**UNITED
        STATES**
 **SECURITIES
        AND EXCHANGE COMMISSION**
 **WASHINGTON,
        D.C. 20549**
 
 **FORM
        10-Q**
 
 (Mark
        One)
 
 **x**  **QUARTERLY
        REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
        1934**
 
 For
        the
        quarterly period ended September 30, 2006
 
 or
 
 **o**  **TRANSITION
        REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
        1934** **** ****
 
 For
        the
        transition period from _______________ to _______________
 
  
 *Commission
                  file number: 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***(Address
                  of principal executive office)***(270)
                  926-8686***(Registrant’s
                  telephone number, including area code
                  )*
 
 
 Indicate
        by check mark whether the registrant (1) has filed all reports required to
        be
        filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
        the
        preceding 12 months (or for such shorter period that the registrant was required
        to file such reports), and (2) has been subject to such filing requirements
        for
        the past 90 days.        Yes x No  ̈
 
 Indicate
        by check mark whether the registrant 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 o      Accelerated
        filer  ̈     Non-accelerated
        filer x
 
 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 27, 2006, the registrant had 68,256,122 common units outstanding
        and
        33,093,878 subordinated units outstanding.
 
 
  
  **TABLE
        OF CONTENTS**
 **FORM
        10-Q**
 **SEPTEMBER
        30, 2006**
 **BOARDWALK
        PIPELINE PARTNERS, LP**
 
 
 **PART
        I - FINANCIAL INFORMATION**
  **Item
        1. Financial Statements**
  **Condensed
        Consolidated Balance Sheets**
  **Condensed
        Consolidated Statements Of Income**
  **Condensed
        Consolidated Statements Of Cash Flows**
  **Condensed
        Consolidated Statements Of Changes In Member’s Equity And Partners’ Capital And
        Comprehensive Income**
  **Notes
        To Condensed Consolidated Financial Statements**
  **Item
        2. Management’s Discussion And Analysis Of Financial Condition And Results Of
        Operations**
  **Item
        3. Quantitative And Qualitative Disclosures About Market
        Risk**
  **Item
        4. Controls And Procedures**
 
 **PART
        II - OTHER INFORMATION**
 
  **Item
        1. Legal Proceedings**
  **Item
        1 A. Risk Factors**
  **Item
        6. Exhibits**
  2
  **PART
        I - FINANCIAL INFORMATION**
  **Item
        1. Financial
        Statements**
  
 
 **BOARDWALK
        PIPELINE PARTNERS, LP**
  **CONDENSED
        CONSOLIDATED BALANCE
        SHEETS**
  **** **(Thousands
        of Dollars)**
 **(Unaudited)**
 
 
 **ASSETS**
              
              **September
                  30, 2006**
              
              **December
                  31, 2005**Current
                  Assets:Cash
                  and cash equivalents
              
              $
              57,560
              
              $
              65,792Receivables,
                  net:Trade
              
              
              45,356
              
              
              59,115Other
              
              
              6,655
              
              
              5,564Gas
                  receivables:Transportation
                  and exchange
              
              
              8,172
              
              
              29,557Storage
              
              
              306
              
              
              12,576Inventories
              
              
              14,148
              
              
              15,881Costs
                  recoverable from customers
              
              
              9,665
              
              
              3,560Gas
                  stored underground
              
              
              15,063
              
              
              6,500Prepaid
                  expenses and other current assets
              
              
              21,288
              
              
              7,720Total
                  current assets
              
              
              178,213
              
              
              206,265Property,
                  Plant and Equipment:Natural
                  gas transmission plant
              
              
              1,897,774
              
              
              1,772,483Other
                  natural gas plant
              
              
              212,857
              
              
              213,1362,110,631
              
              
              1,985,619Less—accumulated
                  depreciation and amortization
              
              
              169,204
              
              
              118,213Property,
                  plant and equipment, net
              
              
              1,941,427
              
              
              1,867,406Other
                  Assets:Goodwill
              
              
              163,474
              
              
              163,474Gas
                  stored underground
              
              
              169,523
              
              
              169,177Costs
                  recoverable from customers
              
              
              35,095
              
              
              43,960Other
              
              
              16,165
              
              
              15,209Total
                  other assets
              
              
              384,257
              
              
              391,820Total
                  Assets
              
              $
              2,503,897
              
              $
              2,465,491The
                  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, 2006**
              
              **December
                  31, 2005**Current
                  Liabilities:Payables:Trade
              
              $
              21,084
              
              $
              20,433Other
              
              
              14,547
              
              
              3,681Gas
                  payables:Transportation
                  and exchange
              
              
              13,494
              
              
              14,710Storage
              
              
              36,091
              
              
              27,559Accrued
                  taxes other
              
              
              23,118
              
              
              16,004Accrued
                  interest
              
              
              14,045
              
              
              17,996Accrued
                  payroll and employee benefits
              
              
              20,561
              
              
              29,028Current
                  note payable
              
              
              -
              
              
              42,100Other
                  current liabilities
              
              
              44,510
              
              
              30,776Total
                  current liabilities
              
              
              187,450
              
              
              202,287Long-Term
                  Debt
              
              
              1,161,896
              
              
              1,101,290Other
                  Liabilities and Deferred Credits:Postretirement
                  benefits
              
