**UNITED
      STATES SECURITIES AND EXCHANGE COMMISSION**


**WASHINGTON,
      D.C.  20549**





**FORM
      10-Q**





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





**For
      the quarterly period ended September 30, 2007**








OR





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


****


**For
      the transition period from _______________ to
      _______________**





*Commission
                file number:*      01-32665**BOARDWALK
                PIPELINE PARTNERS, LP***(Exact
                name of registrant as specified in its charter)***DELAWARE***(State
                or other jurisdiction of incorporation or
                organization)***20-3265614***(I.R.S.
                Employer Identification No.)***3800
                Frederica Street, Owensboro, Kentucky 42301**
              **(270)
                926-8686***(Address
                and Telephone Number of Registrant’s Principal Executive
                Office)*








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    Noo








Indicate
      by check mark whether the registrant is a large accelerated filer, an
      accelerated filer, or a non-accelerated filer.


See
      definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of
      the Exchange Act. (check one:)





Large
      accelerated filer  x                                                                Accelerated
      filer  o                                                      Non-accelerated
      filer  o





Indicate
      by check mark whether the registrant is a shell company (as defined in Rule
      12b-2 of the Exchange Act).  Yes  ̈  No x





As
      of
      October 19, 2007, the registrant had 83,156,122 common units outstanding and
      33,093,878 subordinated units outstanding.





1


**TABLE
      OF CONTENTS**





**FORM
      10-Q**





**SEPTEMBER
      30, 2007**





**BOARDWALK
      PIPELINE PARTNERS, LP**










PART
      1 – FINANCIAL INFORMATON




3


3


5


6


7


8


9


20


28


30




PART
      II - OTHER INFORMATION




31


31


34


35




























2


**PART
      I – FINANCIAL INFORMATION**





**Item
      1.  Financial Statements**








**BOARDWALK
      PIPELINE PARTNERS, LP**





**CONDENSED
      CONSOLIDATED BALANCE SHEETS**


**(Thousands
      of Dollars)**


**(Unaudited)**








**ASSETS**
            
            **September
                30, 2007**
            
            
            **December
                31, 2006**Current
                Assets:Cash
                and cash equivalents
            
            $
            45,161
            
            
            $
            399,032Short-term
                investments
            
            
            540,000
            
            
            
            -Receivables:Trade,
                net
            
            
            40,543
            
            
            
            54,082Other
            
            
            12,349
            
            
            
            12,759Gas
                Receivables:Transportation
                and exchange
            
            
            8,345
            
            
            
            9,115Storage
            
            
            653
            
            
            
            11,704Inventories
            
            
            14,315
            
            
            
            14,110Costs
                recoverable from customers
            
            
            6,313
            
            
            
            11,236Gas
                stored underground
            
            
            14,252
            
            
            
            14,001Prepaid
                expenses and other current assets
            
            
            13,773
            
            
            
            22,117Total
                current assets
            
            
            695,704
            
            
            
            548,156Property,
                Plant and Equipment:Natural
                gas transmission plant
            
            
            2,752,860
            
            
            
            1,997,922Other
                natural gas plant
            
            
            233,031
            
            
            
            213,9262,985,891
            
            
            
            2,211,848Less—Accumulated
                depreciation and amortization
            
            
            243,990
            
            
            
            187,412Property,
                plant and equipment, net
            
            
            2,741,901
            
            
            
            2,024,436Other
                Assets:Goodwill
            
            
            163,474
            
            
            
            163,474Gas
                stored underground
            
            
            175,304
            
            
            
            161,537Costs
                recoverable from customers
            
            
            15,210
            
            
            
            19,767Other
            
            
            31,582
            
            
            
            33,929Total
                other assets
            
            
            385,570
            
            
            
            378,707Total
                Assets
            
            $
            3,823,175
            
            
            $
            2,951,299








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





3


**BOARDWALK
      PIPELINE PARTNERS, LP**





**CONDENSED
      CONSOLIDATED BALANCE SHEETS**


**(Thousands
      of Dollars, except number of units)**


**(Unaudited)**





**LIABILITIES
                AND PARTNERS’ CAPITAL**
            
            **September
                30, 2007**
            
            
            **December
                31, 2006**Current
                Liabilities:Payables:Trade
            
            $
            139,202
            
            
            $
            56,604Affiliates
            
            
            1,127
            
            
            
            3,014Other
            
            
            14,336
            
            
            
            14,459Gas
                Payables:Transportation
                and exchange
            
            
            11,797
            
            
            
            15,485Storage
            
            
            40,966
            
            
            
            42,127Other
                accrued taxes
            
            
            25,659
            
            
            
            16,082Accrued
                interest
            
            
            22,862
            
            
            
            19,376Accrued
                payroll and employee benefits
            
            
            16,475
            
            
            
            18,198Deferred
                income
            
            
            9,809
            
            
            
            22,147Other
                current liabilities
            
            
            30,221
            
            
            
            20,926Total
                current liabilities
            
            
            312,454
            
            
            
            228,418Long
                –Term Debt
            
            
            1,847,534
            
            
            
            1,350,920Other
                Liabilities and Deferred Credits:Pension
                and postretirement benefits
            
            
            17,658
            
            
            
            15,761Asset
                retirement obligation
            
            
            14,751
            
            
            
            14,307Provision
                for other asset retirement
            
            
            41,648
            
            
            
            39,644Other
            
            
            29,992
            
            
            
            29,742Total
                other liabilities and deferred credits
            
            
            104,049
            
            
            
            99,454Commitments
                and ContingenciesPartners’
                Capital:Common
                units - 83,156,122 units and 75,156,122 units issued and outstanding
                as of
                September 30, 2007 and December 31, 2006
            
            
            1,232,734
            
            
            
            941,792Subordinated
                units - 33,093,878 units issued and outstanding as of September 30,
                2007
                and December 31, 2006
            
            
            287,538
            
            
            
            285,543General
                partner
            
            
            28,122
            
            
            
            22,060Accumulated
                other comprehensive income
            
            
            10,744
            
            
            
            23,112Total
                partners’ capital
            
            
            1,559,138
            
            
            
            1,272,507Total
                Liabilities and Partners’ Capital
            
            $
            3,823,175
            
            
            $
            2,951,299








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


4


**BOARDWALK
      PIPELINE PARTNERS, LP**





**CONDENSED
      CONSOLIDATED STATEMENTS OF INCOME**


**(Thousands
      of Dollars, except number of units and per unit amounts)**


**(Unaudited)**





**For
                the**
              **Three
                Months Ended**
              **September
                30,**
            
            
            **For
                the**
              **Nine
                Months Ended**
              **September
                30,****2007**
            
            
            **2006**
            
            
            **2007**
            
            
            **2006**Operating
                Revenues:Gas
                transportation
            
            $
            111,572
            
            
            $
            108,195
            
            
            $
            379,494
            
            
            $
            364,597Parking
                and lending
            
            
            6,845
            
            
            
            9,099
            
            
            
            38,024
            
            
            
            32,030Gas
                storage
            
            
            10,256
            
            
            
            8,321
            
            
            
            28,455
            
            
            
            25,136Other
            
            
            6,059
            
            
            
            7,430
            
            
            
            27,413
            
            
            
            14,390Total
                operating revenues
            
            
            134,732
            
            
            
            133,045
            
            
            
            473,386
            
            
            
            436,153Operating
                Costs and Expenses:Operation
                and maintenance
            
            
            45,863
            
            
            
            39,740
            
            
            
            128,317
            
            
            
            114,901Administrative
                and general
            
            
            22,103
            
            
            
            23,878
            
            
            
            70,011
            
            
            
            74,111Depreciation
                and amortization
            
            
            20,510
            
            
            
            18,888
            
            
            
            60,644
            
            
            
            56,298Taxes
                other than income taxes
            
            
            6,588
            
            
            
            6,592
            
            
            
            21,757
            
            
            
            18,607Asset
                impairment
            
            
            -
            
            
            
            -
            
            
            
            14,698
            
            
            
            -Net
                (gain) on disposal of operating assets and related
                contracts
            
            
            (8,879
            )
            
            
            (826
            )
            
            
            (7,241
            )
            
            
            (3,032
            )Total
                operating costs and expenses
            
            
            86,185
            
            
            
            88,272
            
            
            
            288,186
            
            
            
            260,885Operating
                income
            
            
            48,547
            
            
            
            44,773
            
            
            
            185,200
            
            
            
            175,268Other
                Deductions (Income):Interest
                expense
            
            
            14,760
            
            
            
            14,977
            
            
            
            46,106
            
            
            
            45,822Interest
                income
            
            
            (5,741
            )
            
            
            (553
            )
            
            
            (16,283
            )
            
            
            (1,796
            )Interest
                income from affiliates, net
            
            
            (16
            )
            
            
            (10
            )
            
            
            (36
            )
            
            
            (16
            )Miscellaneous
                other deductions (income), net
            
            
            (575
            )
            
            
            (406
            )
            
            
            (751
            )
            
            
            (1,383
            )Total
                other deductions
            
            
            8,428
            
            
            
            14,008
            
            
            
            29,036
            
            
            
            42,627Income
                before income taxes
            
            
            40,119
            
            
            
            30,765
            
            
            
            156,164
            
            
            
            132,641Income
                taxes
            
            
            140
            
            
            
            118
            
            
            
            503
            
            
            
            364Net
                income
            
            $
            39,979
            
            
            $
            30,647
            
            
            $
            155,661
            
            
            $
            132,277








**Calculation
                of limited partners’ interest in Net income:**Net
                income
            
            $
            39,979
            
            
            $
            30,647
            
            
            $
            155,661
            
            
            $
            132,277Less
                general partner’s interest in Net income
            
            
            1,511
            
            
            
            612
            
            
            
            4,521
            
            
            
            2,645Limited
                partners’ interest in Net income
            
            $
            38,468
            
            
            $
            30,035
            
            
            $
            151,140
            
            
            $
            129,632Basic
                and diluted net income per limited partner unit:Common
                units
            
            $
            0.35
            
            
            $
            0.35
            
            
            $
            1.32
            
            
            $
            1.27Subordinated
                units
            
            $
            0.30
            
            
            $
            0.19
            
            
            $
            1.32
            
            
            $
            1.27Cash
                distribution to common and subordinated unitholders
            
            $
            0.44
            
            
            $
            0.38
            
            
            $
            1.29
            
            
            $
            0.92Weighted-average
                number of limited partner units outstanding:Common
                units
            
            
            83,156,122
            
            
            
            68,256,122
            
            
            
            80,773,769
            
            
            
            68,256,122Subordinated
                units
            
            
            33,093,878
            
            
            
            33,093,878
            
            
            
            33,093,878
            
            
            
            33,093,878








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


5


**BOARDWALK
      PIPELINE PARTNERS, LP**





**CONDENSED
      CONSOLIDATED STATEMENTS OF CASH FLOWS**


**(Thousands
      of Dollars)**


**(Unaudited)**





**For
                the**
              **Nine
                Months Ended**
              **September
                30,****2007**
            
            
            **2006**OPERATING
                ACTIVITIES:Net
                income
            
            $
            155,661
            
            
            $
            132,277Adjustments
                to reconcile to cash provided by operations:Depreciation
                and amortization
            
            
            60,644
            
            
            
            56,298Amortization
                of deferred costs
            
            
            1,161
            
            
            
            1,746Amortization
                of acquired executory contracts
            
            
            (994
            )
            
            
            (3,236
            )Asset
                impairment
            
            
            14,698
            
            
            
            -(Gain)
                loss on disposal of operating assets and related contracts
            
            
            (7,241
            )
            
            
            (3,032
            )Changes
                in operating assets and liabilities:Trade
                and other receivables
            
            
            16,376
            
            
            
            13,637Gas
                receivables and storage assets
            
            
            (2,195
            )
            
            
            24,417Costs
                recoverable from customers
            
            
            4,471
            
            
            
            2,584Other
                assets
            
            
            (14,120
            )
            
            
            (12,104
            )Trade
                and other payables
            
            
            (15,325
            )
            
            
            (369
            )Gas
                payables
            
            
            (11,087
            )
            
            
            (54,079
            )Accrued
                liabilities
            
            
            11,340
            
            
            
            (5,304
            )Other
                liabilities
            
            
            15,348
            
            
            
            31,949Net
                cash provided by operating activities
            
            
            228,737
            
            
            
            184,784INVESTING
                ACTIVITIES:Capital
                expenditures
            
            
            (688,155
            )
            
            
            (124,175
            )Proceeds
                from sale of operating assets
            
            
            5,025
            
            
            
            3,967Proceeds
                from insurance reimbursements and other recoveries
            
            
            1,726
            
            
            
            4,960Advances
                to affiliates, net
            
            
            187
            
            
            
            (660
            )Purchase
                of short-term investments
            
            
            (540,000
            )
            
            
            -Net
                cash used in investing activities
            
            
            (1,221,217
            )
            
            
            (115,908
            )FINANCING
                ACTIVITIES:Payments
                of notes payable
            
            
            -
            
            
            
            (42,100
            )Proceeds
                from long-term debt
            
            
            495,271
            
            
            
            60,000Distributions
            
            
            (150,479
            )
            
            
            (95,021
            )Proceeds
                from sale of common units, net of related transaction
                costs
            
            
            287,858
            
            
            
            13Capital
                contribution from general partner
            
            
            5,959
            
            
            
            -Net
                cash provided by (used in) financing activities
            
            
            638,609
            
            
            
            (77,108
            )(Decrease)
                in cash and cash equivalents
            
            
            (353,871
            )
            
            
            (8,232
            )Cash
                and cash equivalents at beginning of period
            
            
            399,032
            
            
            
            65,792Cash
                and cash equivalents at end of period
            
            $
            45,161
            
            
            $
            57,560





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








6


**BOARDWALK
      PIPELINE PARTNERS, LP**





**CONDENSED
      CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL**


**(Thousands
      of Dollars, except units)**


**(Unaudited)**





**Common**
              **Units**
            
            
            **Subordinated
                Units**
            
            
            **General
                Partner**
            
            
            **Accumulated Other
                Comprehensive (Loss) Income**
            
            
            **Total
                Partners’ Capital****Balance,
                January 1, 2006**
            
            $
            705,609
            
            
            $
            266,578
            
            
            $
            16,661
            
            
            $
            (174
            )
            
