related to commodity derivatives to be reclassified into earnings over the next 12 months related to amounts currently reported in AOCI. The amount ultimately realized, however, will differ as commodity prices change and the underlying physical transaction occurs.

Interest Rate Risk

We are exposed to market risk for changes in interest rates. In order to maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We manage a portion of our current and future interest rate exposures by utilizing interest rate swaps in order to achieve our desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.

In May and August 2010, we terminated interest rate swaps with total notional amounts of $750.0 million and $350.0 million, respectively, for proceeds of $15.4 million and $11.1 million, respectively. These swaps were designated as fair value hedges. In connection with the swap terminations, $9.7 million and $10.4 million of previously recorded fair value adjustments to hedged long-term debt will be amortized as a reduction of interest expense through February 2015 and July 2013, respectively. The unamortized balance remaining related to these swaps was $18.7 million as of September 30, 2010.

In August 2010, we de-designated $200.0 million of total notional amounts of forward-starting interest rate swaps previously designated as cash flow hedges. These swaps remain outstanding as of September 30, 2010, along with additional swaps with a total notional amount of $200.0 million entered into during the three months ended September 30, 2010. These forward starting swaps, which are not designated as hedges for accounting purposes, begin in August 2012 and we will pay a weighted average fixed rate of 3.64% and receive a floating rate.

In addition to interest rate swaps, we also periodically enter into interest rate swaptions that enable counterparties to exercise options to enter into interest rate swaps with us. Swaptions may be utilized when our targeted benchmark interest rate for anticipated debt issuance is not attainable at the time in the interest rate swap market. Upon issuance of a swaption, we receive a premium, which we recognize over the term of the swaption to “Gains (losses) on non-hedged interest rate derivatives” in the condensed consolidated statements of operations. No swaptions were outstanding as of September 30, 2010. In October 2010, the Partnership sold a swaption with a notional amount of $100.0 million and maturity date of December 31, 2010 to enter into a swap that, if exercised, would lock in the rate on a portion of anticipated debt issuances.

Derivative Summary

The following table provides a balance sheet overview of the Partnership’s derivative assets and liabilities as of September 30, 2010 and December 31, 2009:

 

     Fair Value of Derivative Instruments  
     Asset Derivatives      Liability Derivatives  
     September 30,
2010
     December 31,
2009
     September 30,
2010
    December 31,
2009
 

Derivatives designated as hedging instruments:

          

Commodity derivatives (margin deposits)

   $ 57,648       $ 669       $ (1,732   $ (24,035

Commodity derivatives

     5,921         8,443         (181     (201
                                  
     63,569         9,112         (1,913     (24,236
                                  

Derivatives not designated as hedging instruments:

          

Commodity derivatives (margin deposits)

     66,113         72,851         (59,654     (36,950

Commodity derivatives

             3,928         (25     (241

Interest rate derivatives

     201                 (13,164       
                                  
     66,314         76,779         (72,843     (37,191
                                  

Total derivatives

   $ 129,883       $ 85,891       $ (74,756   $ (61,427
                                  

The commodity derivatives (margin deposits) are recorded in “Other current assets” on our condensed consolidated balance sheets. The remainder of the derivatives are recorded in “Price risk management assets/liabilities.”

 

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We disclose the non-exchange traded financial derivative instruments as price risk management assets and liabilities on our condensed consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.

We utilize master-netting agreements and have maintenance margin deposits with certain counterparties in the OTC market and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the condensed consolidated balance sheets. The Partnership had net deposits with counterparties of $58.7 million and $79.7 million as of September 30, 2010 and December 31, 2009, respectively.