              
              42,499
              
              
              32,413Asset
                  retirement obligations
              
              
              14,680
              
              
              14,074Provision
                  for other asset retirements
              
              
              39,962
              
              
              33,212Other
              
              
              27,865
              
              
              93,541Total
                  other liabilities and deferred credits
              
              
              125,006
              
              
              173,240Commitments
                  and Contingencies (Note 5)
              
              
              -
              
              
              -Partners’
                  Capital:Common
                  units - 68,256,122 issued and outstanding
              
              
              730,211
              
              
              705,609Subordinated
                  units - 33,093,878 issued and outstanding
              
              
              278,500
              
              
              266,578General
                  partner
              
              
              17,406
              
              
              16,661Accumulated
                  other comprehensive income (loss)
              
              
              3,428
              
              
              (174
              )Total
                  partners’ capital
              
              
              1,029,545
              
              
              988,674Total
                  Liabilities and Partners’ Capital
              
              $
              2,503,897
              
              $
              2,465,491
 
 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,****2006**
              
              **2005**
              
              **2006**
              
              **2005**Operating
                  Revenues:Gas
                  transportation
              $
                  108,195
              $
                  111,181
              $
                  364,597
              $
                  347,953Parking
                  and lending
              9,099
              3,081
              32,030
              16,157Gas
                  storage
              8,321
              5,314
              25,136
              15,546Other
              7,430
              1,339
              14,390
              9,904Total
                  operating revenues
              133,045
              120,915
              436,153
              389,560Operating
                  Costs and Expenses:Operation
                  and maintenance
              39,740
              51,635
              114,901
              119,262Administrative
                  and general
              23,878
              22,533
              74,111
              60,512Depreciation
                  and amortization
              18,888
              18,092
              56,298
              53,152Taxes
                  other than income taxes*
              6,592
              6,409
              18,607
              20,968Net
                  (gain) loss on disposal of operating assets
              (826)
              1,228
              (3,032)
              1,713Total
                  operating costs and expenses
              88,272
              99,897
              260,885
              255,607Operating
                  Income
              44,773
              21,018
              175,268
              133,953Other
                  (Income) Deductions:Interest
                  expense
              14,977
              14,985
              45,822
              44,722Interest
                  income
              (553)
              (353)
              (1,796)
              (1,098)Interest
                  income from affiliates, net
              (10)
              (772)
              (16)
              (1,729)Miscellaneous
                  other income, net
              (406)
              (443)
              (1,383)
              (1,179)Total
                  other (income) deductions
              14,008
              13,417
              42,627
              40,716Income
                  before income taxes
              30,765
              7,601
              132,641
              93,237Income
                  taxes and charge-in-lieu of income taxes*
              118
              3,047
              364
              37,121Net
                  Income*
              $
                  30,647
              $
                  4,554
              $
                  132,277
              $
                  56,116
 
 *Results
                  of operations reflect a change in the tax status associated with
                  Boardwalk
                  Pipeline Partners coincident with its initial public offering and
                  conversion to an MLP on November 15, 2005. Boardwalk Pipeline Partners
                  recorded a charge-in-lieu of income taxes and certain state franchise
                  taxes for the three and nine month periods ended September 30,
                  2005, and
                  each period thereafter through the date of the offering. A subsidiary
                  of
                  Boardwalk Pipeline Partners directly incurs some income-based state
                  taxes
                  following the date of the offering.
 
 **For
                  the**
                **Three
                  Months Ended**
                **September
                  30, 2006**
              
              **For
                  the**
                **Nine
                  Months Ended**
                **September
                  30, 2006**Calculation
                  of limited partners’ interest in 2006 net income:Net
                  income to partners
              $
                  30,647
              
              $
                  132,277Less
                  general partner’s interest in net income
              613
              
              2,646Limited
                  partners’ interest in net income
              $
                  30,034
              
              $
                  129,631Basic
                  and diluted net income per limited partner unit:Common
                  units (See Note 6)
              $
                  0.35
              
              $
                  1.27Subordinated
                  units (See Note 6)
              $
                  0.19
              
              $
                  1.27Cash
                  distribution to common and subordinated unitholders and general
                  partner
                unit
                  equivalents
              $0.38
              
              $0.92Weighted-average
                  number of limited partner units outstanding:Common
                  units
              68,256,122
              
              68,256,122Subordinated
                  units
              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,****2006**
              
              **2005**
  OPERATING
                  ACTIVITIES:Net
                  income
              $
                  132,277
              $
                  56,116Adjustments
                  to reconcile to cash provided from (used in) operations:Depreciation
                  and amortization
              56,298
              53,152Amortization
                  of acquired executory contracts
              (3,236)
              (7,793)(Gain)
                  loss on disposal of operating assets
              (3,032)
              1,713Provision
                  for deferred income taxes
              87
              50,550Changes
                  in operating assets and liabilities:Receivables
              47,291
              38,264Inventories
              1,733
              (573)Affiliates
              (175)
              (671)Other
                  current assets
              (20,560)
              (2,897)Accrued
                  income taxes
              69
              (13,436)Payables
                  and accrued liabilities
              17,335
              9,031Other,
                  including changes in noncurrent assets and liabilities
              (43,227)
              (23,774)Net
                  cash provided by operating activities
              184,860
              159,682INVESTING
                  ACTIVITIES:Capital
                  expenditures, net
              (120,209)
              (50,440)Insurance
                  and other recoveries
              4,960
              -Advances
                  to affiliates, net
              (723)
              (27,795)Net
                  cash used in investing activities
              (115,972)
              (78,235)FINANCING
                  ACTIVITIES:Payment
                  of short-term debt
              (42,100)
              -Proceeds
                  from long-term debt
              60,000
              569,369Payment
                  of long-term debt
              -
              (575,000)Distributions
                  paid
              (95,021)
              (65,000)Capital
                  contribution from parent
              -
              6,684Net
                  cash used in financing activities
              (77,121)
              (63,947)Increase
                  (decrease) in cash and cash equivalents
              (8,232)
              17,500Cash
                  and cash equivalents at beginning of period
              65,792
              16,518Cash
                  and cash equivalents at end of period
              $
                  57,560
              $
                  34,018
 