            $
            988,674Add
                (deduct):Net
                income
            
            
            87,303
            
            
            
            42,329
            
            
            
            2,645
            
            
            
            -
            
            
            
            132,277Distributions
                paid
            
            
            (62,714
            )
            
            
            (30,407
            )
            
            
            (1,900
            )
            
            
            -
            
            
            
            (95,021
            )Other
                comprehensive income
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            3,602
            
            
            
            3,602Transaction
                costs related to sale of common units
            
            
            13
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            13**Balance,
                September 30, 2006**
            
            $
            730,211
            
            
            $
            278,500
            
            
            $
            17,406
            
            
            $
            3,428
            
            
            $
            1,029,545













**Balance,
                January 1, 2007**
            
            $
            941,792
            
            
            $
            285,543
            
            
            $
            22,060
            
            
            $
            23,112
            
            
            $
            1,272,507Add
                (deduct):Net
                income
            
            
            106,620
            
            
            
            44,520
            
            
            
            4,521
            
            
            
            -
            
            
            
            155,661Distributions
                paid
            
            
            (103,536
            )
            
            
            (42,525
            )
            
            
            (4,418
            )
            
            
            -
            
            
            
            (150,479
            )Other
                comprehensive (loss)
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (12,368
            )
            
            
            (12,368
            )Sale
                of common units, net of related transaction costs (8,000,000
                units)
            
            
            287,858
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            287,858Capital
                contribution from general partner
            
            
            -
            
            
            
            -
            
            
            
            5,959
            
            
            
            -
            
            
            
            5,959**Balance,
                September 30, 2007**
            
            $
            1,232,734
            
            
            $
            287,538
            
            
            $
            28,122
            
            
            $
            10,744
            
            
            $
            1,559,138





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








7


**BOARDWALK
      PIPELINE PARTNERS, LP**





**CONDENSED
      CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME**


**(Thousands
      of Dollars)**


**(Unaudited)**








**For
                the**
              **Three
                Months Ended**
              **September
                30,**
            
            
            **For
                the**
              **Nine
                Months Ended**
              **September
                30,****2007**
            
            
            **2006**
            
            
            **2007**
            
            
            **2006**Net
                income
            
            $
            39,979
            
            
            $
            30,647
            
            
            $
            155,661
            
            
            $
            132,277Other
                comprehensive income:(Loss)
                gain on cash flow hedges
            
            
            (5,765
            )
            
            
            1,328
            
            
            
            (4,869
            )
            
            
            11,736Reclassification
                adjustment transferred to Net income
            
            
            (2,889
            )
            
            
            (2,540
            )
            
            
            (7,499
            )
            
            
            (8,134
            )Total
                comprehensive income
            
            $
            31,325
            
            
            $
            29,435
            
            
            $
            143,293
            
            
            $
            135,879





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





8





**BOARDWALK
      PIPELINE PARTNERS, LP**





**NOTES
      TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS**





**(Unaudited)**








**Note
      1:  Basis of Presentation**





Boardwalk
      Pipeline Partners, LP (the
      Partnership) is a Delaware limited partnership formed to own and operate the
      business conducted by Boardwalk Pipelines, LP (Boardwalk Pipelines) and its
      subsidiaries, Gulf South Pipeline Company, LP (Gulf South) and Texas Gas
      Transmission, LLC (Texas Gas) (together, the operating subsidiaries). The
      Partnership is a 74.8%-owned subsidiary of Boardwalk Pipelines Holding Corp.
      (BPHC), which is wholly owned by Loews Corporation (Loews).





The
      accompanying unaudited condensed
      consolidated financial statements of the Partnership were prepared pursuant
      to
      the rules and regulations of the Securities and Exchange Commission. Certain
      information and footnote disclosures normally included in financial statements
      prepared in accordance with accounting principles generally accepted in the
      United States of America have been condensed or omitted pursuant to such rules
      and regulations. In the opinion of management, the accompanying condensed
      consolidated financial statements reflect all adjustments (consisting of only
      normal recurring accruals) necessary to present fairly the financial position
      as
      of September 30, 2007 and December 31, 2006, and the results of operations
      for
      the three and nine months ended September 30, 2007 and 2006 and changes in
      cash flow for the nine months ended September 30, 2007 and
      2006.  Reference is made to the Notes to Consolidated Financial
      Statements in the 2006 Annual Report on Form 10-K, which should be read in
      conjunction with these unaudited condensed consolidated financial statements.
      The accounting policies described in Note 2 to the Consolidated Financial
      Statements included in such Annual Report on Form 10-K are the same used in
      preparing the accompanying unaudited condensed consolidated financial
      statements.





Net
      income for interim periods may not necessarily be indicative of results for
      the
      calendar year. All intercompany items have been eliminated in consolidation.
      Certain reclassifications have been made to the 2006 financial statements to
      conform to the 2007 presentation, primarily related to individual amounts and
      captions within the Operating Activities section of the Condensed Consolidated
      Statements of Cash Flows.








**Note
      2:  Gas in Storage and Gas Receivables/Payables**





Gas
      receivables and payables reflect
      amounts of customer-owned gas at the Texas Gas facilities. Consistent with
      the
      method of storage accounting elected by Texas Gas and the risk-of-loss
      provisions included in its tariff, Texas Gas reflects an equal and offsetting
      receivable and payable for customer-owned gas in its facilities for storage
      and
      related services. The gas payables amount is reflected in Gas Payables on the
      Condensed Consolidated Balance Sheets and is valued at a historical cost of
      gas
      of $41.8 million and $45.7 million at September 30, 2007 and December 31, 2006.
      Due to the method of storage accounting elected by Gulf South, the Partnership
      does not reflect volumes held by Gulf South on behalf of others on its Condensed
      Consolidated Balance Sheets. As of September 30, 2007 and December 31, 2006,
      Gulf South held 53.1 trillion British thermal units (TBtu) and 61.0 TBtu of
      gas
      owned by shippers.  Gulf South loaned 0.6 TBtu of gas to shippers as
      of September 30, 2007.  No gas was loaned by Gulf South to shippers as
      of December 31, 2006.








**Note
      3: Derivative Financial Instruments**





Subsidiaries
      of the Partnership use
      futures, swaps, and option contracts (collectively, derivatives) to hedge
      exposure to various risks, including natural gas commodity price risk and
      interest rate risk.  These hedge contracts are reported at fair value
      in accordance with Statement of Financial Accounting Standards (SFAS) No. 133,
      *Accounting for Derivative Instruments and Hedging Activities,*as
      amended.





Certain
      volumes of gas stored underground are available for sale and subject to
      commodity price risk. At September 30, 2007 and December 31, 2006, approximately
      $14.3 million and $14.0 million of gas stored underground at the Gulf South
      facilities, which the Partnership owns and carries as current Gas stored
      underground, is exposed to commodity price risk. The Partnership utilizes
      derivatives to hedge certain exposures to market price fluctuations on the
      anticipated operational sales of gas.





9


As
      a
      result of the approval of Phase II of the Western Kentucky storage expansion
      project, approximately 4.8 billion cubic feet (Bcf) of gas stored underground
      with a book value of $11.3 million became available for sale. Approximately
      3.0
      Bcf of this gas is subject to forward sales agreements under which the ultimate
      sales price was determined in March 2007, based on the price of New York
      Mercantile Exchange natural gas futures.  The Partnership entered into
      derivatives to hedge the price exposure related to the storage
      gas.  The derivatives associated with the volumes subject to forward
      sales agreements were designated as cash flow hedges during February 2007,
      concurrent with the designation of the forward sales agreements as normal sales
      and were settled in March 2007 when the sales price was
      determined.  Prior to the designation, these derivatives were marked
      to fair value through earnings along with the related forward sales agreements,
      resulting in a loss of $0.1 million in the first quarter
      2007.  The derivatives related to the remaining 1.8 Bcf of storage gas
      were not designated as cash flow hedges in accordance with SFAS No. 133 and
      have been marked to fair value through earnings.  In the third quarter
      2007, approximately 0.9 Bcf of this gas was sold and the related derivatives
      were settled resulting in a gain of $4.4 million.  The gain is
      included in Net (gain) loss on disposal of operating assets and related
      contracts on the Condensed Consolidated Statements of Income.





In
      the
      second quarter 2007, the Partnership entered into natural gas price swaps to
      hedge exposure to prices associated with the purchase of 2.1 Bcf of natural
      gas
      to be used for line pack for the Partnership’s Gulf Crossing expansion project
      and the Southeast expansion project, approximately 1.3 Bcf of which remained
      outstanding at September 30, 2007.  The derivatives were not
      designated as hedges in accordance with SFAS No. 133 and were marked to fair
      value through earnings resulting in a loss of $0.4 and $1.1 million for the
      three and nine months ended September 30, 2007.





In
      August
      2007, the Partnership entered into a Treasury rate lock for a notional amount
      of
      $150.0 million of principal to hedge the risk attributable to changes in the
      risk-free component of forward 10-year interest rates through February 1,
      2008.  The reference rate on the rate lock is 4.74%. Under the terms
      of the rate lock, the counterparty would pay the Partnership a settlement amount
      if the 10-year Treasury rate is greater than the reference rate on February
      1,
      2008. Conversely, the Partnership would pay the counterparty a settlement amount
      if the 10-year Treasury rate is less than the reference rate. The Treasury
      rate
      lock was designated as a cash flow hedge in accordance with SFAS No.
      133.  As of September 30, 2007, the Partnership recorded a payable of
      $1.6 million and a corresponding amount in Accumulated other comprehensive
      income for the fair value of the rate lock.





In
      August
      2006, the Partnership entered into Treasury rate locks with two counterparties
      each for a notional amount of $100.0 million of principal to hedge the risk
      attributable to changes in the risk-free component of forward 10-year interest
      rates through August 1, 2007. The reference rates on the rate locks were 5.00%
      and 4.96%.  The rate locks were designated as cash flow hedges in
      accordance with SFAS No. 133.  In August 2007, the rate locks were
      settled resulting in payments to the counterparties of approximately $3.9
      million.  The effective amount of the hedge of approximately $3.4
      million, which was recorded in Accumulated other comprehensive income, will
      be
      amortized to interest expense over the 10-year term of the related notes which
      were issued in August 2007.





With
      the
      exception of the derivatives related to storage gas volumes and line pack gas
      purchases referred to above, the derivatives related to the sale or purchase
      of
      natural gas, cash for fuel reimbursement and debt issuance generally qualify
      for
      cash flow hedge accounting under SFAS No. 133 and are designated as such. The
      effective component of related unrealized gains and losses resulting from
      changes in fair values of the derivatives contracts designated as cash flow
      hedges are deferred as a component of Accumulated other comprehensive
      income.  The deferred gains and losses are recognized in the Condensed
      Consolidated Statements of Income when the anticipated transactions affect
      earnings. Generally, for gas sales and cash for fuel reimbursement, any
      gains and losses on the related derivatives would be recognized in Operating
      Revenues. For the sale of gas related to the Western Kentucky storage
      expansion project, any gains and losses on the related derivatives would be
      recognized in Net (gain) on disposal of operating assets and related
      contracts.  Any gains and losses on the derivatives related to the
      line pack gas purchases would be recognized in Miscellaneous other income,
      net.





The
      fair
      values of derivatives existing as of September 30, 2007 and December 31, 2006,
      were included in the following captions in the Condensed Consolidated Balance
      Sheets (in millions):





**September
                30, 2007**
            
            
            **December
                31, 2006**Prepaid
                expenses and other current assets
            
            $
            1.7
            
            
            $
            13.7Other
                Assets - Other
            
            
            0.2
            
            
            
            -Other
                current liabilities
            
            
            1.9
            
            
            
            5.1Other
                Liabilities and Deferred Credits - Other
            
            
            1.0
            
            
            
            -Accumulated
                other comprehensive income
            
            
            (2.5
            )
            
            
            8.3





10


The
      changes in fair values of the
      derivatives designated as cash flow hedges are expected to, and do, have a
      high
      correlation to changes in value of the anticipated transactions. Each reporting
      period the Partnership measures the effectiveness of the cash flow hedge
      contracts.  To the extent the changes in the fair values of the hedge
      contracts do not effectively offset the changes in the estimated cash flows
      of
      the anticipated transactions, the ineffective portion of the hedge contracts
      is
      currently recognized in earnings. If the anticipated transactions are deemed
      no
      longer probable to occur, hedge accounting would be terminated and changes
      in
      the fair values of the associated derivative financial instruments would be
      recognized currently in earnings.  Ineffectiveness recorded during the
      three and nine month periods ended September 30, 2007 increased Net
      income by $0.5 million and $0.9 million. The Partnership did not
      record any ineffectiveness during the three and nine month periods ending
      September 30, 2006. The Partnership did not discontinue any cash flow hedges
      during the three and nine months ended September 30, 2007 and 2006.








**Note
      4:  Income Taxes**





The
      Partnership is not a taxable entity
      for federal income tax purposes.  As such, it does not directly pay
      federal income tax.  The Partnership’s taxable income or loss, which
      may vary substantially from the net income or loss reported in the Condensed
      Consolidated Statements of Income, is includable in the federal income tax
      returns of each partner.  The aggregate difference in the basis of the
      Partnership’s net assets for financial and income tax purposes cannot be readily
      determined as the Partnership does not have access to the information about
      each
      partner’s tax attributes.  The Partnership’s subsidiaries directly
      incur some income-based state taxes which are presented in Income taxes on
      the
      Condensed Consolidated Statements of Income.








**Note
      5:  Commitments and Contingencies**





**A.  Impact
      of Hurricanes Katrina and Rita**





In
      August
      and September 2005, Hurricanes Katrina and Rita and related storm activity
      caused extensive and catastrophic physical damage to the offshore, coastal
      and
      inland areas in the Gulf Coast region of the United States.  A
      substantial portion of the Gulf South assets and a smaller portion of the Texas
      Gas assets are located in the area directly impacted by the
      hurricanes.