The following tables summarize the amounts recognized with respect to our derivative financial instruments for the periods presented:

 

     Change in Value Recognized
in OCI on Derivatives
(Effective Portion)
 
     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
     2010     2009     2010     2009  

Derivatives in cash flow hedging relationships:

        

Commodity derivatives

   $ 36,035      $ (15,146   $ 60,992      $ (15,282

Interest rate derivatives

     (1,162            (1,367       
                                

Total

   $ 34,873      $ (15,146   $ 59,625      $ (15,282
                                

 

     Location of Gain/(Loss)
Reclassified from
AOCI into  Income
(Effective Portion)
     Amount of Gain/(Loss)
Reclassified from
AOCI into Income
(Effective Portion)
 
            Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
            2010     2009     2010     2009  

Derivatives in cash flow hedging relationships:

           

Commodity derivatives

     Cost of products sold       $ 6,780      $ (847   $ 19,153      $ 8,702   

Interest rate derivatives

     Interest expense         (1,635     71        (1,493     215   
                                   

Total

      $ 5,145      $ (776   $ 17,660      $ 8,917   
                                   
     Location of Gain/(Loss)
Reclassified from
AOCI into  Income
(Ineffective Portion)
     Amount of Gain/(Loss)
Recognized in Income
on Ineffective Portion
 
            Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
            2010     2009     2010     2009  

Derivatives in cash flow hedging relationships:

           

Commodity derivatives

     Cost of products sold       $ 241      $ (95   $ 346      $ (95

Interest rate derivatives

     Interest expense                                
                                   

Total

      $ 241      $ (95   $ 346      $ (95
                                   

 

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     Location of Gain/(Loss)
Recognized in Income
on Derivatives
    Amount of Gain/(Loss)
Recognized in Income
representing hedge
ineffectiveness and
amount excluded from the
assessment of effectiveness
 
           Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
           2010     2009     2010     2009  

Derivatives in fair value hedging
relationships
(including hedged item):

          

Commodity derivatives

     Cost of products sold      $ 9,968      $ (20,909   $ 9,001      $ (8,411

Interest rate derivatives

     Interest expense                               
                                  

Total

     $ 9,968      $ (20,909   $ 9,001      $ (8,411
                                  
     Location of Gain/(Loss)
Recognized in Income
on Derivatives
    Amount of Gain/(Loss)
Recognized in Income
on Derivatives
 
           Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
           2010     2009     2010     2009  

Derivatives not designated as hedging instruments:

          

Commodity derivatives

     Cost of products sold      $ 9,438      $ 30,346      $ 10,110      $ 87,349   

Interest rate derivatives

    
 
 
Gains (losses) on
non-hedged interest
rate derivatives
  
  
  
    (11,963     (18,241     (11,963     32,327   
                                  

Total

     $ (2,525   $ 12,105      $ (1,853   $ 119,676   
                                  

We recognized $12.5 million of unrealized gains and $13.5 million of unrealized losses on commodity derivatives not in fair value hedging relationships (including the ineffective portion of commodity derivatives in cash flow hedging relationships) for the three months ended September 30, 2010 and 2009, respectively. We recognized $32.8 million and $32.7 million of unrealized losses on commodity derivatives not in fair value hedging relationships (including the ineffective portion of commodity derivatives in cash flow hedging relationships) for the nine months ended September 30, 2010 and 2009, respectively. For the three months ended September 30, 2010 and 2009, we recognized unrealized gains of $8.2 million and unrealized losses of $16.4 million, respectively, on commodity derivatives and related hedged inventory in fair value hedging relationships. For the nine months ended September 30, 2010 and 2009, we recognized unrealized losses of $35.3 million and $3.9 million, respectively, on commodity derivatives and related hedged inventory in fair value hedging relationships.

Credit Risk

We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements, which allow for netting of positive and negative exposure associated with a single counterparty.

Our counterparties consist primarily of financial institutions, major energy companies and local distribution companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Based on our policies, exposures, credit and other reserves, management does not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty performance.

For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our condensed consolidated balance sheet and recognized in net income or other comprehensive income.

 

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15.

RELATED PARTY TRANSACTIONS:

As discussed in Note 8, Regency became a related party on May 26, 2010. Regency provides us with contract compression services. For the three months ended September 30, 2010, we recorded revenue of $0.9 million, cost of products sold of $0.7 million and operating expenses of $0.2 million related to transactions with Regency. For the period from May 26, 2010 to September 30, 2010, we recorded revenue of $0.9 million, costs of products sold of $1.4 million and operating expenses of $0.4 million related to transactions with Regency.

We recorded $2.6 million and $0.1 million from ETE for the provision of various general and administrative services for ETE’s benefit for the three months ended September 30, 2010 and 2009, respectively. We recorded $3.7 million and $0.4 million from ETE related to these services for the nine months ended September 30, 2010 and 2009, respectively.