 The
                  accompanying notes are an integral part of these condensed consolidated
                  financial statements.
  6
  **BOARDWALK
        PIPELINE PARTNERS, LP**
  **CONDENSED
        CONSOLIDATED STATEMENTS OF CHANGES IN********MEMBER’S
        EQUITY AND PARTNERS’ CAPITAL AND COMPREHENSIVE INCOME**
  **(Thousands
        of Dollars)**
 **(Unaudited)**
  **Paid-in
                  Capital**
              
              **Retained
                  Earnings**
              
              **Accumulated
                  Other**
                **Comprehensive
                  Income**
                **(Loss)**
              
              **Comprehensive
                  Income**
              
              **Common**
                **Units**
              
              **Subordinated
                  Units**
              
              **General**
                **Partner**
              
              **Total
                  Member’s Equity and Partners’ Capital****Balance
                  January 1, 2005**
              $
                  1,071,651
              $ 21,276
              -
              -
              -
              -
              -
              $
                  1,092,927Add
                  (deduct):Net
                  income
              -
              56,116
              -
              $ 56,116
              -
              -
              -
              56,116Capital
                  contribution
              6,684
              -
              -
              -
              -
              -
              -
              6,684Distributions
                  paid
              -
              (65,000)
              -
              -
              -
              -
              -
              (65,000)Other
                  comprehensive (loss), net of tax
              -
              -
              $  (1,578)
              (1,578)
              -
              -
              -
              (1,578)Comprehensive
                  income
              
              
              
              $ 54,538**Balance,
                  September 30, 2005**
              $
                  1,078,335
              $  12,392
              $  (1,578)
              
              -
              -
              -
              $
                  1,089,149**Balance
                  January 1, 2006**
              -
              -
              $  (174)
              -
              $
                  705,609
              $
                  266,578
              $
                  16,661
              $    
                  988,674Add
                  (deduct):Net
                  income
              -
              -
              -
              $
                  132,277
              87,303
              42,329
              2,645
              132,277Distributions
                  paid
              -
              -
              -
              -
              (62,714)
              (30,407)
              (1,900)
              (95,021)Other
                  comprehensive income
              -
              -
              3,602
              3,602
              -
              -
              -
              3,602Transaction
                  costs related to sale of common units
              -
              -
              -
              -
              13
              -
              -
              13Comprehensive
                  income
              
              
              
              $ 135,879**Balance
                  September 30, 2006**
              -
              -
              $ 3,428
              
              $
                  730,211
              $
                  278,500
              $
                  17,406
              $
                  1,029,545
 
 The
                  accompanying notes are an integral part of these condensed consolidated
                  financial statements.
 
 7
 **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
        in 2005 to own and operate the business conducted by Boardwalk Pipelines,
        LP
        (Boardwalk Pipelines) and its subsidiaries, Texas Gas Transmission, LLC (Texas
        Gas) and Gulf South Pipeline Company, LP (Gulf South). The Partnership is
        an
        85.5% owned subsidiary of Boardwalk Pipelines Holding Corp. (BPHC) which
        is
        wholly owned by Loews Corporation (Loews). The
        Partnership is engaged through its subsidiaries in the interstate transportation
        and storage of natural gas and operates
        in one reportable segment - the operation of interstate natural gas pipeline
        systems.
 
 The
        accompanying Condensed Consolidated Financial Statements of the Partnership
        were
        prepared in accordance with accounting principles generally accepted in the
        United States of America (GAAP) and i n
        the
        opinion of management, reflect all adjustments (consisting of only normal
        recurring accruals) necessary to present fairly the financial position as
        of
        September 30, 2006 and December 31, 2005, the results of operations for the
        three and nine months ended September 30, 2006 and 2005 and changes in cash
        flows. Reference is made to the Notes to Consolidated Financial Statements
        in
        the 2005 Annual Report on Form 10-K, which should be read in conjunction
        with
        these unaudited condensed consolidated financial statements.
 
 Net
        income for interim periods may not necessarily be indicative of results for
        the
        calendar year. All significant intercompany items have been eliminated in
        consolidation. Certain
        reclassifications have been made to the 2005 financial statements to conform
        to
        the 2006 presentation, primarily related to the presentation of parking and
        lending revenues and interest expense as separate line items on the
        Condensed Consolidated Statements of Income.
 
 In
        connection with the November 15, 2005 initial public offering of the Partnership
        (IPO), BPHC contributed all of the equity interests of Boardwalk
        Pipelines to the
        Partnership for limited partner and general partner units .
        This
        contribution was accounted for as a transfer of assets between entities under
        common control in accordance with Statement
        of Financial Accounting Standards (SFAS)
        No. 141, *Business
        Combinations* .
        Therefore, the consolidated results of Boardwalk Pipelines for the periods
        prior
        to the IPO have been presented in this report as the consolidated results
        of the
        Partnership.
 