In
      the
      third quarter 2007, the Partnership accrued estimated insurance proceeds of
      $5.1
      million for claims related to Hurricane Rita which represented the minimum
      amount of insurance proceeds that were probable of recovery.  This
      amount resulted in a reduction of Operating Costs and Expenses.  Also
      in the third quarter 2007, because the remediation work related to the
      hurricanes was completed, the remaining accrued liability of $0.7 million was
      reversed to income as a component of Operating Costs and Expenses.  In
      the first quarter 2007, the Partnership received a final cash payment of $6.2
      million of insurance proceeds related to damages incurred during Hurricane
      Katrina, $4.7 million of which was applied against a receivable and $1.5 million
      of which was recognized in Gas transportation revenue.





In
      the
      third quarter 2006, the liability was increased by $0.9 million with a
      corresponding charge to earnings.  Operating Costs and Expenses were
      favorably impacted by $2.6 million related to the hurricanes, during the nine
      months ended September 30, 2006, mainly due to the recognition of $2.7 million
      of insurance proceeds that were probable of recovery.  The accrued
      liability for the hurricanes was zero and $1.0 million as of September 30,
      2007,
      and December 31, 2006.





Through
      September 30, 2007, the
      Partnership has received a total of approximately $12.2 million in insurance
      proceeds related to Hurricane Katrina, and will continue to pursue additional
      recovery of insurance proceeds related to Hurricane Rita.







**B.
      South Timbalier Bay Pipeline Assets**





In
      conjunction with a review of its
      offshore pipeline assets in the South Timbalier Bay area, offshore Louisiana,
      Gulf South discovered that approximately 8 to 9 miles of offshore pipeline
      does
      not have adequate cover.  In the third quarter, the Partnership
      accrued a liability of $4.0 million, which was charged to Operation and
      maintenance expense, for the estimated cost to re-bury the pipeline. 
Gulf South will continue to explore alternatives to mitigate these costs while
      complying with applicable regulations.








11


**C.  Legal
      Proceedings**





***Napoleonville
      Salt Dome Matter***





In
      December 2003, natural gas leaks were observed near two natural gas storage
      caverns that were being leased and operated by Gulf South for natural gas
      storage in Napoleonville, Louisiana. Gulf South commenced remediation efforts
      immediately and ceased using those storage caverns. Several actions have been
      filed against Gulf South and other defendants by local residents and businesses
      as well as the lessor of the property seeking monetary damages. Gulf South
      continues to vigorously defend each of these actions; however, it is not
      possible to predict the outcome of this litigation as the cases remain in
      discovery. Litigation is subject to many uncertainties, and it is possible
      these
      actions could be decided unfavorably. Gulf South has settled several of the
      cases filed against it and may enter into discussions in an attempt to settle
      other cases if Gulf South believes it is appropriate to do
      so*.*





The
      remediation work related to the incident was completed in November
      2006.  Gulf South incurred $8.1 million for remediation costs, root
      cause investigation and legal fees.  Gulf South has made demand for
      reimbursement from its insurance carriers and will continue to pursue recoveries
      of the costs incurred, including legal expenses. To date the insurance carriers
      have not taken any definitive coverage positions on all of the issues raised
      in
      the various lawsuits. Through September 30, 2007, Gulf South has received $1.0
      million of insurance reimbursements for legal expenses and root cause
      investigation.





***The
      NET Complaint***





On
      June
      2, 2007, a complaint was filed by National Energy & Trade, LP (NET) at the
      Federal Energy Regulatory Commission (FERC) against Texas Gas and Gulf
      South.  In its complaint, NET alleged that Texas Gas failed to follow
      its tariff in awarding capacity, Texas Gas violated the Natural Gas Act in
      awarding transportation capacity to Gulf South, and Texas Gas and Gulf South
      engaged in market manipulation in violation of the Energy Policy Act of
      2005.  On October 18, 2007, the FERC issued an order dismissing the
      complaint.  NET can request a rehearing within thirty days of the
      order.








***Other
      Legal Matters***





The
      Partnership's subsidiaries are parties to various other legal actions arising
      in
      the normal course of business. Management believes the disposition of all known
      outstanding legal actions will not have a material adverse impact on the
      Partnership's financial condition, results of operations or cash
      flows.








**D.  Regulatory
      and Rate Matters**





***Pipeline
      Expansion Projects***





*East
      Texas to Mississippi
      Expansion.*  On June 18, 2007, the FERC granted Gulf South the
      authority to construct, own and operate a pipeline expansion consisting of
      approximately 242 miles of 42-inch pipeline from DeSoto Parish in western
      Louisiana to near Harrisville, Mississippi and approximately 110,000 horsepower
      of new compression.  The expansion will add approximately 1.7 Bcf of
      new peak-day transmission capacity to the Gulf South pipeline
      system.  This project is supported by firm transportation agreements
      with customers who have contracted, on a long-term basis (with a weighted
      average term of approximately 6.8 years), for 1.4 Bcf per day of capacity from
      Carthage, Texas, which represents substantially all of the normal operating
      capacity.  Construction of this project has commenced and the
      Partnership expects this project to be in service during the later part of
      the
      fourth quarter 2007.





*Gulf
      Crossing Project.*The Partnership is pursuing construction of a new
      interstate pipeline that will begin near Sherman, Texas and proceed to the
      Perryville, Louisiana area.  The project will be owned by Gulf
      Crossing Pipeline Company LLC (Gulf Crossing), a subsidiary of the Partnership,
      and will consist of approximately 357 miles of 42-inch pipeline having capacity
      of up to approximately 1.7 Bcf of peak-day transmission
      capacity.  Additionally, Gulf Crossing will enter into: (i) a lease
      for up to 1.4 Bcf per day of capacity on the Partnership’s Gulf South pipeline
      system (including capacity on the Southeast Expansion and capacity on a portion
      of the East Texas to Mississippi Expansion) to make deliveries to an
      interconnect with Transcontinental Pipe Line Company (Transco) in Choctaw
      County, Alabama (Transco 85); and (ii) a lease with Enogex, a third-party
      intrastate pipeline, which will bring certain gas supplies to the Partnership’s
      system.  This project is supported by firm transportation agreements
      with customers who have contracted, on a long-term basis (with a weighted
      average term of approximately 9.5 years), for 1.1 Bcf per day of
      capacity.  A customer’s option for an additional 300 MMcf per day of
      firm transportation capacity expired on October 1, 2007.  Another
      customer has the option through November 30, 2007 to increase its contract
      capacity by 50 MMcf per day. The certificate application for this project was
      filed with the FERC on June 19, 2007, and the project is expected to be in
      service during the later part of the fourth quarter 2008.  The
      Partnership is no longer engaged in negotiations for the possible sale of up
      to
      a 49.0% equity interest in Gulf Crossing to one of the foundation shippers
      on
      the project.





12


*Southeast
      Expansion*.  On September 28, 2007, the FERC granted Gulf South
      the authority to construct, own and operate a pipeline expansion originating
      near Harrisville, Mississippi and extending to an interconnect with Transco
      85.
      This expansion will initially consist of approximately 112 miles of 42-inch
      pipeline having capacity of approximately 1.2 Bcf of peak-day transmission
      capacity, and will be expanded to 2.2 Bcf per day to accommodate volumes
      expected to come from the Gulf Crossing leased capacity discussed
      above.  In addition, Gulf South has executed a lease with Destin
      Pipeline Company for capacity which will enhance Gulf South’s access to markets
      in Florida.  This project is supported by firm transportation
      agreements with customers who have contracted, on a long-term basis (with a
      weighted-average term of 8.7 years), for 660 MMcf per day of capacity as well
      as
      the capacity leased to Gulf Crossing discussed above.  The Partnership
      expects to commence construction in the fourth quarter 2007, and this expansion
      to be in service during the later part of the first quarter 2008.





*Fayetteville
      and Greenville
      Laterals*.   The Partnership is pursuing the construction of
      two laterals connected to its Texas Gas pipeline system to transport gas from
      the Fayetteville Shale area in Arkansas to markets directly and indirectly
      served by the Partnership’s existing interstate pipelines.  The
      Fayetteville Lateral, consisting of approximately 165 miles of 36-inch pipeline,
      has an initial design capacity of approximately 800 MMcf of peak-day
      transmission capacity.  This lateral will originate in Conway County,
      Arkansas and proceed southeast through the Bald Knob, Arkansas, area to an
      interconnect with Texas Gas’ mainline in Coahoma County, Mississippi. The
      Greenville Lateral, consisting of approximately 95 miles of pipeline with an
      initial design capacity of approximately 750 MMcf of peak-day transmission
      capacity, will originate at the Texas Gas mainline near Greenville, Mississippi
      and proceed east to the Kosciusko, Mississippi area.  The Greenville
      Lateral will allow customers to access additional markets, primarily in the
      Midwest, Northeast and Southeast. Construction of both laterals is supported
      by
      a binding precedent agreement with Southwestern Energy Services Company, a
      wholly-owned subsidiary of Southwestern Energy Company.  The
      certificate application for this project was filed with the FERC on July 11,
      2007.  The Partnership expects the first 60 miles of the Fayetteville
      Lateral to be in service during the early part of the third quarter 2008 and
      the
      remainder of the Fayetteville and Greenville Laterals to be in service during
      the first quarter 2009.





*Pipeline
      Expansion Project
      Costs*.  The total cost of the pipeline expansion projects discussed
      above is estimated to be approximately $3.7 billion. These costs include the
      expanded pipeline capacity necessary to accommodate additional volumes from
      certain assumed capacity options, contractor penalties incurred as a result
      of
      delays in construction and higher labor and materials costs due to the large
      number of pipeline projects under way throughout the industry.  Actual
      costs may exceed the current estimate due to a variety of factors, including
      awaiting receipt of regulatory approvals, the timing of which the Partnership
      cannot control, weather-related costs and further delays in construction which
      could result in additional contractor penalties and stand-by costs.








***Storage
      Expansion Projects***





*Western
      Kentucky Storage Expansion
      Phase II.*  In December 2006, the FERC issued a certificate
      approving the Phase II storage expansion project which will expand the working
      gas capacity in the Partnership’s western Kentucky storage complex by
      approximately 9.0 Bcf.  This project is supported by binding
      commitments from customers to contract on a long-term basis (with a
      weighted-average term of 8.3 years) for the full additional capacity at Texas
      Gas’ maximum applicable rate.  The Partnership expects this project to
      cost approximately $56.0 million and to be in service November
      2007.





*Western
      Kentucky Storage Expansion
      Phase III.*  Texas Gas has signed two 10-year precedent agreements
      for 4.0 Bcf of storage capacity for its Phase III storage
      project.  The certificate application for this project was filed with
      the FERC on June 25, 2007, seeking up to 8.3 Bcf of new storage capacity if
      Texas Gas is granted market-based rate authority for the new storage capacity
      being proposed.  The cost of this project will be dependent on the
      ultimate size of the expansion. The Partnership expects 4.0 Bcf of storage
      capacity to be in service in 2008.





*Magnolia
      Storage Facility.* The
      Partnership was developing a salt dome storage cavern near Napoleonville,
      Louisiana.  Operational tests, which began in May 2007 and were
      completed in July, indicated that due to anomalies that could not be corrected,
      the Partnership will be unable to place the cavern in service as
      expected.  As a result, the Partnership has elected to abandon that
      cavern and is exploring the possibility of securing a new site on which a new
      cavern could be developed.  In accordance with the requirements of
      SFAS No. 144, *Accounting for the Impairment or Disposal of Long-Lived
      Assets,* the carrying value of the cavern and related facilities of
      approximately $45.1 million was tested for recoverability.  In the
      second quarter 2007, the Partnership recognized an impairment charge to earnings
      of approximately $14.7 million, representing the carrying value of the cavern,
      the fair value of which was determined to be zero based on discounted expected
      future cash flows. The charge was presented as Asset impairment on the Condensed
      Consolidated Statements of Income.  The Partnership expects to use the
      other assets associated with the project, which include pipeline, compressors,
      base gas and other equipment and facilities, in conjunction with a replacement
      storage cavern to be developed. If it is determined in the future that the
      assets cannot be used in conjunction with a new cavern, the Partnership may
      be
      required to record an additional impairment charge at the time that
      determination is made.  Additional costs to abandon the impaired
      cavern may be incurred due to regulatory or contractual obligations, however
      the
      amounts are inestimable at this time.








13








***Contract
      Termination Payment***




The
      Partnership terminated its agreement with one of its construction contractors
      on
      the Southeast Expansion project effective September 30, 2007, to avoid a cost
      increase associated with the delay of construction.  Another
      contractor was selected at more favorable pricing terms to perform the work
      that
      would have been performed under the terminated contract.  This
      decision will not have an effect on the project schedule.  The cost to
      terminate the construction contract of $3.8 million was recorded in Operation
      and maintenance expense.








***Pipeline
      Integrity***





The
      Office of Pipeline Safety has issued a final rule that requires natural gas
      pipeline operators to develop integrity management programs. The Partnership
      expenses all costs incurred in the development of its integrity management
      program and the ongoing inspecting, testing and reporting on the condition
      of
      the pipeline system.  Costs incurred to replace segments of pipeline
      or install software or equipment are capitalized to the extent they meet the
      requirements in the Partnership’s capitalization policy for those types of
      expenditures.  The estimated costs to comply with the rule during the
      initial ten-year baseline period ending in 2012 range from $110.0 to $115.0
      million.  As of September 30, 2007, the Partnership has invested
      approximately $12.3 million to develop and implement integrity management
      program computer systems that allow it to dynamically assess various pipeline
      risks on an integrated basis.  The Partnership has systematically used
      smart, in-line inspection tools to verify the integrity of certain of its
      pipelines.








**E.  Environmental
      and Safety Matters**





The
      operating subsidiaries are subject
      to federal, state and local environmental laws and regulations in connection
      with the operation and remediation of various operating sites. The Partnership
      accrues for environmental expenses resulting from existing conditions that
      relate to past operations when the costs are probable and can be reasonably
      estimated.  In addition to federal and state mandated remediation
      requirements, the Partnership often enters into voluntary remediation programs
      with the agencies.