Enterprise GP Holdings L.P. and its subsidiaries (collectively “Enterprise) are considered to be related parties to us due to equity interests that Enterprise holds in ETE and its general partner. We and Enterprise transport natural gas on each other’s pipelines, share operating expenses on jointly-owned pipelines and ETC OLP sells natural gas to Enterprise. Our propane operations routinely buy and sell product with Enterprise. The following table presents sales to and purchase from Enterprise:

 

     Three Months Ended
September 30,
     Nine Months Ended
September 30,
 
     2010      2009      2010      2009  

Natural Gas Operations:

           

Sales

   $ 126,992       $ 118,272       $ 402,238       $ 283,346   

Purchases

     396         12,958         13,928         29,304   

Propane Operations:

           

Sales

     262         2,815         11,228         14,323   

Purchases

     58,642         44,022         276,821         220,245   

Our propane operations purchase a portion of our propane requirements from Enterprise pursuant to an agreement that was extended until March 2015, and includes an option to extend the agreement for an additional year. As of December 31, 2009, Titan had forward mark-to-market derivatives for approximately 6.1 million gallons of propane at a fair value asset of $3.3 million with Enterprise. All of these forward contracts were settled as of June 30, 2010. In addition, as of September 30, 2010 and December 31, 2009, Titan had forward derivatives accounted for as cash flow hedges of 58.1 million and 20.5 million gallons of propane at a fair value asset of $5.7 million and $8.4 million, respectively, with Enterprise.

The following table summarizes the related party balances on our condensed consolidated balance sheets:

 

     September 30,
2010
     December 31,
2009
 

Accounts receivable from related parties:

     

Enterprise:

     

Natural Gas Operations

   $ 35,175       $ 47,005   

Propane Operations

     407         3,386   

Other

     10,192         6,978   
                 

Total accounts receivable from related parties

   $ 45,774       $ 57,369   
                 

Accounts payable to related parties:

     

Enterprise:

     

Natural Gas Operations

   $ 1,561       $ 3,518   

Propane Operations

     8,209         31,642   

Other

     2,007         3,682   
                 

Total accounts payable to related parties

   $ 11,777       $ 38,842   
                 

The net imbalance payable from Enterprise was $32 thousand and $0.7 million as of September 30, 2010 and December 31, 2009, respectively.

 

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16.

OTHER INFORMATION:

The tables below present additional detail for certain balance sheet captions.

Other Current Assets

Other current assets consisted of the following:

 

     September 30,
2010
     December 31,
2009
 

Deposits paid to vendors

   $ 58,710       $ 79,694   

Prepaid and other

     62,895         68,679   
                 

Total other current assets

   $ 121,605       $ 148,373   
                 

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

 

     September 30,
2010
     December 31,
2009
 

Interest payable

   $ 113,784       $ 136,222   

Customer advances and deposits

     111,374         88,430   

Accrued capital expenditures

     55,013         46,134   

Accrued wages and benefits

     48,582         25,202   

Taxes other than income taxes

     70,507         23,294   

Income taxes payable

     4,607         3,401   

Deferred income taxes

     189           

Other

     87,011         42,485   
                 

Total accrued and other current liabilities

   $ 491,067       $ 365,168   
                 

 

17.

REPORTABLE SEGMENTS:

Our financial statements reflect four reportable segments, which conduct their business exclusively in the United States of America, as follows:

 

   

natural gas operations consisting of:

 

  o

intrastate transportation and storage;

 

  o

interstate transportation; and

 

  o

midstream.

 

   

retail propane and other retail propane related operations.