 See
        Note
        4 of the Notes to Condensed Consolidated Financial Statements for additional
        information related to the change in income and franchise taxes.
 
  **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 regulatory treatment prescribed by the Federal
        Energy Regulatory Commission (FERC) and 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 valued at the historical cost of gas, and was $40.7 million
        and $33.6 million at September 30, 2006 and December 31, 2005, respectively.
        The
        Partnership does not reflect volumes held by Gulf South on behalf of others
        on
        its Condensed Consolidated Balance Sheets. As of September 30, 2006 and December
        31, 2005, Gulf South held 57.4 trillion British thermal units (TBtu) and
        32.9
        TBtu of gas owned by shippers, respectively, and had loaned 0.2 TBtu of gas
        to
        shippers as of December 31, 2005. No gas was loaned by Gulf South to shippers
        as
        of September 30, 2006. The average market price during September 2006 and
        December 2005 was $4.88 and $12.34 per one million British thermal units
        (MMBtu), respectively.
 
  **Note
        3: Derivative Financial Instruments**
   In
        accordance with the Partnership’s risk management policy, Gulf South utilizes
        natural gas futures, swaps and options contracts (collectively, derivatives)
        to
        hedge exposures to market price fluctuations for natural gas. These transactions
        include hedges of anticipated natural gas purchases and sales related to
        system
        operations, fuel reimbursement and management of company-owned storage capacity.
        Each of these types of transactions are performed by employees of Gulf South
        in
        furtherance of its performance of transportation and storage services in
        interstate commerce. The derivatives are reported at fair value in accordance
        with SFAS No. 133, *Accounting
        for Derivative Instruments and Hedging Activities,* as
        amended.
  On
        August
        1 and August 3, 2006, Boardwalk Pipelines entered into Treasury rate locks
        with
        two counterparties, each for a notional amount of $100 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
        Treasury rate locks were 5.00% and 4.96%. Under the terms of the Treasury
        rate
        locks, the counterparties would pay Boardwalk Pipelines settlement amounts
        if
        the 10-year Treasury rate was greater than the reference rates at August
        1,
        2007. Conversely, Boardwalk Pipelines would pay the counterparties settlement
        amounts if the 10-year Treasury rate was less than the reference rates. The
        Treasury rate locks are reported at fair value in accordance with SFAS No.
        133.
  The
        fair
        values of derivatives existing
        as of September 30, 2006 and December 31, 2005, were included in the following
        captions in the condensed consolidated financial statements (expressed in
        millions):
 
 **September
                  30, 2006**
              
              **December
                  31, 2005**Prepaid
                  expenses and other current assets
              $
                  10.2
              
              $
                  0.6Other
                  noncurrent assets
              0.6
              
              -Other
                  current liabilities
              6.4
              
              0.8Accumulated
                  other comprehensive income (loss)
              3.4
              
              (0.2)
 
 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. The derivatives related to the sale of natural
        gas and
        derivatives related to cash for fuel reimbursement generally qualify for
        cash
        flow hedge accounting under SFAS No. 133 and are designated as such. Similarly,
        t he
        Treasury rate locks are designated as a cash flow hedge of expected future
        interest payments in accordance with SFAS No. 133. The
        related unrealized gains and losses resulting from changes in the fair values
        of
        derivatives contracts designated as cash flow hedges are deferred as a component
        of Accumulated Other Comprehensive Income (Loss). For the cash flow hedges
        related to the sale of natural gas and fuel reimbursement, the deferred gains
        and losses are recognized in the Condensed Consolidated Statements of Income
        when the hedged anticipated purchases or sales affect earnings. For the Treasury
        rate locks, the
        balance of Accumulated Other Comprehensive Income (Loss) would be amortized
        to
        interest expense over the term corresponding with the related interest payments
        on the debt issue.
 
 The
        Partnership expects
        to reclassify $2.5 million of the credits currently recorded in Accumulated
        Other Comprehensive Income (Loss) to
        earnings by December 31, 2006. The
        amounts recorded in Accumulated Other Comprehensive Income (Loss) reflected
        in
        the Condensed Consolidated Balance Sheets and the Condensed Consolidated
        Statements of Changes in Member’s Equity and Partners’ Capital and Comprehensive
        Income were comprised of $8.9 million from cash flow hedges related to the
        sale
        of natural gas and fuel retained less the unrealized loss of $5.5 million
        associated with the Treasury rate locks.
 
 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 purchases or sales or, in the case of the Treasury rate locks,
        the change in the expected future interest payments, the ineffective portion
        of
        the hedge contracts is currently recognized in earnings. Less than $0.1 million
        of ineffectiveness was recorded during the three and nine month periods ended
        September 30, 2006. No ineffectiveness was recorded during the comparable
        2005
        periods. If the anticipated purchases, sales, debt issuances or other related
        transactions are deemed no longer probable to occur, hedge accounting would
        be
        terminated and the changes in the fair values of the associated derivative
        financial instruments would be recognized currently on the Condensed
        Consolidated Statements of Income.  No cash flow hedges were discontinued
        during the three and nine month periods ended September 30, 2006 and 2005.
 