As
      of
      September 30, 2007 and December 31, 2006, the Partnership had an accrued
      liability of approximately $17.5 million and $18.4 million related to assessment
      and/or remediation costs associated with the historical use of polychlorinated
      biphenyls, petroleum hydrocarbons and mercury, enhancement of groundwater
      protection measures and other costs.  The expenditures are expected to
      occur over approximately the next ten years.  The accrual represents
      management’s estimate of the undiscounted future obligations based on
      evaluations and discussions with counsel and independent consultants and the
      current facts and circumstances related to these matters.  As of
      September 30, 2007 and December 31, 2006, approximately $2.7 and $3.5 million
      were recorded in Other current liabilities.  As of September 30, 2007
      and December 31, 2006, approximately $14.8 million and $14.9 million were
      recorded in Other Liabilities and Deferred Credits.





On
      October 20, 2006, Texas Gas received notice from the Environmental Protection
      Agency (EPA) that Texas Gas is a potentially responsible party under the
      Comprehensive Environmental Response, Compensation, and Liability Act of 1980
      with respect to the LWD, Inc. Superfund Site in Calvert City,
      Kentucky.  The Partnership is unable to estimate with any certainty at
      this time any potential liability it may incur related to this notice; however,
      the Partnership does not expect this to have a material effect on its financial
      condition.





The
      Partnership’s pipelines are subject
      to the Clean Air Act (CAA) and the CAA Amendments of 1990 (Amendments) which
      added significant provisions to the CAA. The Amendments require the EPA to
      promulgate new regulations pertaining to mobile sources, air toxins, areas
      of
      ozone non-attainment and acid rain. The Partnership operates two facilities
      in
      areas affected by non-attainment requirements for the current ozone standard
      (eight-hour standard). As of September 30, 2007, the Partnership had incurred
      costs of approximately $16.1 million for emission control modifications of
      compression equipment located at facilities required to comply with current
      CAA
      provisions, the Amendments and state implementation plans for nitrogen oxide
      reductions.  These costs are being recorded as additions to property,
      plant and equipment (PPE) as the modifications are added.  If the EPA
      designates additional new non-attainment areas or promulgates new air
      regulations where the Partnership operates, the cost of additions to PPE is
      expected to increase, however the Partnership is unable at this time to estimate
      with any certainty the cost of any additions that may be required.





The
      Partnership considers environmental
      assessment, remediation costs and costs associated with compliance with
      environmental standards to be recoverable through base rates, as they are
      prudent costs incurred in the ordinary course of business and, therefore, no
      regulatory asset has been recorded to defer these costs.  The actual
      costs incurred will depend on the actual amount and extent of contamination
      discovered, the final cleanup standards mandated by the EPA or other
      governmental authorities and other factors.





14


**F.  Commitments
      for Construction**





The
      Partnership’s future capital
      commitments as of September 30, 2007, for contracts already authorized are
      expected to approximate the following amounts (in millions):





Less
                than 1 year
            
            $
            755.21-3
                years
            
            
            145.24-5
                years
            
            
            -More
                than 5 years
            
            
            -Total
            
            $
            900.4





The
      construction work in progress
      included in Property, plant and equipment, net in the Condensed Consolidated
      Balance Sheets was $960.2 million and $166.0 million as of September 30, 2007
      and December 31, 2006.








**Note
      6:  Net Income per Limited Partner Unit and Cash
      Distributions**





The
      Partnership calculates net income per limited partner unit in accordance with
      Emerging Issues Task Force Issue No. 03-6 (EITF No.
      03-6),*Participating Securities and the Two-Class Method under
      FASB Statement No. 128*.  In Issue 3 of EITF No. 03-6, the EITF
      reached a consensus that undistributed earnings for a period should be
      allocated to a participating security based on the contractual
      participation rights of the security to share in those earnings as if all of
      the
      earnings for the period had been distributed.  The Partnership's general
      partner holds contractual participation rights which are incentive distribution
      rights in accordance with the partnership agreement as follows:





**Total
                Quarterly Distribution**
            
            **Marginal Percentage Interest in**
              **Distributions****Target
                Amount**
            **Common
                and**
              **Subordinated**
              **Unitholders**
            
            **General Partner**Minimum
                Quarterly Distribution
            
            $0.3500
            
            98%
            2%First
                Target Distribution
            
            up to $0.4025
            
            98%
            2%Second
                Target Distribution
            
            Above $0.4025 up to $0.4375
            
            85%
            15%Third
                Target Distribution
            
            Above
                $0.4375 up to $0.5250
            
            75%
            25%Thereafter
            
            above
                $0.5250
            
            50%
            50%





The amounts
      reported for net income per limited partner unit on the Condensed
      Consolidated Statements of Income for the three and nine month periods
      ended September 30, 2007 and 2006, were adjusted to take into account an
      assumed allocation to the general partner's incentive distribution rights.
      Payments made on account of the incentive distribution rights are determined
      in
      relation to actual declared distributions and not based on the assumed
      allocation required by EITF No. 03-6. A reconciliation of the limited partners'
      interest in net income and net income available to limited partners used in
      computing net income per limited partner unit follows (in thousands, except
      weighted average units and per unit data):








**For
                the**
              **Three
                Months Ended**
              **September
                30,**
            
            
            **For
                the**
              **Nine
                Months Ended**
              **September
                30,****2007**
            
            
            **2006**
            
            
            **2007**
            
            
            **2006**Limited
                partners' interest in net income
            
            $
            38,468
            
            
            $
            30,035
            
            
            $
            151,140
            
            
            $
            129,632Less
                assumed allocation to incentive distribution rights
            
            
            (711
            )
            
            
            -
            
            
            
            719
            
            
            
            962Net
                income available to limited partners
            
            $
            39,179
            
            
            $
            30,035
            
            
            $
            150,421
            
            
            $
            128,670Less
                assumed allocation to subordinated units
            
            
            10,074
            
            
            
            6,144
            
            
            
            43,718
            
            
            
            42,015Net
                income available to common units
            
            $
            29,105
            
            
            $
            23,891
            
            
            $
            106,703
            
            
            $
            86,655Weighted
                average common units
            
            
            83,156,122
            
            
            
            68,256,122
            
            
            
            80,773,769
            
            
            
            68,256,122Weighted
                average subordinated units
            
            
            33,093,878
            
            
            
            33,093,878
            
            
            
            33,093,878
            
            
            
            33,093,878Net
                income per limited partner unit - common units
            
            $
            0.35
            
            
            $
            0.35
            
            
            $
            1.32
            
            
            $
            1.27Net
                income per limited partner unit – subordinated units
            
            $
            0.30
            
            
            $
            0.19
            
            
            $
            1.32
            
            
            $
            1.27





15


**Note
      7:  Financing**





On
      August
      17, 2007, the Partnership received net proceeds of approximately $495.3 million
      after deducting initial purchaser discounts and offering expenses of $4.7
      million from Gulf South’s sale of $225.0 million of 5.75% senior unsecured notes
      due August 15, 2012, and $275.0 million of 6.30% senior unsecured notes due
      August 15, 2017.  Interest on the notes will be payable on February 15
      and August 15 of each year, beginning on February 15, 2008.  The
      notes are redeemable, in whole or in part, at Gulf South’s option at any
      time, at a redemption price equal to the greater of 100% of the principal amount
      of the notes to be redeemed or a “make whole” redemption price based on the
      remaining scheduled payments of principal and interest discounted to the date
      of
      redemption at a Treasury rate plus 20 basis points in the case of the 2012
      notes, or 25 basis points in the case of the 2017 notes, plus accrued and unpaid
      interest, if any.  Other customary covenants apply, including those
      concerning events of default.





As
      of
      September 30, 2007 and December 31, 2006, no funds were drawn under the
      Partnership’s $700 million revolving credit facility.  However, at
      September 30, 2007, the Partnership had outstanding letters of credit under
      the
      facility for $221.5 million to support certain obligations associated with
      the
      Fayetteville Lateral and Gulf Crossing expansion projects which reduced the
      available capacity under the facility by such amount.





In
      March
      2007, the Partnership completed a public offering of 8.0 million of its common
      units at a price of $36.50 per unit.  The Partnership received
      proceeds of approximately $293.8 million, net of underwriting discounts and
      offering expenses, and including approximately $6.0 million from the general
      partner to maintain its 2.0% general partner interest.  After the
      offering, the Partnership has 83.2 million common units issued and outstanding,
      of which 29.9 million are held by the public.  The balance of the
      common units and all of the subordinated units are held by BPHC.





As
      of
      September 30, 2007 and December 31, 2006, the weighted average interest rate
      of
      the Partnership’s long-term debt was 5.82% and 5.41%.  The Partnership
      was in compliance with all loan covenants at September 30, 2007.





During
      the three and nine months ended September 30, 2007, the Partnership capitalized
      interest of $8.2 million and $14.5 million.  During the three and nine
      months ended September 30, 2006, the Partnership capitalized interest of
      approximately $0.7 million and $0.8 million. In accordance with SFAS No. 71,
      *Accounting for the Effect of Certain Types of Regulation*, the
      Partnership’s Texas Gas subsidiary capitalizes allowance for funds used during
      construction (AFUDC), comprised of debt and equity components. The Partnership
      capitalized $1.3 million and $2.4 million of AFUDC for the three and nine months
      ended September 30, 2007.  The Partnership capitalized $0.5 million
      and $1.1 million of AFUDC for the three and nine months ended September 30,
      2006.








**Note
      8: Investment in Securities Under Repurchase Agreements**





During
      the third quarter 2007, the
      Partnership began investing its undistributed cash in U.S. Government
      securities, primarily Treasury notes, under repurchase
      agreements.  Generally, the Partnership has engaged in overnight
      repurchase transactions where purchased securities are sold back to the
      counterparty the following business day.  Pursuant to the master
      repurchase agreements, the Partnership takes actual possession of the purchased
      securities.  In the event of default by the counterparty under the
      agreement, the repurchase would be deemed immediately to occur and the
      Partnership would be entitled to sell the securities in the open market, or
      give
      the counterparty credit based on the market price on such date, and apply the
      proceeds (or deemed proceeds) to the aggregate unpaid repurchase amounts and
      any
      other amounts owing by the counterparty.  Previously, the
      Partnership’s cash balances were invested in money market accounts.





At
      September 30, 2007, the portfolio
      consisted of two tranches of Treasury securities purchased in overnight
      repurchase agreement transactions, each in the amount of $270.0 million, with
      original maturities in August 2008 and January 2011.  The amount
      invested under repurchase agreements of $540.0 million, stated at cost which
      closely approximates the fair values of the securities, is presented as
      Short-term investments in Current Assets on the Condensed Consolidated Balance
      Sheets.








**Note
      9: Credit Concentration**





Natural
      gas price volatility has increased dramatically in recent years which has
      materially increased credit risk related to gas loaned to customers. Gas loaned
      to customers refers to receivables for services provided, as well as volumes
      owed by customers for imbalances or gas lent by the Partnership to them,
      generally under PAL and no-notice service (NNS). As of September 30, 2007,
      the
      amount of gas loaned out by the Partnership’s subsidiaries was approximately 6.6
      TBtu and, assuming an average market price during September 2007 of $5.86 per
      million British thermal units (MMBtu), the market value of gas loaned out at
      September 30, 2007, would have been approximately $38.7 million.  If
      any significant customer of the Partnership should have credit or financial
      problems resulting in a delay or failure to repay the gas they owe to it, this
      could have a material adverse effect on the Partnership’s financial condition,
      results of operations and cash flows.





16





**Note
      10:  Employee Benefits**





Substantially
      all of Texas Gas'
      employees are covered under a non-contributory, defined benefit pension
      plan.  The Texas Gas Supplemental Retirement Plan provides pension
      benefits for the portion of an eligible employee’s pension benefit that becomes
      subject to compensation limitations under the Internal Revenue
      Code.  Effective in November 2006, the defined benefit retirement plan
      was closed to new participants and new employees will be provided benefits
      under
      a defined contribution money purchase plan.  All Gulf South employees
      are provided retirement benefits under a similar defined contribution money
      purchase plan.  Texas Gas provides postretirement life insurance and
      postretirement health care benefits to certain retired employees.  The
      operating subsidiaries also provide 401(k) plan benefits to their
      employees.  The Partnership uses a measurement date of December 31 for
      its benefits plans.








***Early
      Retirement Incentive Program***





In
      2006,
      Texas Gas implemented an early retirement incentive program (ERIP) which was
      made available to approximately 240 eligible non-executive
      employees.  Retirements under the program were generally effective
      January 1, 2007. Approximately 100 of the eligible employees elected to
      participate in the program.  In 2007, the Partnership recognized a pension
      settlement charge in Administrative and general expense related to the ERIP
      of
      $4.2 million to recognize the effects of retirements associated with the ERIP
      that were initiated during the period. In third quarter 2006, as a result of
      the
      ERIP, the Partnership recognized a special termination benefit of approximately
      $5.6 million for pension and $0.9 million for post retirement benefits other
      than pensions (PBOP).