 

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We evaluate the performance of our operating segments based on operating income, which includes allocated selling, general and administrative expenses. The following tables present the financial information by segment for the following periods:

 

     Three Months Ended
September  30,
    Nine Months Ended
September 30,
 
     2010     2009     2010     2009  

Revenues:

        

Intrastate transportation and storage:

        

Revenues from external customers

   $ 529,507      $ 364,087      $ 1,662,037      $ 1,192,564   

Intersegment revenues

     369,487        102,626        952,336        396,734   
                                
     898,994        466,713        2,614,373        1,589,298   

Interstate transportation – revenues from external customers

     74,659        71,415        213,007        203,349   

Midstream:

        

Revenues from external customers

     458,381        507,721        1,484,211        1,607,497   

Intersegment revenues

     416,703        65,345        945,438        142,969   
                                
     875,084        573,066        2,429,649        1,750,466   

Retail propane and other retail propane related – revenues from external customers

     205,833        184,287        987,114        902,471   

All other:

        

Revenues from external customers

     22,264        2,086        83,962        5,632   

Intersegment revenues

     1,325        372        3,706        372   
                                
     23,589        2,458        87,668        6,004   

Eliminations – against operating expenses

     (84            (252       

Eliminations – against cost of products sold

     (787,431     (168,343     (1,901,228     (540,075
                                

Total revenues

   $ 1,290,644      $ 1,129,596      $ 4,430,331      $ 3,911,513   
                                

Cost of products sold:

        

Intrastate transportation and storage

   $ 660,107      $ 278,868      $ 1,930,798      $ 895,433   

Midstream

     775,769        480,746        2,138,125        1,510,030   

Retail propane and other retail propane related

     109,910        85,028        534,800        393,019   

All other

     19,056        1,849        70,638        4,873   

Eliminations

     (787,431     (168,343     (1,901,228     (540,075
                                

Total cost of products sold

   $ 777,411      $ 678,148      $ 2,773,133      $ 2,263,280   
                                

Depreciation and amortization:

        

Intrastate transportation and storage

   $ 29,340      $ 27,188      $ 87,484      $ 78,080   

Interstate transportation

     12,643        12,521        37,856        36,017   

Midstream

     21,592        18,091        62,209        51,792   

Retail propane and other retail propane related

     20,609        23,031        60,994        63,477   

All other

     1,428        853        4,222        1,095   
                                

Total depreciation and amortization

   $ 85,612      $ 81,684      $ 252,765      $ 230,461   
                                

Operating income (loss):

        

Intrastate transportation and storage

   $ 133,750      $ 109,781      $ 395,772      $ 410,425   

Interstate transportation

     34,576        41,610        98,338        101,755   

Midstream

     52,793        43,414        154,990        96,603   

Retail propane and other retail propane related

     (13,053     (16,550     107,285        152,079   

All other

     (2,601     (3,021     (3,963     (4,803

Selling, general and administrative expenses not allocated to segments

     2,682        2,113        (753     1,361   
                                

Total operating income

   $ 208,147      $ 177,347      $ 751,669      $ 757,420   
                                

 

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     Three Months Ended
September  30,
    Nine Months Ended
September 30,
 
     2010     2009     2010     2009  

Other items not allocated by segment:

        

Interest expense, net of interest capitalized

   $ (101,241   $ (101,503   $ (309,217   $ (284,228

Equity in earnings of affiliates

     595        9,581        10,848        11,751   

Gains (losses) on disposal of assets

     281        (1,088     (198     (1,333

Gains (losses) on non-hedged interest rate derivatives

     (11,963     (18,241     (11,963     32,327   

Allowance for equity funds used during construction

     12,432        30        18,039        18,618   

Impairment of investment in affiliate

                   (52,620       

Other income, net

     1,129        3,433        (3,731     4,400   

Income tax expense (benefit)

     (1,993     2,897        (12,486     (8,594
                                
     (100,760     (104,891     (361,328     (227,059
                                

Net income

   $ 107,387      $ 72,456      $ 390,341      $ 530,361   
                                

 

     As of
September 30,
2010
     As of
December 31,
2009
 

Total assets:

     

Intrastate transportation and storage

   $ 4,787,477       $ 4,901,102   

Interstate transportation

     3,281,738         3,313,837   

Midstream

     1,716,877         1,523,538   

Retail propane and other retail propane related

     1,681,240         1,784,353   

All other

     246,999         212,142   
                 

Total

   $ 11,714,331       $ 11,734,972   
                 
     Nine Months Ended
September  30,
 
     2010      2009  

Additions to property, plant and equipment including acquisitions, net of contributions in aid of construction costs (accrual basis):

     

Intrastate transportation and storage

   $ 72,797       $ 362,816   

Interstate transportation

     743,197         127,927   

Midstream

     269,533         76,408   

Retail propane and other retail propane related

     46,264         45,904   

All other

     8,710         29,404   
                 

Total

   $ 1,140,501       $ 642,459   
                 

 

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

(Tabular dollar amounts are in thousands)

The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 2009 filed with the SEC on February 24, 2010. Our Management’s Discussion and Analysis includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Item 1A. Risk Factors” included in this report and in our Annual Report on Form 10-K for the year ended December 31, 2009.