 Derivatives
        related to the value of company-owned storage capacity and the purchase of
        operational gas for the East Texas and Mississippi pipeline expansion project
        during the second quarter 2006 were not designated as hedges in accordance
        with
        SFAS No. 133. The changes in the values of the derivatives were recognized
        currently in earnings. The Partnership recognized $0.9 million and $1.3 million
        of credits to earnings, respectively, for the three and nine months ended
        September 30, 2006 related to the change in fair values associated with the
        derivatives.
  8
  The
        activity affecting Accumulated
        Other Comprehensive Income (Loss), with
        respect to cash flow hedges included the following:
 **September
                  30,**For
                  the three months ended (expressed in thousands):
              **2006**
              
              **2005**
                **(net
                  of tax)**Net
                  unrealized gains (losses) on derivatives qualifying as cash flow
                  hedges at
                  the beginning of the period
              $   
                  4,640
              
              $   
                  (372)Unrealized
                  hedging gains (losses) arising during the period on derivatives
                  qualifying
                  as cash flow hedges
              1,328
              
              (1,877)Reclassification
                  adjustment transferred to net income
              (2,540)
              
              671Net
                  unrealized gains (losses) on derivatives qualifying as cash flow
                  hedges at
                  the end of the period
              $  
                  3,428
              
              $
                  (1,578)
 
 **September
                  30,**For
                  the nine months ended (expressed in thousands):
              **2006**
              
              **2005**
                **(net
                  of tax)**Net
                  unrealized losses on derivatives qualifying as cash flow hedges
                  at the
                  beginning of the period
              $   
                  (174)
              
              -Unrealized
                  hedging gains (losses) arising during the period on derivatives
                  qualifying
                  as cash flow hedges
              11,736
              
              $  
                   (2,424)Reclassification
                  adjustment transferred to net income
              (8,134)
              
              846Net
                  unrealized gains (losses) on derivatives qualifying as cash flow
                  hedges at
                  the end of the period
              $  
                  3,428
              
              $  
                  (1,578)
   **Note
        4: Income and Franchise Taxes**
  The
        Partnership is not a taxable entity for federal income tax purposes and 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 taxable income of
        its
        partners. The partners are required to pay federal income taxes and, in some
        cases, state and local income taxes on their share of taxable income.
 
 Prior
        to
        converting to a limited partnership on November 15, 2005, Boardwalk Pipelines’
taxable income was included in the consolidated federal income tax return
        of
        Loews, and Boardwalk Pipelines recorded a charge-in-lieu of income taxes
        pursuant to a tax sharing agreement with Loews. The tax sharing agreement
        required Boardwalk Pipelines to remit to Loews on a quarterly basis any federal
        income taxes as if it were filing a separate return. Boardwalk Pipelines
        and its
        subsidiaries were also included in the state franchise tax filings of BPHC.
        The
        franchise taxes were charged to, and recorded by, Boardwalk Pipelines and
        its
        subsidiaries pursuant to the companies’ tax sharing policy.
  Following
        the IPO, the Partnership and its subsidiaries no longer record a charge-in-lieu
        of income taxes or certain state franchise taxes incurred by BPHC and no
        longer
        participate in a tax sharing agreement with Loews or tax sharing policy with
        BPHC. A subsidiary of the Partnership directly incurs some income-based state
        taxes which are accrued as Income taxes and charge-in-lieu of 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 in and 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.
  The
        total
        cost to repair storm damages before insurance recoveries is not expected
        to
        exceed $20.0 million; however, repairs and system evaluations are ongoing.
        During the third quarter 2006, an additional $0.5 million was accrued related
        to
        ongoing Katrina-related expenditures. The combined remaining liability for
        both
        Hurricanes Katrina and Rita was $1.8 million as of September 30, 2006.
 
 In
        the
        first quarter 2006, the Partnership accrued estimated insurance proceeds
        of $2.7
        million related to Hurricane Katrina which represented the minimum amount
        of
        insurance proceeds that were probable of recovery. The Partnership will continue
        to pursue recovery of additional insurance proceeds related to Hurricane
        Katrina. In September 2006, the Partnership received confirmation from the
        insurance underwriters that a partial payment was approved for the Katrina
        claim. In addition, the Partnership is pursuing recovery of insurance proceeds
        related to Hurricane Rita, but no amount has been recorded.
  Although
        the Partnership does not currently anticipate that the overall impact of
        Hurricanes Katrina and Rita will have a material adverse effect upon its
        future
        financial condition, results of operations or cash flows, in light of the
        magnitude of the damage caused by the hurricanes and the enormity of the
        relief
        and reconstruction effort, some uncertainty remains as to the ultimate impact
        these hurricanes will have on the Partnership.
 