***Components
      of Net Periodic Benefit Cost***





Components
      of net periodic benefit cost
      for both the retirement plans and PBOP for the three and nine months ended
      September 30, 2007 and 2006 were the following (in thousands):





**Retirement
                Plans**
            
            
            **PBOP****For
                the**
              **Three
                Months Ended**
              **September
                30,**
            
            
            **For
                the**
              **Three
                Months Ended**
              **September
                30,****2007**
            
            
            **2006**
            
            
            **2007**
            
            
            **2006**Service
                cost
            
            $
            935
            
            
            $
            1,826
            
            
            $
            152
            
            
            $
            108Interest
                cost
            
            
            1,542
            
            
            
            2,816
            
            
            
            818
            
            
            
            858Expected
                return on plan assets
            
            
            (1,695
            )
            
            
            (2,942
            )
            
            
            (1,183
            )
            
            
            (1,134
            )Amortization
                of prior service credit
            
            
            1
            
            
            
            -
            
            
            
            (1,940
            )
            
            
            (1,939
            )Amortization
                of unrecognized net loss
            
            
            69
            
            
            
            383
            
            
            
            167
            
            
            
            110Settlement
                charge (ERIP)
            
            
            400
            
            
            
            5,600
            
            
            
            -
            
            
            
            900Regulatory
                asset (increase) decrease
            
            
            (453
            )
            
            
            (3,295
            )
            
            
            1,354
            
            
            
            1,354Net
                periodic expense
            
            $
            799
            
            
            $
            4,388
            
            
            $
            (632
            )
            
            $
            257





**Retirement
                Plans**
            
            
            **PBOP****For
                the**
              **Nine
                Months Ended**
              **September
                30,**
            
            
            **For
                the**
              **Nine
                Months Ended**
              **September
                30,****2007**
            
            
            **2006**
            
            
            **2007**
            
            
            **2006**Service
                cost
            
            $
            2,800
            
            
            $
            3,984
            
            
            $
            456
            
            
            $
            1,194Interest
                cost
            
            
            4,767
            
            
            
            6,044
            
            
            
            2,455
            
            
            
            4,319Expected
                return on plan assets
            
            
            (5,275
            )
            
            
            (6,492
            )
            
            
            (3,550
            )
            
            
            (3,418
            )Amortization
                of prior service credit
            
            
            3
            
            
            
            -
            
            
            
            (5,820
            )
            
            
            (2,587
            )Amortization
                of unrecognized net loss
            
            
            215
            
            
            
            584
            
            
            
            501
            
            
            
            876Settlement
                charge (ERIP)
            
            
            4,200
            
            
            
            5,600
            
            
            
            -
            
            
            
            900Regulatory
                asset (increase) decrease
            
            
            (453
            )
            
            
            (3,045
            )
            
            
            4,061
            
            
            
            4,964Net
                periodic expense
            
            $
            6,257
            
            
            $
            6,675
            
            
            $
            (1,897
            )
            
            $
            6,248





17


The
      decrease in the regulatory asset
      for PBOP was due primarily to the amortization of costs incurred in prior
      years.  The regulatory asset for the retirement plans was increased
      due to the accumulated cost for the year exceeding the expense cap established
      in the 2005 rate case settlement between Texas Gas and its
      customers.  In accordance with the rate case settlement, Texas Gas is
      permitted to seek future rate recovery for amounts of annual pension costs
      in
      excess of $6.0 million.








***Defined
      Contribution Plans***





Costs
      related to the Partnership’s defined contribution plans were $1.2 million and
      $3.9 million for the three and nine months ended September 30, 2007, and
      $1.2 million and $3.7 million for the three and nine months ended September
      30,
      2006.








**Note
      11:  Related Parties**





Loews
      provides a variety of corporate
      services to the Partnership and its subsidiaries under services agreements.
      Services provided by Loews include, among others, information technology, tax,
      risk management, internal audit and corporate development services. Loews
      charged $2.7 million and $9.3 million for the three and nine months ended
      September 30, 2007, and $2.1 million and $8.6 million for the three and nine
      months ended September 30, 2006, to the Partnership based on the actual time
      spent by Loews personnel performing these services, plus related
      expenses.





Distributions
      paid on common and
      subordinated units held by BPHC and the 2.0% general partner interest and
      incentive distribution rights held by Boardwalk GP, LP were $115.4 million
      and
      $81.2 million during the nine months ended September 30, 2007 and
      2006.  In addition, as a result of the public offering of common units
      in March 2007, the general partner contributed approximately $6.0 million to
      maintain its general partner interest.








**Note
      12: Distributions**





The
      Partnership has declared quarterly
      distributions per unit to unitholders of record, including common and
      subordinated units and the 2.0% general partner interest held by its general
      partner as follows:





**Record
                Date**
            
            **Payable
                Date**
            
            **Distribution
                per Unit**November
                5, 2007
            
            November
                12, 2007
            
            0.45August
                6, 2007
            
            August
                13, 2007
            
            0.44May
                7, 2007
            
            May
                14, 2007
            
            0.43February
                20, 2007
            
            February
                27, 2007
            
            0.415October
                30, 2006
            
            November
                6, 2006
            
            0.40August
                11, 2006
            
            August
                18, 2006
            
            0.38May
                12, 2006
            
            May
                19, 2006
            
            0.36February
                16, 2006
            
            February
                23, 2006
            
            0.179*





*Distribution
                represented a prorated portion of the $0.35 per unit “minimum quarterly
                distribution” (as defined in the Partnership’s partnership agreement) for
                the period November 15, 2005 through December 31,
                2005.





The
      Partnership also pays cash
      distributions to its general partner on account of its incentive distribution
      rights with respect to that portion of a quarterly distribution in excess of
      $0.4025 per unit.  These payments were $1.4 million for the nine
      months ended September 30, 2007, and will be $1.1 million in the fourth quarter
      2007 based on the declared distribution.








**Note
      13:  Accumulated Other Comprehensive Income**





The
      following table shows the
      components of Accumulated other comprehensive income at September 30, 2007
      and
      December 31, 2006 (in thousands):





**As
                of**
              **September
                30, 2007**
            
            
            **As
                of**
              **December
                31, 2006**(Loss)
                gain on cash flow hedges
            
            $
            (2,524
            )
            
            $
            8,309Deferred
                components of net periodic benefit cost
            
            
            13,268
            
            
            
            14,803Total
                Accumulated other comprehensive income
            
            $
            10,744
            
            
            $
            23,112








18


**Note
      14:  Guarantee of Securities of Subsidiaries**





The
      Partnership has no assets or
      operations other than its investment in its subsidiaries.  The
      Partnership’s operating subsidiaries have issued securities which have all been
      fully and unconditionally guaranteed by the Partnership.   The
      Partnership does have separate partners’ capital including publicly traded
      limited partner common units.





The
      Partnership’s subsidiaries have no
      significant restrictions on their ability to pay distributions or loans to
      the
      Partnership and have no restricted assets at September 30, 2007.








**Note
      15:  Recently Issued Accounting Pronouncements**





*SFAS
      No. 157*





On
      September 15, 2006, the Financial
      Accounting Standards Board (FASB) issued SFAS No. 157,*Fair Value
      Measurements*. Fair value refers to the price that would be received to sell
      an asset or paid to transfer a liability in an orderly transaction between
      market participants in the market in which the reporting entity transacts.
      The
      standard clarifies the principle that fair value should be based on the
      assumptions market participants would use when pricing the asset or liability.
      In support of this principle, the standard establishes a fair value hierarchy
      that prioritizes the information used to develop those assumptions. The fair
      value hierarchy gives the highest priority to quoted prices in active markets
      and the lowest priority to unobservable data, for example, the reporting
      entity's own data. Under the standard, fair value measurements would be
      separately disclosed by level within the fair value hierarchy. The Statement
      is
      effective for financial statements issued for fiscal years beginning after
      November 15, 2007, and interim periods within those fiscal years. The
      effective date for the Partnership is January 1, 2008.  The
      Partnership is currently evaluating the impact, if any, that SFAS No. 157 would
      have on its financial condition, results of operations or cash
      flows.








*SFAS
      No. 159*





In
      February 2007, the FASB issued SFAS
      No. 159, *The Fair Value Option for Financial Assets and Financial
      Liabilities- including an amendment of SFAS No. 115.*SFAS No.
      159 allows companies to elect to measure financial assets and financial
      liabilities at fair value.  Unrealized gains and losses on items for
      which the fair value option has been chosen are reported in
      earnings.  SFAS No. 159 is effective for fiscal years beginning after
      November 15, 2007.  The effective date for the Partnership is January
      1, 2008.  The Partnership is currently evaluating the impact, if any,
      of adopting SFAS No. 159 on its financial condition, results of operations
      or
      cash flows.


19





**Item
      2.   Management's Discussion and Analysis of
      Financial Condition and Results of Operations**





*The
      following discussion and analysis
      of financial condition and results of operations should be read in conjunction
      with our accompanying interim condensed consolidated financial statements and
      related notes, included elsewhere in this report and prepared in accordance
      with
      accounting principles generally accepted in the United States of America
      and  our consolidated financial statements, related notes,
      Management's Discussion and Analysis of Financial Condition and Results of
      Operations and Risk Factors included in our Annual Report on Form 10-K for the
      year ended December 31, 2006.*





We
      are a Delaware limited partnership
      formed to own and operate the business conducted by Boardwalk Pipelines, LP
      (Boardwalk Pipelines) and its subsidiaries, Gulf South Pipeline Company, LP
      (Gulf South) and Texas Gas Transmission, LLC (Texas Gas) (together, the
      operating subsidiaries).  We own and operate pipeline systems in the
      Gulf Coast states of Texas, Louisiana, Mississippi, Alabama, and
      Florida which extend northward through Arkansas to the Midwestern states of
      Tennessee, Kentucky, Illinois, Indiana, and Ohio.








**Results
      of Operations – Business Overview**





We
      derive
      our revenues primarily from the interstate transportation and storage of natural
      gas for third parties. Transportation and storage services are provided under
      firm and interruptible service agreements. Transportation rates are subject
      to
      maximum tariff rates established by the Federal Energy Regulatory Commission
      (FERC), although many services are provided at a rate lower than the maximum
      tariff rates due to competition in the marketplace.Our Gulf
      South subsidiary is authorized to charge market-based rates for its firm and
      interruptible storage services.





We
      are
      not in the business of buying and selling natural gas other than for system
      management and operational purposes, but changes in the price of natural gas
      can
      affect the overall supply and demand of natural gas which in turn does affect
      our results of operations.  We deliver gas to a broad mix of customers
      including local distribution companies, municipalities, interstate and
      intrastate pipelines, direct industrial users, electric power generation plants,
      marketers and producers.  In addition to serving directly connected
      markets, our pipeline systems have indirect market access to the northeastern
      and southeastern United States through interconnections with unaffiliated
      pipelines.





Under
      firm transportation agreements, customers generally pay a fixed “demand” or
“capacity reservation” charge to reserve pipeline capacity at certain receipt
      and delivery points, plus a commodity and fuel charge paid on the volume of
      gas
      actually transported. Firm storage customers reserve a specific amount of
      storage capacity and injection and withdrawal capability and generally pay
      a
      capacity reservation charge based on the amount of capacity being reserved
      plus
      an injection and/or withdrawal fee. Capacity reservation revenues derived from
      a
      firm service contract (including no-notice storage service) are generally
      consistent during the contract term, but can be higher in winter peak periods,
      especially related to no-notice storage agreements, than in off-peak periods.
      The seasonal effect is also impacted by increased revenues generated from usage
      during the winter peak periods.





Interruptible
      transportation and storage services are typically short-term in nature and
      are
      generally used by customers that do not require the certainty of delivery that
      is provided with firm services. Customers pay for interruptible services when
      the service is used.





Revenues
      for our parking and lending (PAL) services and certain of our storage services
      for which we are authorized to charge market-based rates are affected by
      period-to-period natural gas price spreads (for example, summer to
      winter).  In recent periods, these price spreads have been wider and
      more volatile than in previous years, resulting in significant
      increases in parking and lending and storage revenues.  We are uncertain if
      these recent favorable trends in period-to-period natural gas price spreads
      will
      continue. A reversal of this trend could result in lower revenues and profits
      from these services in future periods.





Operating
      expenses typically do not vary significantly based upon the amount of gas
      transported with the exception of gas consumed by Gulf South’s compressor
      stations. Gulf South’s fuel recoveries are included as part of transportation
      revenues.





20


**Results
      of Operations for the Three Months Ended September 30, 2007 and
      2006**





Our
      net
      income for the third quarter 2007 increased $9.4 million, or 30.7%, from the
      comparable 2006 period.  The primary drivers for the increase were higher
      revenues from firm transportation services resulting from higher reservation
      rates and pipeline system expansion.





Operating
      revenues for the third quarter 2007 increased $1.7 million, or 1.3%, to $134.7
      million, compared to $133.0 million for the third quarter 2006 primarily due
      to:





·
            $5.1
                million increase in transportation fees due to higher reservation
                rates,
                including $2.4 million from new contracts associated with the Carthage,
                Texas to Keatchie, Louisiana pipeline expansion which was placed
                in
                service at the end of 2006, partly offset
                by





·
            a
                $2.5 million decrease in fuel revenues due to lower realized gas
                prices,
                including hedging activity.





Operating
      expenses for the third quarter 2007 decreased $2.1 million, or 2.4%, to $86.2
      million, compared to $88.3 million for the third quarter 2006 primarily due
      to:





·
            $6.7
                million decrease comprised of a $5.1 million accrual of estimated
                insurance proceeds deemed probable of recovery related to Hurricane
                Rita
                and a $1.6 million decrease in the estimated cost of damage caused
                by
                Hurricanes Katrina and Rita
                (hurricanes);


·
            $4.4
                million gain on the sale of gas associated with the Western Kentucky
                storage expansion project and related derivative
                contracts;


·
            $1.8 million
                decrease in administrative and general expenses driven primarily
                by
                benefit plan changes at Texas Gas, partly offset by an increase in
                other
                expenses due to growth; and





The
      decreases were partly offset by:





·
            $4.0
                million increase from an accrual for remediation of an offshore pipeline
                in the South Timbalier Bay area, offshore
                Louisiana;


·
            $3.8 million
                increase related to termination of an agreement with a construction
                contractor on the Southeast expansion
                project;


·
            $2.1
                million increase in fuel costs due to an increase in gas usage;
                and


·
            $1.6
                million increase in depreciation and amortization from additions
                to plant
                and computer systems.











Total
      other deductions for the third quarter 2007 declined by $5.6 million, or 40.0%,
      to $8.4 million, compared to $14.0 million for the third quarter 2006, primarily
      due to an increase in interest income of $5.1 million as a result of higher
      levels of invested cash.








**Results
      of Operations for the Nine Months Ended September 30, 2007 and
      2006**





Our
      net
      income for the first nine months of 2007 increased $23.4 million or 17.7% from
      the comparable 2006 period.  The primary drivers for the increase were
      higher revenues from increased utilization and strong demand for firm
      transportation services, pipeline system expansion and a continued strong
      environment for PAL and storage services resulting in higher reservation
      rates.  The higher revenues were partly offset by a $14.7 million
      impairment charge associated with a portion of our Magnolia storage project
      and
      higher operating expenses.





Operating
      revenues for the nine months ended September 30, 2007 increased $37.2 million,
      or 8.5%, to $473.4 million, compared to $436.2 million for the nine months
      ended
      September 30, 2006 primarily due to:





·
            $18.8
                million increase in transportation fees due to higher reservation
                rates,
                including $6.6 million from new contracts associated with the Carthage,
                Texas to Keatchie, Louisiana pipeline
                expansion;


·
            $11.5
                million increase in fuel revenues due to an increase in other system
                volumes and higher realized gas prices including hedging activity;
                and


·
            $9.3
                million increase in PAL and storage services mainly due to increased
                firm
                storage service rates and gas parked by customers during summer and
                fall
                2006 for withdrawal during summer
                2007.