References to “we,” “us,” “our”, the “Partnership” and “ETP” shall mean Energy Transfer Partners, L.P. and its subsidiaries.

Overview

Our activities are primarily conducted through our operating subsidiaries: La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company (“ETC OLP”); Energy Transfer Interstate Holdings, LLC (“ET Interstate”), the parent company of Transwestern Pipeline Company, LLC (“Transwestern”), ETC Fayetteville Express Pipeline, LLC (“ETC FEP”), and ETC Tiger Pipeline, LLC (“ETC Tiger”); ETC Compression, LLC (“ETC Compression”); Heritage Operating, L.P. (“HOLP”); and Titan Energy Partners, L.P. (“Titan”).

General

Our primary objective is to increase the level of our cash distributions over time by pursuing a business strategy that is currently focused on growing our natural gas midstream and intrastate transportation and storage businesses (including transportation, gathering, compression, treating, processing, storage and marketing) and our propane business through, among other things, pursuing certain construction and expansion opportunities relating to our existing infrastructure and acquiring certain additional businesses or assets. The actual amounts of cash that we will have available for distribution will primarily depend on the amount of cash we generate from operations.

During the past several years, we have been successful in completing several transactions that have been accretive to our Unitholders. We have also made, and are continuing to make, significant investments in internal growth projects, primarily the construction of pipelines, gathering systems and natural gas treating and processing plants, which we believe will provide additional cash flow to our Unitholders for years to come.

Our principal operations are conducted in the following segments:

 

 

Intrastate transportation and storage — Revenue is principally generated from fees charged to customers to reserve firm capacity on or move gas through our pipelines on an interruptible basis. Our interruptible or short-term business is generally impacted by basis differentials between delivery points on our system and the price of natural gas. The basis differentials that primarily impact our interruptible business are receipt points between West Texas to East Texas. When basis differentials widen, our interruptible volumes and fees generally increase. The fee structure normally consists of a monetary fee and/or fuel retention. Excess fuel retained after consumption is sold at market prices. In addition to transport fees, our HPL System generates revenue primarily from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies.

We generate fee-based revenue from our natural gas storage facilities by contracting with third parties for their use of our storage capacity. From time to time, we utilize any excess storage capacity to inject and hold natural gas in our Bammel storage facility to take advantage of contango markets, a term used to describe a pricing environment when the price of natural gas is higher in the future than the current spot price. We use financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, we lock in a margin by purchasing gas in the spot market and entering into a financial derivative to lock in the forward sale price. If we designate the related financial derivative as a fair value hedge for accounting purposes, we value the hedged natural gas inventory at current spot market prices whereas the financial derivative is valued using forward natural gas prices. As a result of fair value hedge accounting, we have elected to exclude the spot forward premium from the measurement of effectiveness and changes in the spread between forward natural gas prices and spot

 

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market prices result in unrealized gains or losses until the underlying physical gas is withdrawn and the related financial derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. If the spread narrows between spot and forward prices, we will record unrealized gains or lower unrealized losses. If the spread widens, we will record unrealized losses or lower unrealized gains.

We also use financial derivatives to hedge prices on a portion of natural gas volumes retained as fees in our intrastate transportation and storage segment. For certain contracts that qualify for hedge accounting, we designate them as cash flow hedges of the forecasted sale of gas. The change in value, to the extent the contracts are effective, remains in accumulated other comprehensive income until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.

In addition, we use financial derivatives to lock in price differentials between market hubs connected to our assets on a portion of our intrastate transportation system’s open capacity. Gains and losses on these financial derivatives are dependent on price differentials at market locations, primarily points in West Texas and East Texas. We account for these derivatives using mark-to-market accounting, and the change in the value of these derivatives is recorded in earnings.