  **B.
        Legal Proceedings**
  
 ***Hurricane
        Katrina - Related Class Actions***
 
 Gulf
          South, along with at least eight other interstate pipelines and major natural
          gas producers, has been named in three Hurricane Katrina-related class
          action
          lawsuits filed in the United States District Court for the Eastern District
          of
          Louisiana (District Court). The lawsuits allege that the dredging of canals
          caused damage to the marshes and that undamaged marshes would have prevented
          all, or almost all, of the loss of life and destruction of property caused
          by
          Hurricane Katrina. The District Court has dismissed the first two lawsuits
          for
          failure to state a claim. The third case was filed after the motions to
          dismiss
          were filed but prior to the District Court’s ruling. A motion to dismiss has
          been filed in this third case, but has not been ruled upon. The Partnership
          is
          currently unable to estimate the ultimate outcomes of the 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. Two class action lawsuits
        were filed relating to this incident and were converted to individual actions.
        Several individual actions have been filed against Gulf South and other
        defendants by local residents and businesses. In addition, the lessor of
        the
        property has filed an affirmative claim against Gulf South in an action filed
        against the lessor by one of Gulf South’s insurers. 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 are in the early stages of
        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 *.*
  From
        the
        date of acquisition of Gulf South on December 29, 2004 through September
        30,
        2006, Gulf South has incurred $6.2 million for remediation costs, root cause
        investigation, and legal fees and had a liability balance at September 30,
        2006
        and December 31, 2005, of $0.3 million and $1.1 million, respectively, in
        Other
        current liabilities on the Condensed Consolidated Balance Sheets pertaining
        to
        this incident *.* Gulf
        South has made demand for reimbursement from its insurance carriers and will
        continue to pursue recoveries of the remaining expenses, 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. For the nine
        months ended September 30, 2006, Gulf South received $0.8 million of insurance
        reimbursements for legal expenses and root cause investigation. The range
        of
        loss related to this incident could not be estimated at September 30, 2006.
  ***Other
        Legal Matters***
  *Devon
        Energy
        Eugene Island Offshore Facilities Settlement* .
        In June
        2006, Gulf South received $4.0 million from Devon Energy in settlement of
        a
        lawsuit concerning the parties’ rights and obligations under a lease for a
        platform that Devon will decommission in the Eugene Island area in the Gulf
        of
        Mexico. The proceeds will be used to offset the costs of rebuilding certain
        offshore facilities. The total cost of the new facilities is not expected
        to
        exceed $8.0 million.
 
 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.
 
  9
   **C.
        Regulatory and Rate Matters**
   ***Expansion
        Projects***
  The
        Partnership is currently engaged in the following expansion
        projects:
 ·
              *Carthage
                  to Keatchie Loop*.
                  The Partnership has begun construction on a 20.5 mile segment of
                  42-inch
                  pipeline from Carthage, Texas to Keatchie, Louisiana. The capacity
                  of the
                  segment will be 120 MMcf per day and is expected to be in service
                  by the
                  end of November 2006.  ·
              *East
                  Texas and Mississippi Pipeline Expansion.*The
                  Partnership is pursuing a pipeline expansion project consisting
                  of 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 would add approximately 1.7 Bcf per
                  day of new
                  transmission capacity to the Gulf South pipeline system. The natural
                  gas
                  to be transported on this expansion will originate primarily from
                  the
                  Barnett Shale and Bossier Sands producing regions of East Texas.
                  The
                  expansion will transport natural gas to new interstate pipeline
                  interconnects in the Perryville, Louisiana area and existing pipeline
                  interconnects with other pipelines east of the Mississippi River.
                  This
                  expansion is supported by binding precedent agreements with customers
                  who
                  have contracted, on a long-term basis (with a weighted average
                  life of
                  approximately 7 years), for 1.3 Bcf with an option for an additional
                  100
                  MMcf of the approximately 1.7 Bcf per day capacity. On September
                  1, 2006,
                  Gulf South filed a certificate application relating to this project
                  with
                  FERC. Gulf South has ordered the pipeline and compression materials
                  needed
                  to construct this project. The Partnership expects this project
                  to be in
                  service during September 2007. The total cost of this expansion
                  and the
                  Carthage to Keatchie Loop is expected to be approximately $800
                  million. *·*
                *Western
                    Kentucky Storage Expansion.*The Partnership is pursuing a project to expand the working gas
                    capacity
                    in Texas Gas’ western Kentucky storage complex by approximately 9 Bcf.
                    This project is supported by binding commitments from customers
                    to
                    contract on a long-term firm basis for the full additional capacity
                    at
                    Texas Gas’ maximum applicable rate. On April 14, 2006, Texas Gas filed a
                    certificate application relating to this project with FERC. The
                    Partnership expects this project to cost approximately $36 million
                    and to
                    be in service during November 2007.
  ·
              *Magnolia
                  Storage Expansion*.
                  Gulf South has leased a gas storage facility near Napoleonville,
                  Louisiana, and is currently developing an additional storage cavern.
                  During recent mining operations, certain issues have arisen causing
                  the
                  mining of the caverns to be suspended. Gulf South has conducted
                  and is
                  continuing during the fourth quarter 2006 to conduct operational
                  integrity
                  tests on the caverns and associated facilities. If the test results
                  are
                  favorable, Gulf South expects the storage facilities to be in service
                  during 2009. If the test results are not favorable, management
                  will
                  consider the options it has available, including developing a new
                  cavern,
                  sale or abandonment of the project. The total book value of the
                  project at
                  September 30, 2006 was $42.2 million. The Partnership tests the
                  investment
                  in Magnolia for recoverability in accordance with the requirements
                  of SFAS
                  No. 144,*Accounting
                  for the Impairment or Disposal of Long-Lived Assets*.
                  No impairment loss has been recognized as a result of the recoverability
                  tests.
  ***General
        Rate Case***
  On June
        20, 2006 the settlement of Texas Gas’ general rate case became final. On June
        30, 2006, Texas Gas refunded approximately $6.6 million consisting of $6.4
        million in principal and $0.2 million of interest to its customers. The amount
        of the refund was accrued as a reduction to revenues and an increase to interest
        expense over the period from November 1, 2005 to the date of the refund.
        At
        December 31, 2005, the amount of the estimated liability for refund was
        approximately $5.0 million.
 