The
      increases were partly offset by:





·
            $2.2
                million due to a decrease in the amortization of acquired executory
                contracts.





21


Operating
      expenses for the nine months ended September 30, 2007 increased $27.3 million,
      or 10.5%, to $288.2 million, compared to $260.9 million for the nine months
      ended September 30, 2006 primarily due to:





·
            $14.7
                million loss from impairment of the Magnolia storage facility in
                the
                second quarter 2007;


·
            $5.0
                million increase in fuel costs due to an increase in gas
                usage;


·
            $4.3
                million increase in depreciation and amortization from additions
                to plant
                and computer systems;


·
            $4.0
                million increase from an accrual for remediation of an offshore pipeline
                in the South Timbalier Bay area, offshore
                Louisiana;


·
            $3.8
                million increase related to termination of an agreement with a
                construction contractor on the Southeast expansion project;
                and


·
            $3.2
                million increase in property and other taxes primarily as a result
                of a
                reversal of a franchise tax accrual in the 2006
                period.





The
      increases were partly offset by:





·
            $4.1
                million decrease in administrative and general expenses driven primarily
                by benefit plan changes at Texas Gas, partly offset by an increase
                in
                other expenses due to growth;


·
            $3.6
                million net favorable variance from a gain on the sale of gas associated
                with the Western Kentucky storage expansion project and related derivative
                contracts; and


·
            $3.0
                million decrease from the accrual of estimated insurance proceeds
                related
                to the hurricanes deemed probable of
                recovery.





Total
      other deductions for the nine months ended September 30, 2007 declined by $13.6
      million, or 31.9%, to $29.0 million, compared to $42.6 million for the nine
      months ended September 30, 2006.  The decline is primarily due to an
      increase in interest income of $14.5 million as a result of higher levels of
      invested cash.








**Capital
      Expenditures**





Capital
      expenditures for the nine
      months ended September 30, 2007 and 2006 were $688.2 million and $124.2
      million.  For the year ending December 31, 2007, we expect to make
      capital expenditures of approximately $1.3 billion, of which we expect
      approximately $1.2 billion to be for the expansion projects discussed below
      and
      approximately $62.4 million to be for maintenance capital. The amount of capital
      we expend in 2007 could vary significantly depending on the progress made with
      these projects, the number and types of other capital projects we decide to
      pursue, the timing of any of those projects and numerous other factors beyond
      our control.





We
      expect to fund our expansion capital
      expenditures for 2007 and beyond with cash on hand, liquidation of short-term
      investments, proceeds from additional sales of our debt and equity securities,
      borrowings under our revolving credit facility and operating cash flows, though
      we have not made any determination with regard to any future financing
      activities.  We expect to fund our maintenance capital expenditures
      from operating cash flows.





We
      are currently engaged in the
      following pipeline expansion projects:





·
            *East
                Texas to Mississippi Expansion.*  On June 18, 2007, the FERC
                granted Gulf South the authority to construct, own and operate a
                pipeline
                expansion consisting of approximately 242 miles of 42-inch pipeline
                from
                DeSoto Parish in western Louisiana to near Harrisville, Mississippi
                and
                approximately 110,000 horsepower of new compression.  The
                expansion will add approximately 1.7 billion cubic feet (Bcf) of
                new
                peak-day transmission capacity to the Gulf South pipeline
                system.  This project is supported by firm transportation
                agreements with customers who have contracted, on a long-term basis
                (with
                a weighted average term of approximately 6.8 years), for 1.4 Bcf
                per day
                of capacity from Carthage, Texas, which represents substantially
                all of
                the normal operating capacity.  Construction of this project has
                commenced and we expect this project to be in service during the
                later
                part of the fourth quarter 2007.





In
      September 2007, Gulf South became aware of allegations by two former employees
      of a manufacturer of pipe to be installed as part of the East Texas to
      Mississippi expansion project that certain irregularities occurred during the
      manufacturing process.  Gulf South has conducted an investigation into
      these allegations and informed appropriate government officials. Gulf South
      has,
      among other things, interviewed the complainants and other individuals and
      reviewed documentation related to the manufacture and inspection of the pipe,
      including radiographic records related to allegedly deficient pipe welds, and
      has found no evidence to support these allegations. Based on these results,
      we
      believe that the subject pipe meets our specifications and is suitable to be
      placed into service.





22





·
            *Gulf
                Crossing Project.*We are pursuing construction of a new interstate
                pipeline that will begin near Sherman, Texas and proceed to the
                Perryville, Louisiana area.  The project will be owned by Gulf
                Crossing Pipeline Company LLC (Gulf Crossing), a subsidiary of ours,
                and
                will consist of approximately 357 miles of 42-inch pipeline having
                capacity of up to approximately 1.7 Bcf of peak-day transmission
                capacity.  Additionally, Gulf Crossing will enter into: (i) a
                lease for up to 1.4 Bcf per day of capacity on our Gulf South pipeline
                system (including capacity on the Southeast Expansion and capacity
                on a
                portion of the East Texas to Mississippi Expansion) to make deliveries
                to
                an interconnect with Transcontinental Pipe Line Company (Transco)
                in
                Choctaw County, Alabama (Transco 85); and (ii) a lease with Enogex,
                a
                third-party intrastate pipeline, which will bring certain gas supplies
                to
                our system.  This project is supported by firm transportation
                agreements with customers who have contracted, on a long-term basis
                (with
                a weighted average term of approximately 9.5 years), for 1.1 Bcf
                per day
                of capacity.  A customer’s option for an additional 300 MMcf per
                day of firm transportation capacity expired on October 1, 2007. Another
                customer has the option through November 30, 2007, to increase its
                contract capacity by 50 MMcf per day. The certificate application
                for this
                project was filed with the FERC on June 19, 2007, and the project
                is
                expected to be in service during the later part of the fourth quarter
                2008.  We are no longer engaged in negotiations for the possible
                sale of up to a 49.0% equity interest in Gulf Crossing to one of
                the
                foundation shippers on the project.





·
            *Southeast
                Expansion*.  On September 28, 2007, the FERC granted Gulf
                South the authority to construct, own and operate a pipeline expansion
                originating near Harrisville, Mississippi and extending to an interconnect
                with Transco 85. This expansion will initially consist of approximately
                112 miles of 42-inch pipeline having capacity of approximately 1.2
                Bcf of peak-day transmission capacity, and will be expanded to 2.2
                Bcf per
                day to accommodate volumes expected to come from the Gulf Crossing
                leased
                capacity discussed above.  In addition, Gulf South has executed
                a lease with Destin Pipeline Company for capacity which will enhance
                Gulf
                South’s access to markets in Florida.  This project is supported
                by firm transportation agreements with customers who have contracted,
                on a
                long-term basis (with a weighted-average term of 8.7 years), for
                660 MMcf
                per day of capacity as well as the capacity leased to Gulf Crossing
                discussed above.  We expects to commence construction in the
                fourth quarter 2007, and this expansion to be in service during the
                later
                part of the first quarter 2008.





·
            *Fayetteville
                and Greenville Laterals*. We are pursuing the construction of two
                laterals connected to our Texas Gas pipeline system to transport
                gas from
                the Fayetteville Shale area in Arkansas to markets directly and indirectly
                served by our existing interstate pipelines.  The Fayetteville
                Lateral, consisting of approximately 165 miles of 36-inch pipeline,
                has an
                initial design capacity of approximately 800 MMcf of peak-day transmission
                capacity.  This lateral will originate in Conway County,
                Arkansas and proceed southeast through the Bald Knob, Arkansas, area
                to an
                interconnect with Texas Gas’ mainline in Coahoma County, Mississippi. The
                Greenville Lateral, consisting of approximately 95 miles of pipeline
                with
                an initial design capacity of 750 MMcf of peak-day transmission capacity,
                will originate at the Texas Gas mainline near Greenville, Mississippi
                and
                proceed east to the Kosciusko, Mississippi area.  The Greenville
                Lateral will allow customers to access additional markets, primarily
                in
                the Midwest, Northeast and Southeast. Construction of both laterals
                is
                supported by a binding precedent agreement with Southwestern Energy
                Services Company, a wholly-owned subsidiary of Southwestern Energy
                Company.  The certificate application for this project was filed
                with the FERC on July 11, 2007.  We expect the first 60 miles of
                the Fayetteville Lateral to be in service during the early part of
                the
                third quarter 2008 and the remainder of the Fayetteville and Greenville
                Laterals to be in service during the first quarter
                2009.





*Pipeline
      Expansion Costs*. The
      total cost of the pipeline expansion projects discussed above is estimated
      to be
      approximately $3.7 billion.  These costs include the expanded pipeline
      capacity necessary to accommodate additional volumes from certain assumed
      capacity options, contractor penalties incurred as a result of delays in
      construction and higher labor and materials costs due to the large number of
      pipeline projects under way throughout the industry.  Actual costs may
      exceed the current estimate due to a variety of factors, including awaiting
      receipt of regulatory approvals, the timing of which we cannot control,
      weather-related costs and further delays in construction which could result
      in
      additional contractor penalties and stand-by costs.





In
      addition to the pipeline expansion
      projects described above, we are currently engaged in the following storage
      expansion projects:





·
            *Western
                Kentucky Storage Expansion Phase II.*  In December 2006, the
                FERC issued a certificate approving the Phase II storage expansion
                project
                which will expand the working gas capacity in our western Kentucky
                storage
                complex by approximately 9.0 Bcf.  This project is supported by
                binding commitments from customers to contract on a long-term basis
                (with
                a weighted-average term of 8.3 years), for the full additional capacity
                at
                Texas Gas’ maximum applicable rate.  We expect this project to
                cost approximately $56.0 million and to be in service November
                2007.





23


·
            *Western
                Kentucky Storage Expansion Phase III*.  Texas Gas has signed
                two 10-year precedent agreements for 4.0 Bcf of storage capacity
                for our
                Phase III storage project.  The certificate application for this
                project was filed with the FERC on June 25, 2007, seeking up to 8.3
                Bcf of
                new storage capacity if Texas Gas is granted market-based rate authority
                for the new storage capacity being proposed.  The cost of this
                project will be dependent on the ultimate size of the
                expansion.  We expect 4.0 Bcf of storage capacity to be in
                service in 2008.





·
            *Magnolia
                Storage Facility.* We were developing a salt dome storage cavern near
                Napoleonville, Louisiana.  Operational tests, which began in May
                2007 and were completed in July, indicated that due to anomalies
                that
                could not be corrected, we will be unable to place the cavern in
                service
                as expected.  As a result, we have elected to abandon that
                cavern and are exploring the possibility of securing a new site on
                which a
                new cavern could be developed.  In accordance with the
                requirements of Statement of Financial Accounting Standards (SFAS)
                No.
                144, *Accounting for the Impairment or Disposal of Long-Lived
                Assets,* the carrying value of the cavern and related facilities of
                approximately $45.1 million was tested for recoverability.  In
                the second quarter 2007 we recognized an impairment charge to earnings
                of
                approximately $14.7 million, representing the carrying value of the
                cavern.  We expect to use the other assets associated with the
                project, which include pipeline, compressors, base gas and other
                equipment
                and facilities, in conjunction with a replacement storage cavern
                to be
                developed.  If it is determined in the future that the assets
                cannot be used in conjunction with a new cavern, we may be required
                to
                record an additional impairment charge at the time that determination
                is
                made.  Additional costs to abandon the impaired cavern may be
                incurred due to regulatory or contractual obligations, however, the
                amounts are inestimable at this
                time.








**Distributions**





Note
      12 of the Notes to Condensed
      Consolidated Financial Statements in Item 1 of this Report contains information
      regarding our distributions.








**Liquidity
      and Capital Resources**





We
      are a
      limited partnership holding company and derive all of our operating cash flow
      from our operating subsidiaries. We use cash provided from our subsidiaries
      and,
      as needed, borrowings under our revolving credit facility to service our
      indebtedness and make distributions to unitholders and our general
      partner.





During
      the third quarter 2007, Gulf South sold $225.0 million of 5.75% senior unsecured
      notes due August 15, 2012, and $275.0 million of 6.30% senior unsecured notes
      due August 15, 2017. We received net proceeds of approximately $495.3 million
      after deducting initial purchaser discounts and offering expenses of $4.7
      million.  The proceeds will primarily be used to fund capital
      expenditures associated with our expansion projects.





As
      of
      September 30, 2007, and December 31, 2006, no funds were drawn under our $700
      million revolving credit facility.  However, at September 30, 2007, we
      had outstanding letters of credit under the facility for $221.5 million to
      support certain obligations associated with the Fayetteville Shale and Gulf
      Crossing expansion projects which reduced the available capacity under the
      facility by such amount.





During
      the third quarter 2007, we began investing our cash and cash equivalents in
      U.S.
      Government securities, primarily Treasury notes, under repurchase agreements.
      Generally, we have engaged in overnight repurchase transactions where purchased
      securities are sold back to the counterparty the following business
      day.  Pursuant to the master repurchase agreements, we take actual
      possession of the purchased securities.  In the event of default by
      the counterparty under the agreement, the repurchase would be deemed immediately
      to occur and we would be entitled to sell the securities in the open market,
      or
      give the counterparty credit based on the market price on such date, and apply
      the proceeds (or deemed proceeds) to the aggregate unpaid repurchase amounts
      and
      any other amounts owing by the counterparty.  Note 8 of the Notes to
      Condensed Consolidated Financial Statements in Item 1 of this Report contains
      more information about our investments under the program.








**Changes
      in cash flow from operating activities**





Net
      cash
      provided by operating activities increased $43.9 million, or 23.8%, to $228.7
      million for the nine months ended September 30, 2007, compared to $184.8 million
      for the comparable 2006 period, primarily due to:





·
            $44.1
                million improvement in net income, excluding non-cash items such
                as
                depreciation and amortization and the Magnolia impairment
                charge;


·
            $21.9
                million increase in cash due to gas purchases of imbalance gas made
                in
                2006; and


·
            $18.0
                million increase in cash due to the timing of
                expenditures.