 

   

Interstate transportation — Revenue is primarily generated by fees earned from natural gas transportation services and operational gas sales.

 

   

Midstream — Revenue is principally dependent upon the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipelines as well as the level of natural gas and NGL prices.

In addition to fee-based contracts for gathering, treating and processing, we also have percent of proceeds and keep-whole contracts, which are subject to market pricing. For percent of proceeds contracts (which accounted for approximately 11% of total processed volumes for the nine month periods ended September 30, 2010 and 2009, respectively), we retain a portion of the natural gas and NGLs processed as a fee. When natural gas and NGL pricing increase, the value of the portion we retain as a fee increases. Conversely, when prices of natural gas and NGL’s decrease, so does the value of the portion we retain as a fee. For keep-whole contracts (which accounted for approximately 32% and 26% of total processed volumes for the nine month periods ended September 30, 2010 and 2009, respectively), we retain the difference between the price of NGLs and the cost of the gas to process it. In periods of high NGL prices relative to natural gas, our margins increase. During periods of low NGL prices relative to natural gas, our margins decrease or could be negative. In the event it is uneconomical to process this gas, we have the ability to bypass our processing plants to avoid negative margins that may occur from processing NGLs.

We conduct marketing operations in which we market the natural gas that flows through our gathering assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other suppliers and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices of natural gas, less the costs of transportation.

 

   

Retail propane and other retail propane related operations — Revenue is principally generated from the sale of propane and propane-related products and services.

 

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Results of Operations

Consolidated Results

 

     Three Months Ended
September 30,
          Nine Months Ended
September 30,
       
     2010     2009     Change     2010     2009     Change  

Revenues

   $ 1,290,644      $ 1,129,596      $ 161,048      $ 4,430,331      $ 3,911,513      $ 518,818   

Cost of products sold

     777,411        678,148        99,263        2,773,133        2,263,280        509,853   
                                                

Gross margin

     513,233        451,448        61,785        1,657,198        1,648,233        8,965   

Operating expenses

     174,740        158,883        15,857        515,021        517,337        (2,316

Depreciation and amortization

     85,612        81,684        3,928        252,765        230,461        22,304   

Selling, general and administrative

     44,734        33,534        11,200        137,743        143,015        (5,272
                                                

Operating income

     208,147        177,347        30,800        751,669        757,420        (5,751

Interest expense, net of interest capitalized

     (101,241     (101,503     262        (309,217     (284,228     (24,989

Equity in earnings of affiliates

     595        9,581        (8,986     10,848        11,751        (903

Gains (losses) on disposal of assets

     281        (1,088     1,369        (198     (1,333     1,135   

Gains (losses) on non-hedged interest rate derivatives

     (11,963     (18,241     6,278        (11,963     32,327        (44,290

Allowance for equity funds used during construction

     12,432        30        12,402        18,039        18,618        (579

Impairment of investment in affiliate

                          (52,620            (52,620

Other, net

     1,129        3,433        (2,304     (3,731     4,400        (8,131

Income tax (expense) benefit

     (1,993     2,897        (4,890     (12,486     (8,594     (3,892
                                                

Net income

   $ 107,387      $ 72,456      $ 34,931      $ 390,341      $ 530,361      $ (140,020
                                                

See the detailed discussion of revenues, costs of products sold, gross margin, operating expenses, and depreciation and amortization by operating segment below.

Interest Expense. Interest expense increased $25.0 million for the nine months ended September 30, 2010 compared to the same period in the previous year principally due to our issuances of $1.0 billion in senior notes in April 2009 and Transwestern’s issuance of $350.0 million of senior notes in December 2009. Interest expense is presented net of capitalized interest and allowance for debt funds used during construction, which totaled $7.1 million and $5.7 million for the three months ended September 30, 2010 and 2009, respectively, and $11.0 million and $15.5 million for the nine months ended September 30, 2010 and 2009, respectively.

Equity in Earnings of Affiliates. Equity in earnings of affiliates decreased $9.0 million for the three months ended September 30, 2010 compared to the same period in the previous year primarily due to our transfer of substantially all of our interest in MEP to ETE on May 26, 2010. For the nine months ended September 30, 2010, the impact of the MEP transfer is offset by increased earnings from MEP during the period prior to May 26, 2010 as a result of placing the Midcontinent Express pipeline into service in 2009.