 Due
        to
        the settlement, in the first quarter 2006, Texas Gas began to amortize the
        balance of its regulatory asset for postretirement benefits other than pensions
        (PBOP).  The amortization of the remaining regulatory asset balance of
        approximately $27.2 million at September 30, 2006, will continue to be amortized
        on a straight-line basis over approximately five years.
 
  10
   ***Pipeline
        Integrity***
  On
        June 30, 2005, FERC issued an order addressing the accounting treatment for
        the
        costs pipeline operators will incur in implementing all aspects of pipeline
        integrity management programs which are required by the Office of Pipeline
        Safety. FERC’s accounting guidance became effective prospectively, beginning
        with integrity management costs incurred on or after January 1, 2006. Amounts
        capitalized in periods prior to January 1, 2006, were permitted to remain
        as
        recorded. The Partnership applied the accounting guidance order on January
        1,
        2006. There were no changes to the Partnership’s accounting policy for the
        pipeline integrity management programs as a result of the application of
        this
        guidance.
  **D.** **Environmental
        and Safety Matters**
  Texas
        Gas
        and Gulf South are subject to federal, state and local environmental laws
        and
        regulations in connection with the operation and remediation of various sites.
        When possible, the Partnership enters into voluntary remediation programs
        with
        the regulatory agencies. The Partnership accrues for environmental remediation
        expenses resulting from existing conditions that relate to past operations
        when
        the costs are probable and can be reasonably estimated. As of September 30,
        2006
        and December 31, 2005, the Partnership had an accrued liability of approximately
        $19 million and $20 million respectively, related to environmental
        remediation.
 
 The
        Partnership’s pipeline operations are subject to the Clean Air Act (CAA) and
        include two facilities in areas affected by non-attainment requirements for
        the
        current ozone standard (eight-hour standard), which are now in compliance.
        As of
        September 30, 2006, the Partnership had incurred costs of approximately $14
        million for emission control modifications of compression equipment located
        at
        facilities required to comply with current CAA provisions and state
        implementation plans for nitrogen oxide reductions. The costs were recorded
        as
        additions to Property, plant and equipment (PPE) as the modifications were
        added. If the Environmental Protection Agency (EPA) designates additional
        new
        non-attainment areas where the pipelines operate, the cost of additions to
        PPE
        would be expected to increase. The Partnership is unable at this time to
        estimate with any certainty the cost of any additions that may be required.
 
 On
        October 20, 2006, Texas Gas received notice from the 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, Marshall County, 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.
 
 In
        addition, the EPA promulgated new rules regarding hazardous air pollutants
        in
        2004, which will impose additional controls at four facilities at an estimated
        cost of $1.6 million. The effective compliance date for the hazardous air
        pollutants regulations is 2007. The Partnership anticipates installation
        of
        associated controls to meet these new regulations in 2006 and 2007.
 
 The
        Partnership considers environmental assessment, remediation costs and costs
        associated with compliance with environmental standards to be recoverable
        through its rates, as they are prudent costs incurred in the ordinary course
        of
        business. No regulatory asset has been recorded to defer these costs. The
        actual
        costs incurred will depend on the amount and extent of contamination discovered,
        the final cleanup standards mandated by the EPA or other governmental
        authorities, and other factors.
 
  **E.
        Commitments for Construction**
  The
        Partnership’s significant commitments for construction as of September 30, 2006,
        by period were as follows (expressed in millions):
 Less than 1 year
              $    
                  277.91-2 years
              7.03-5 years
              -> 5 years
              -Total
              $   
                  284.9
 
 The
        commitments for construction were primarily related to the East Texas and
        Mississippi pipeline expansion. For further discussion of the East Texas
        and
        Mississippi pipeline expansion see Note 5C *Expansion
        Projects* contained
        in these Notes to Condensed Consolidated Financial Statements.
 
  **F.
        Lease Commitments**
  The
        Partnership has various operating lease commitments extending through the
        year
        2018 covering storage facilities, transportation capacity on third-party
        pipelines, office facilities and equipment. The table below summarizes minimum
        future commitments related to the leases at September 30, 2006 (expressed
        in
        millions):
 
 2006
              $   1.22007
              5.52008
              5.62009
              4.42010
              4.2Thereafter
              14.6Total
              $ 
                   35.5
 
 The
        Partnership’s lease commitments increased from those shown in the 2005 Annual
        Report on Form 10-K, mainly from the signing of a ten-year lease for new
        office
        facilities at Gulf South. The estimated commencement date of the lease is
        May 1,
        2007.
 
  **Note
        6: Net Income per Limited Partner Unit**
  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 Financial Accounting Standards
        Board
        (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:
 
 **Net
                  Income per Unit**
              
              **Limited
                  Partner Units**
                **(and
                  Subordinated Units*)**
              
              **General
                  Partner Units**Up
                  to $0.4025
              
              98%
              
              2%From
                  $0.4026 to $0.4375
              
              85%
              
              15%From
                  $0.4376to
                  $0.5250
              
              75%
              
              25%Greater
                  than $0.5250
              
              50%
              
              50%
  *
        Under
        the terms of the partnership agreement, distributions during the subordination
        period are first made to the common unitholders and general partner, and
        then to
        the subordinated unitholders and general partner to the extent the total
        distributed amount is greater than the minimum quarterly distribution of
        $0.35
        per unit to the common unitholders.
 
 The amount
        reported for net income per limited partner unit on the Condensed
        Consolidated Statements of Income for the nine month period ended September
        30, 2006 was reduced to take into account an assumed allocation to the
        general partner’s incentive distribution rights. However, the Partnership has
        not paid, nor has the general partner authorized the payment of any amounts
        to
        the general partner on account of its incentive distribution rights.
 