These
      increases were partly offset by:





·
            $32.9
                million reduction in cash due to recognition of deferred income related
                to
                PAL services..





24





**Changes
      in cash flow from investing activities**





Net
      cash
      used in investing activities increased $1.1 billion to $1.2 billion for the
      nine
      months ended September 30, 2007, compared to $115.9 million for the comparable
      2006 period, primarily due to:





·
            $564.0
                million increase in capital expenditures mainly for our expansion
                projects; and


·
            $540.0
                million increase in purchases of short-term
                investments.








**Changes
      in cash flow from financing activities**





Net
      cash
      provided by (used in) financing activities increased $715.7 million to $638.6
      million for the nine months ended September 30, 2007, compared to a use of
      $77.1
      million for the comparable 2006 period, primarily due to:





·
            $293.8
                million in net proceeds from the sale of 8,000,000 units and related
                general partner capital contribution in March 2007;
                and


·
            $495.3
                million in net proceeds from the issuance of long term debt at Gulf
                South.





These
      increases were partly offset by:





·
            $55.5
                million increase in cash distributions to unitholders and the general
                partner.








**Contractual
      Obligations**





The
      table below is updated for
      significant changes in capital commitments from those included in the 2006
      Annual Report on Form 10-K by period  (in millions):








**Payments
                due by Period****Total**
            
            
            **Less than**
              **1
                Year**
            
            
            **1-3 Years**
            
            
            **4-5 Years**
            
            
            **More than**
              **5
                Years**Capital
                commitments
            
            $
            900.4
            
            
            $
            755.2
            
            
            $
            145.2
            
            
            $
            -
            
            
            $
            -





The
      capital commitments for construction were primarily related to the pipeline
      expansion projects. For further discussion of the expansion projects please
      read
      Note 5C *Expansion Projects* in the Notes to Condensed Consolidated
      Financial Statements included in Item 1.





**Off
      Balance Sheet Arrangements**




At
      September 30, 2007, we had no
      guarantees of off balance sheet debt to third parties, no debt obligations
      that
      contain provisions requiring accelerated payment of the related obligations
      in
      the event of specified levels of declines in credit ratings, and no other off
      balance sheet arrangements.








**Critical
      Accounting Policies and Estimates**





Certain
      amounts included in or affecting our condensed consolidated financial statements
      and related disclosures must be estimated, requiring us to make certain
      assumptions with respect to values or conditions that cannot be known with
      certainty at the time the financial statements are prepared. These estimates
      and
      assumptions affect the amounts we report for assets and liabilities and our
      disclosure of contingent assets and liabilities at the date of our financial
      statements. We evaluate these estimates on an ongoing basis, utilizing
      historical experience, consultation with third parties and other methods we
      consider reasonable. Nevertheless, actual results may differ significantly
      from
      our estimates. Any effects on our business, financial position or results of
      operations resulting from revisions to these estimates are recorded, disclosed
      or both, depending on the circumstances, in the period in which the facts that
      give rise to the revision become known.





25


At
      June 30, 2007, the carrying value of
      our Magnolia storage expansion project was tested for impairment.  As
      a result of the impairment test, we recognized a $14.7 million impairment charge
      representing the carrying value of the storage cavern.  In determining
      that the fair value of the cavern was zero, estimates and assumptions were
      made
      regarding the cash flows associated with the storage cavern disposal through
      sale or abandonment.  Certain costs remain inestimable related to
      potential regulatory or contractual obligations associated with abandonment
      of
      the storage cavern.  We believe that alternative uses for the storage
      cavern may be possible in the hands of a third-party, and will pursue these
      options with the lessor, however, we have assumed no future cash flows related
      to these options in our impairment analysis.  In assessing the
      carrying value of the other associated facilities which include pipeline,
      compressors, base gas and other equipment and facilities, we assumed that the
      facilities would be used in conjunction with a replacement storage cavern to
      be
      developed.  Our expected cash flows related to the other facilities
      include the cost of developing a new cavern and revenues from the sale of
      storage services to third-parties over the useful life of the
      asset.  If storage spreads were to compress appreciably or significant
      difficulties were to arise in the development of the cavern, the actual cash
      flows could differ materially from the expected cash flows used in assessing
      the
      carrying value of the facilities.  If it is determined in the future
      that the assets cannot be used in conjunction with a new cavern, we may be
      required to record an additional impairment charge at the time that
      determination is made.





During
      the nine months ended September
      30, 2007, there were no significant changes to our critical accounting policies,
      judgments or estimates disclosed in our Annual Report on Form 10-K for the
      year ended December 31, 2006.








**Forward-Looking
      Statements**





Investors
      are cautioned that certain
      statements contained in this report as well as some statements in periodic
      press
      releases and some oral statements made by our officials and our subsidiaries
      during presentations about us, are “forward-looking” statements. Forward-looking
      statements include, without limitation, any statement that may project, indicate
      or imply future results, events, performance or achievements, and may contain
      the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will
      likely result,” and similar expressions. In addition, any statement concerning
      future financial performance (including future revenues, earnings or growth
      rates), ongoing business strategies or prospects, and possible actions by our
      partnership or its subsidiaries, which may be provided by management, are also
      forward-looking statements.





Forward-looking
      statements are based on
      current expectations and projections about future events and are inherently
      subject to a variety of risks and uncertainties, many of which are beyond our
      control that could cause actual results to differ materially from those
      anticipated or projected. These risks and uncertainties include, among
      others:





·
            We
                may not complete projects, including growth or expansion projects,
                that we
                commence, or we may complete projects on materially different terms
                including contracted volumes or timing than anticipated and we may
                not be
                able to achieve the intended benefits of any such project, if
                completed.





·
            The
                successful completion, timing, cost, scope and future financial
                performance of our expansion projects could differ materially from
                our
                expectations due to availability of contractors, weather, untimely
                regulatory approvals or denied applications, delayed approvals by
                regulatory bodies, land owner opposition, the lack of adequate materials,
                labor difficulties, difficulties we may encounter with partners or
                potential partners, expansion cost higher than anticipated and numerous
                other factors beyond our control.





·
            We
                may not complete any future debt or equity financing transaction,
                including any sale of an equity interest in Gulf Crossing
                Pipeline.





·
            The
                gas transmission and storage operations of our subsidiaries are subject
                to
                rate-making policies and actions by the FERC or customers that could
                have
                an adverse impact on the rates we charge and the revenues we collect
                may
                not cover our full cost of operating our pipelines and a reasonable
                return.





·
            We
                are subject to laws and regulations relating to the environment and
                pipeline operations which may expose us to significant costs, liabilities
                and loss of revenues. Any changes in such regulations or their application
                could negatively affect our business, financial condition and results
                of
                operations.





·
            Our
                operations are subject to operational hazards and unforeseen interruptions
                for which we may not be adequately
                insured.





·
            The
                cost of insuring our assets may increase
                dramatically.





·
            Because
                of the natural decline in gas production from existing wells, our
                success
                depends on our ability to obtain access to new sources of natural
                gas,
                which is dependent on factors beyond our control. Any decrease in
                supplies
                of natural gas in our supply areas could adversely affect our business,
                financial condition and results of
                operations.





·
            Successful
                development of LNG import terminals in the eastern or northeastern
                United
                States could reduce the demand for our
                services.





26


·
            We
                may not be able to maintain or replace expiring gas transportation
                and
                storage contracts at favorable
                rates.





·
            Significant
                changes in natural gas prices could affect supply and demand, reducing
                system throughput and adversely affecting our
                revenues.





Developments
      in any of these areas
      could cause our results to differ materially from results that have been or
      may
      be anticipated or projected. Forward-looking statements speak only as of the
      date of this report and we expressly disclaim any obligation or undertaking
      to
      update these statements to reflect any change in our expectations or beliefs
      or
      any change in events, conditions or circumstances on which any forward-looking
      statement is based.





27





**Item
      3.  Quantitative and Qualitative Disclosures About
      Market Risk**





Our
      long-term debt is subject to
      interest rate risk. Total long-term debt at September 30, 2007, had a carrying
      value of $1.8 billion and a fair value of $1.8 billion. The weighted-average
      interest rate of our long-term debt was 5.82% at September 30,
      2007.





In
      August
      2007, we entered into a Treasury rate lock for a notional amount of $150.0
      million of principal to hedge the risk attributable to changes in the risk-free
      component of forward 10-year interest rates through February 1,
      2008.  The reference rate on the rate lock is 4.74%. Under the terms
      of the rate lock, the counterparty would pay us a settlement amount if the
      10-year Treasury rate is greater than the reference rate on February 1, 2008.
      Conversely, the Partnership would pay the counterparty a settlement amount
      if
      the 10-year Treasury rate is less than the reference rate.  A 10 basis
      point increase in the 10-year Treasury rate would result in a $1.2 million
      favorable change in the value of the rate locks. Conversely, a 10 basis point
      decrease in the 10-year Treasury rate would result in a $1.2 million unfavorable
      change in the value of the rate locks.  The Treasury rate lock was
      designated as a cash flow hedge in accordance with SFAS No. 133.  As
      of September 30, 2007, we recorded a payable of $1.6 million and a corresponding
      amount in Accumulated other comprehensive income for the fair value of the
      rate
      lock.





In
      August
      2006, we entered into Treasury rate locks with two counterparties each for
      a
      notional amount of $100.0 million of principal to hedge the risk attributable
      to
      changes in the risk-free component of forward 10-year interest rates through
      August 1, 2007. The reference rates on the rate locks were 5.00% and
      4.96%.  The rate locks were designated as cash flow hedges in
      accordance with SFAS No. 133.  In August 2007, the rate locks were
      settled resulting in payments to the counterparties of approximately $3.9
      million.  The effective amount of the hedge of approximately $3.4
      million, which was recorded in Accumulated other comprehensive income, will
      be
      amortized to interest expense over the 10-year term of the related notes which
      were issued in August 2007.





Certain
      volumes of our gas stored underground are available for sale and subject to
      commodity price risk. At September 30, 2007 and December 31, 2006, approximately
      $14.3 million and $14.0 million of gas stored underground at the Gulf South
      facilities, which we own and carry as current Gas stored underground, is exposed
      to commodity price risk.  We utilize derivatives to hedge certain
      exposures to market price fluctuations on the anticipated operational sales
      of
      gas.





As
      a
      result of the approval of Phase II of the Western Kentucky storage expansion
      project, approximately 4.8 Bcf of gas stored underground with a book value
      of
      $11.3 million became available for sale. Approximately 3.0 Bcf of this gas
      is
      subject to forward sales agreements under which the ultimate sales price was
      determined in March 2007, based on the price of New York Mercantile Exchange
      (NYMEX) natural gas futures.  We entered into derivatives to hedge the
      price exposure related to the storage gas.  The derivatives associated
      with the volumes subject to forward sales agreements were designated as cash
      flow hedges during February 2007, concurrent with the designation of the forward
      sales agreements as normal sales and were settled in March 2007 when the sales
      price was determined.  Prior to the designation, these derivatives
      were marked to fair value through earnings along with the related forward sales
      agreements, resulting in a loss of $0.1 million in the first quarter
      2007.  The derivatives related to the remaining 1.8 Bcf of storage gas
      were not designated as cash flow hedges in accordance with SFAS No. 133 and
      have
      been marked to fair value through earnings. In the third quarter 2007,
      approximately 0.9 Bcf of this gas was sold and the related derivatives were
      settled, resulting in a gain of $4.4 million.  The gain is included in
      Net (gain) loss on disposal of operating assets and related contracts on the
      Condensed Consolidated Statements of Income.





In
      the
      second quarter 2007, we entered into natural gas price swaps to hedge exposure
      to prices associated with the purchase of 2.1 Bcf of natural gas to be used
      for
      line pack for our Gulf Crossing expansion project and the Southeast expansion
      project, approximately 1.3 Bcf of which remained outstanding at September 30,
      2007.  The derivatives were not designated as hedges in accordance
      with SFAS No. 133 and were marked to fair value through earnings resulting
      in a
      loss of $0.4 million and $1.1 million for the three and nine months ended
      September 30, 2007.  Changes in the fair value of the derivatives will be
      recognized in earnings each quarter until settlement.  The changes in
      the fair value of the gas purchased for line pack will not be recognized in
      earnings each quarter.  When the gas is purchased, the ultimate cost
      will be recorded to Property, Plant and Equipment along with the other capital
      components of the projects and recognized in earnings as the property is
      depreciated.  A $1.00 increase in the price of NYMEX natural gas
      futures, would result in the recognition of a $1.3 million gain in
      earnings.  Conversely, a $1.00 decrease would result in the
      recognition of a $1.3 million loss.





28


With
      the
      exception of the derivatives related to storage gas volumes and line pack gas
      purchases referred to above, the derivatives related to the sale or purchase
      of
      natural gas, cash for fuel reimbursement and debt issuance generally qualify
      for
      cash flow hedge accounting under SFAS No. 133 and are designated as
      such.  The effective component of related unrealized gains and losses
      resulting from changes in fair values of the derivatives contracts designated
      as
      cash flow hedges are deferred as a component of Accumulated other comprehensive
      income.  The deferred gains and losses are recognized in the Condensed
      Consolidated Statements of Income when the anticipated transactions affect
      earnings.  Generally, for gas sales and cash for fuel reimbursement,
      any gains and losses on the related derivatives would be recognized in Operating
      Revenues.  For the sale of gas related to the Western Kentucky storage
      expansion project, any gains and losses on the related derivatives would be
      recognized in Net (gain) on disposal of operating assets and related
      contracts.  Any gains and losses on the derivatives related to the
      line pack gas purchases would be recognized in Miscellaneous other income,
      net.





The
      changes in fair values of the derivatives designated as cash flow hedges are
      expected to, and do, have a high correlation to changes in value of the
      anticipated transactions.  Each reporting period we measure the
      effectiveness of the cash flow hedge contracts.  To the extent the
      changes in the fair values of the hedge contracts do not effectively offset
      the
      changes in the estimated cash flows of the anticipated transactions, the
      ineffective portion of the hedge contracts is currently recognized in
      earnings.  If the anticipated transactions are deemed no longer
      probable to occur, hedge accounting would be terminated and changes in the
      fair
      values of the associated derivative financial instruments would be recognized
      currently in earnings.