Gains (Losses) on Non-Hedged Interest Rate Derivatives. For the three months ended September 30, 2010 and 2009, the losses on non-hedged interest rate derivatives reflect declines in the index rate during the periods. In addition, the losses on non-hedged interest rate derivatives were lower for the three months ended September 30, 2010 compared to the same period in the prior year due to a decrease in the notional amount of interest rate swaps outstanding during the period. As of September 30, 2010 and 2009, we had $400.0 million and $500.0 million, respectively, of total notional amount of interest rate swaps outstanding that were not designated as hedges for accounting purposes.

We did not have any non-hedged interest rate swaps outstanding during the first six months of 2010; therefore, the losses on non-hedged interest rate derivatives for the nine months ended September 30, 2010 reflect the losses recognized during the last three months of that period. For the nine months ended September 30, 2009, the gains on non-hedged interest rate swaps resulted from an increase in the index rate during the period.

 

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Allowance for Equity Funds Used During Construction. Allowance for equity funds used during construction (AFUDC) increased $12.4 million for the three months ended September 30, 2010, primarily due to construction on the Tiger pipeline. AFUDC on equity amounts recorded in property, plant and equipment (which excludes AFUDC gross-up) were $12.4 million and $20 thousand for the three months ended September 30, 2010 and 2009, respectively, and $17.9 million and $11.4 million for the nine months ended September 30, 2010 and 2009, respectively.

Impairment of Investment in Affiliate. In conjunction with the transfer of our interest in MEP, we recorded a non-cash charge of approximately $52.6 million during the nine months ended September 30, 2010 to reduce the carrying value of our interest to its estimated fair value.

Segment Operating Results

We evaluate segment performance based on operating income (either in total or by individual segment), which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments.

Detailed descriptions of our business and segments are included in our Annual Report on Form 10-K for the year ended December 31, 2009 filed with the SEC on February 24, 2010.

Operating income (loss) by segment is as follows:

 

     Three Months Ended
September 30,
          Nine Months Ended
September 30,
       
     2010     2009     Change     2010     2009     Change  

Intrastate transportation and storage

   $ 133,750      $ 109,781      $ 23,969      $ 395,772      $ 410,425      $ (14,653

Interstate transportation

     34,576        41,610        (7,034     98,338        101,755        (3,417

Midstream

     52,793        43,414        9,379        154,990        96,603        58,387   

Retail propane and other retail propane related

     (13,053     (16,550     3,497        107,285        152,079        (44,794

All other

     (2,601     (3,021     420        (3,963     (4,803     840   

Selling, general and administrative expenses not allocated to segments

     2,682        2,113        569        (753     1,361        (2,114
                                                

Operating income

   $ 208,147      $ 177,347      $ 30,800      $ 751,669      $ 757,420      $ (5,751
                                                

Selling, General and Administrative Expenses Not Allocated to Segments. Selling, general and administrative expenses are allocated monthly to the Operating Companies using the Modified Massachusetts Formula Calculation (“MMFC”). The expenses subject to allocation are based on estimated amounts and take into consideration our actual expenses from previous months and known trends. The difference between the allocation and actual costs is adjusted in the following month, which results in over or under allocation of these costs due to timing differences.

 

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Intrastate Transportation and Storage

 

     Three Months Ended
September 30,
            Nine Months Ended
September 30,
        
     2010      2009      Change      2010      2009      Change  

Natural gas MMBtu/d – transported

     13,250,836         11,111,011         2,139,825         12,132,099         12,769,022         (636,923

Natural gas MMBtu/d – sold

     1,812,938         886,463         926,475         1,642,910         879,861         763,049   

Revenues

   $ 898,994       $ 466,713       $ 432,281       $ 2,614,373       $ 1,589,298       $ 1,025,075   

Cost of products sold

     660,107         278,868         381,239         1,930,798         895,433         1,035,365   
                                                     

Gross margin

     238,887         187,845         51,042         683,575         693,865         (10,290

Operating expenses

     56,167         45,053         11,114         145,497         155,461         (9,964

Depreciation and amortization

     29,340         27,188         2,152         87,484