We
      are
      exposed to credit risk relating to the risk of loss resulting from the
      nonperformance by a customer of its contractual obligations. Our exposure
      generally relates to receivables for services provided, as well as volumes
      owed
      by customers for imbalances or gas lent by us to them, generally under PAL
      and
      no-notice service (NNS). We maintain credit policies intended to minimize credit
      risk and actively monitor these policies.  Natural gas price volatility has
      increased dramatically in recent years, which has materially increased credit
      risk related to gas loaned to customers. As of September 30, 2007, the amount
      of
      gas loaned out by our subsidiaries was approximately 6.6 trillion British
      thermal units (TBtu) and, assuming an average market price during September
      2007
      of $5.86 per million British thermal units (MMBtu), the market value of gas
      loaned out at September 30, 2007 would have been approximately $38.7 million.
      As
      of December 31, 2006, the amount of gas loaned out by our subsidiaries was
      approximately 15.1 TBtu and, assuming an average market price during December
      2006 of $6.81 per MMBtu, the market value of gas loaned out at December 31,
      2006
      would have been approximately $102.8 million.  If any significant
      customer of ours should have credit or financial problems resulting in a delay
      or failure to repay the gas they owe to us, this could have a material adverse
      effect on our financial condition, results of operations and cash
      flows.





As
      of September 30, 2007, our cash
      equivalents were invested primarily in Treasury notes under repurchase
      agreements.  Due to the short-term nature and type of our investments,
      a hypothetical 10% increase in interest rates would not have a material effect
      on the fair market value of our portfolio. Since we have the ability to
      liquidate this portfolio, we do not expect our Condensed Consolidated Statements
      of Income or Cash Flows to be materially affected by the effect of a sudden
      change in market interest rates on our investment portfolio.





29


**Item
      4.  Controls and Procedures**





We
      maintain a system of disclosure controls and procedures which are designed
      to
      ensure that information required to be disclosed in reports filed or submitted
      under the federal securities laws, including this report, is recorded,
      processed, summarized and reported on a timely basis.  These
      disclosure controls and procedures are designed to ensure that information
      required to be disclosed under the federal securities laws is accumulated and
      communicated to management on a timely basis to allow assessment of required
      disclosures.





Our
      principal executive officer and
      principal financial officer have conducted an evaluation of the disclosure
      controls and procedures as of the end of the period covered by this
      report.  Based on this evaluation, the principal executive officer and
      principal financial officer have each concluded that the disclosure controls
      and
      procedures are effective.





There
      was
      no change in our internal control over financial reporting identified in
      connection with the foregoing evaluation that occurred during the nine months
      ended September 30, 2007, that has materially affected, or is reasonably likely
      to materially affect, our internal control over financial
      reporting.























30


**PART
      II – OTHER INFORMATION**








**Item
      1.  Legal
      Proceedings**




For
      a discussion of certain of our
      current legal proceedings, please read Note 5 of the Notes to Condensed
      Consolidated Financial Statements in Item 1 of this Report.








**Item****1
      A.  Risk
      Factors**





*The
      following discussion supplements
      the Risk Factors in Item 1A “Risk Factors” of our Annual Report on Form 10-K for
      the year ended December 31, 2006.*








***We
      have adopted certain valuation methodologies that may result in a shift of
      income, gain, loss and deduction between the general partner and the
      unitholders.  The IRS may challenge this treatment, which could
      adversely affect the value of the common units.***




When
      we
      issue additional units or engage in certain other transactions, we determine
      the
      fair market value of our assets and allocate any unrealized gain or loss
      attributable to our assets to the capital accounts of our unitholders and our
      general partner.  Our methodology may be viewed as understating the
      value of our assets.  In that case, there may be a shift of income,
      gain, loss and deduction between certain unitholders and the general partner,
      which may be unfavorable to such unitholders.  Moreover, subsequent
      purchasers of common units may have a greater portion of their Internal Revenue
      Code Section 743(b) adjustment allocated to our tangible assets and a lesser
      portion allocated to our intangible assets.  The IRS may challenge our
      valuation methods, or our allocation of the Section 743(b) adjustment
      attributable to our tangible and intangible assets, and allocations of income,
      gain, loss and deduction between the general partner and certain of our
      unitholders.





A
      successful IRS challenge to these methods or allocations could adversely affect
      the amount of taxable income or loss being allocated to our unitholders. It
      also
      could affect the amount of gain from our unitholders’ sale of common units and
      could have a negative impact on the value of the common units or result in
      audit
      adjustments to our unitholders’ tax returns without the benefit of additional
      deductions.








***Our
      natural gas transportation, gathering and storage operations are subject to
      FERC
      rate-making policies that could have an adverse impact on our ability to
      establish rates that would allow us to recover the full cost of operating our
      pipelines including a reasonable return and our ability to service our
      debt.***




Action
      by
      the FERC on currently pending matters as well as matters arising in the future
      could adversely affect our ability to establish rates, or to charge rates that
      would cover future increases in our costs, or even to continue to collect rates
      that cover current costs, including a reasonable return.  We cannot
      make assurances that we will be able to recover all of our costs through
      existing or future rates. An adverse determination in any future rate proceeding
      brought by or against Texas Gas or Gulf South could have a material adverse
      effect on our business, financial condition and results of operations that
      could
      have an adverse impact on our ability to service our debt.




On
        July 20, 2004, the United
        States Court of Appeals for the District of Columbia Circuit (D.C. Circuit)
        issued its opinion in *BP West Coast Products, LLC v. FERC (BP West
        Coast)* and vacated the portion of the FERC’s decision applying the FERC’s
*Lakehead* policy to determine an allowance for income taxes in the
        regulated cost of service. In its *Lakehead*decision, the FERC allowed
        an oil pipeline limited partnership to include in its cost of service an
        income
        tax allowance to the extent that its unitholders were corporations subject
        to
        income tax. In May and June 2005, the FERC issued a statement of general
        policy
        and an order on remand of *BP West Coast*, respectively, in which the
        FERC stated it will permit pipelines to include in cost-of-service an income
        tax
        allowance to reflect actual or potential tax liability on their public utility
        income attributable to all partnership or limited liability company interests,
        if the ultimate owner of the interest has an actual or potential income tax
        liability on such income. Whether a pipeline’s owners have such actual or
        potential income tax liability will be reviewed by the FERC on a case-by-case
        basis. Although the new policy is generally favorable for pipelines that
        are
        organized as pass-through entities, it still entails risk due to the
        case-by-case review requirement. On December 16, 2005, the FERC issued a
        case-specific review of the income tax allowance issue in the *SFPP,
        L.P.* proceeding. The FERC ruled favorably to SFPP, L.P. on all income tax
        issues and set forth guidelines regarding the type of evidence necessary
        for the
        pipeline to establish its income tax allowance. The FERC’s *BP West
        Coast* remand decision, the new income tax allowance policy, and the
        December 16, 2005 order were appealed to the D.C. Circuit. The D.C. Circuit
        issued an order on May 29, 2007, in which it denied these appeals and fully
        upheld FERC’s new income tax allowance policy and the application of that policy
        in the December 16, 2005 order. On August 20, 2007, the D.C. Circuit denied
        rehearing of its decision. If the FERC were to change its income tax allowance
        policy in the future, such changes could materially and adversely impact
        the
        rates we are permitted to charge as future rates are approved for our interstate
        transportation services.


31


On
      December 8, 2006, FERC issued an order in an interstate oil pipeline proceeding
      addressing its income tax allowance policy, noting that the tax deferral
      features of a publicly traded partnership may cause some investors to receive,
      for some indeterminate duration, cash distributions in excess of their taxable
      income, which FERC characterized as a “tax savings.”  FERC stated that
      it is concerned that this creates an opportunity for those investors to earn
      an
      additional return, funded by ratepayers.  Responding to this concern,
      FERC chose to adjust the pipeline’s equity rate of return downward based on the
      percentage by which the publicly traded partnership’s cash flow exceeded taxable
      income.  On February 7, 2007, the pipeline asked FERC to
      reconsider this ruling.  On March 9, 2007, FERC granted rehearing for
      further consideration of its December 8, 2006 order.





If
      Texas Gas or Gulf South were to file
      a rate case or if we were to be required to defend our rates, we would be
      required to establish pursuant to the new policy that the inclusion of an income
      tax allowance in our cost of service was just and reasonable. To establish
      that
      our tax allowance is just and reasonable, our general partner may elect to
      require owners of  our units to recertify their status as being
      subject to United States federal income taxation on the income generated by
      Texas Gas or Gulf South or we may attempt to provide other evidence. We can
      provide no assurance that the evidence that we will be able to provide
      (including the information the general partner may require in the certification
      and recertification process) will be sufficient to establish that its
      unitholders, or its unitholders’ owners, are subject to United States federal
      income taxation on the income generated by Texas Gas or Gulf South. If we are
      unable to establish that the master partnership’s unitholders, or its
      unitholders’ owners, incur actual or potential income tax liability on the
      income generated by us, the FERC could disallow a substantial portion of Texas
      Gas’ or Gulf South’s income tax allowance. If the FERC were to disallow a
      substantial portion of Texas Gas’ or Gulf South’s income tax allowance, it is
      likely that the level of maximum lawful rates could decrease from current
      levels.





***The
      outcome of certain FERC proceedings involving FERC policy statements is
      uncertain and could affect the level of return on equity that the Partnership
      may be able to achieve in any future rate proceeding.***





In
      an effort to provide some guidance
      and to obtain further public comment on FERC’s policies concerning return on
      equity determinations, on July 19, 2007, FERC issued its Proposed Proxy Policy
      Statement, *Composition of Proxy Groups for Determining Gas and Oil Pipeline
      Return on Equity*.  In the Proposed Proxy Policy Statement, FERC
      proposes to permit inclusion of publicly traded partnerships in the proxy group
      analysis relating to return on equity determinations in rate proceedings,
      provided that the analysis be limited to actual publicly traded partnership
      distributions capped at the level of the pipeline’s earnings and that evidence
      be provided in the form of multiyear analysis of past earnings demonstrating
      a
      publicly traded partnership’s ability to provide stable earnings over
      time.





In
      a
      decision issued shortly after FERC issued its Proposed Proxy Policy Statement,
      the D.C.Circuit vacated FERC’s orders in proceeding involving *High Island
      Offshore System*and *Petal Gas Storage.*  The Court
      determined that FERC had failed to adequately reflect risks of interstate
      pipeline operations both in populating the proxy group (from which a range
      of
      equity returns was determined) with entities the record indicated had lower
      risk, while excluding publicly traded partnerships primarily engaged in
      interstate pipeline operations, and in the placement of the pipeline under
      review in each proceeding within that range of equity
      returns.  Although the Court accepted for the sake of argument FERC’s
      rationale for excluding publicly traded partnerships from the proxy group (i.e.,
      publicly traded partnership distributions may exceed earnings) it observed
      this
      proposition was “not self-evident.”





The
      ultimate outcome of these proceedings is not certain and may result in new
      policies being established at FERC that would not allow the full use of publicly
      traded partnership distributions to unitholders in any proxy group comparisons
      used to determine return on equity in future rate proceedings.  The
      Partnership cannot ensure that such policy developments would not adversely
      affect the Partnership’s ability to achieve a reasonable level of return on
      equity in any future rate proceeding.





***The
      tax treatment of publicly traded partnerships or an investment in our common
      units could be subject to potential legislative, judicial or administrative
      changes and differing interpretations, possibly on a retroactive
      basis.***





The
      present federal income tax treatment of publicly traded partnerships, including
      us, or an investment in our common units may be modified by legislative,
      judicial, or administrative changes and differing interpretations at any time.
      Any modification to the federal income tax laws and interpretations thereof
      may
      or may not be applied retroactively. Members of Congress are considering
      substantive changes to the existing U.S. tax laws that affect certain publicly
      traded partnerships. Although the currently proposed legislation would not
      appear to affect our tax treatment as a partnership, we are unable to
      predict whether any of these changes, or other proposals, will ultimately be
      enacted. Any such changes could negatively impact the value of an investment
      in
      our common units.





32


***We
      prorate our items of income, gain, loss and deduction between transferors and
      transferees of our units each month based upon the ownership of our units on
      the
      first day of each month, instead of on the basis of the date a particular unit
      is transferred. The IRS may challenge this treatment, which could change the
      allocation of items of income, gain, loss and deduction among our
      unitholders.***





We prorate our items of income, gain, loss and deduction between
      transferors and transferees of our units each month based upon the ownership
      of
      our units on the first business day of each month, instead of on the basis
      of
      the date a particular unit is transferred. The use of this proration method
      may
      not be permitted under existing Treasury Regulations, and, accordingly, our
      counsel is unable to opine as to the validity of this method. If the IRS were
      to
      challenge this method or new Treasury Regulations were issued, we may be
      required to change the allocation of items of income, gain, loss and deduction
      among our unitholders.








33





**Item
      6.  Exhibits**








Exhibit
                Designation
            
            Nature
                of Exhibit31.1*
            
            Certification
                of Rolf A. Gafvert, Chief Executive Officer, pursuant to Section
                302 of
                the Sarbanes-Oxley Act of 2002.31.2*
            
            Certification
                of Jamie L. Buskill, Chief Financial Officer, pursuant to Section
                302 of
                the Sarbanes-Oxley Act of 2002.32.1*
            
            Certification
                of Rolf A. Gafvert, Chief Executive Officer, pursuant to Section
                906 of
                the Sarbanes-Oxley Act of 2002.32.2*
            
            Certification
                of Jamie L. Buskill, Chief Financial Officer, pursuant to Section
                906 of
                the Sarbanes-Oxley Act of 2002.








*
      Filed
      herewith


34


**SIGNATURES**





Pursuant
      to the requirements of the
      Securities Exchange Act of 1934, the registrant has duly caused this report
      to
      be signed on its behalf by the undersigned thereunto duly
      authorized.





**Boardwalk
                Pipeline Partners, LP**By:
                Boardwalk GP, LPits
                general partnerBy:
                Boardwalk GP, LLCits
                general partnerDated:
                October 30, 2007
            
            
            By:
            */s/
                Jamie L. Buskill*Jamie
                L. BuskillChief
                Financial Officer

















35