  11
  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 is as follows (expressed in thousands, except per unit data):
 
 **For
                  the**
                **Three
                  Months Ended**
                **September
                  30, 2006**
              
              **For
                  the**
                **Nine
                  Months Ended**
                **September
                  30, 2006**Limited
                  partners’ interest in net income
              
              $
              30,034
              
              $
              129,631Less
                  assumed allocation to incentive distribution rights
              
              
              -
              
              
              962Net
                  income available to limited partners
              
              
              30,034
              
              
              128,669Less
                  assumed allocation to subordinated units
              
              
              6,144
              
              
              42,015Net
                  income available to common units
              
              $
              23,890
              
              $
              86,654Weighted
                  average common units
              
              
              68,256
              
              
              68,256Weighted
                  average subordinated units
              
              
              33,094
              
              
              33,094Net
                  income per limited partner unit - common units
              
              $
              0.35
              
              $
              1.27Net
                  income per limited partner unit - subordinated units
              
              $
              0.19
              
              $
              1.27
 
  **Note
        7: Sale of Facilities**
  In
        June
        2006, Texas Gas received $2.5 million for the sale of offshore transmission
        facilities in the Gulf of Mexico at West Cameron 294. The sale of the facilities
        was considered a normal retirement. In accordance with the composite method
        of
        accounting for property, plant and equipment, the proceeds and the related
        book
        value of the plant were recorded to accumulated depreciation which is classified
        as Property, plant and equipment, net on the Condensed Consolidated Balance
        Sheets.
 
  **Note
        8: Financing**
  In
          June
          2006, the Partnership’s revolving credit facility was amended and restated from
          a $200.0 million facility to a $400.0 million facility. Under the amended
          and
          restated facility, which the Partnership has guaranteed, Boardwalk Pipelines,
          Texas Gas and Gulf South each may borrow funds, up to applicable sub-limits.
          Interest on amounts drawn under the credit facility is payable at a floating
          rate equal to an applicable spread per annum over the London Interbank
          Offered
          Rate (LIBOR) or a base rate defined as the greater of the prime rate or
          the
          Federal funds rate plus 50 basis points. Under the terms of the agreement,
          each
          of the borrowers must maintain a minimum ratio, as of the last day of each
          fiscal quarter, of consolidated total debt to consolidated earnings before
          interest, taxes, depreciation and amortization (EBITDA) (as defined in
          the
          agreement), measured for the preceding twelve months, of not more than
          five to
          one. As of September 30, 2006, the Partnership had drawn $60.0 million
          under
          this facility at an interest rate of 5.73%. The revolving credit facility
          has a
          maturity date of June 29, 2011.
  As
        of
        September 30, 2006 and December 31, 2005 the weighted-average interest rate
        of
        the Partnership’s long-term debt, including the borrowing under the revolving
        credit facility, was 5.13% and 5.29%, respectively. Due to the recent increase
        in capital expenditures mainly from work performed on the East Texas and
        Mississippi pipeline expansion project, the amount of interest capitalized
        during the third quarter 2006 has increased over previous periods.  The
        construction work in progress included in PPE, net in the Condensed Consolidated
        Balance Sheets was $183.5 million as of September 30, 2006. During the three
        months ended September 30, 2006 and 2005, the Partnership capitalized interest
        of $0.7 million and less than $0.1 million.  For the nine months ended
        September 30, 2006 and 2005, the Partnership capitalized $0.8 million and
        $0.1
        million of interest. 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 $0.5 million and $0.6 million of AFUDC for the three months ended
        September 30, 2006 and 2005. For the nine months ended September 30, 2006
        and
        2005, the Partnership capitalized $1.1 million and $1.6 million of
        AFUDC.
 
 In
        connection with the IPO, Boardwalk Pipelines borrowed approximately
        $42.1 million under its revolving credit facility to reimburse BPHC for
        capital expenditures it incurred in connection with the acquisition of Gulf
        South. Interest on the borrowings was accrued at the 3-month LIBOR rate plus
        applicable margin (4.68%). The borrowings were repaid in full during February
        2006.
 
 In
        December 2004, Boardwalk Pipelines borrowed $575.0 million as an interim
        term
        loan in connection with the Gulf South Acquisition. In January 2005, Boardwalk
        Pipelines issued $300.0 million principal amount of 5.50% notes due in 2017
        and
        Gulf South issued $275.0 million principal amount of 5.05% notes due in 2015.
        The proceeds from these notes, together with available cash, were used to
        repay
        the interim loan.
 
  **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. As of
        September 30, 2006, the amount of gas loaned by the Partnership’s subsidiaries
        was approximately 5 TBtu and, assuming an average market price during September
        2006 of $4.88 per MMBtu, the market value of that gas was approximately $24.4
        million. As of December 31, 2005, the amount of gas loaned was approximately
        15
        TBtu and, assuming an average market price during December 2005 of $12.34
        per
        MMBtu, the market value of that gas was approximately $185.1 million. If
        any
        significant customer should have credit or financial problems resulting in
        a
        delay or failure to repay the gas owed to the Partnership’s subsidiaries, this
        could have a material adverse effect on the Partnership’s financial condition,
        results of operations and cash flows.
 
  **Note
        10: Employee Benefits** **and Compensation**
   ***Retirement
        Plan***
  
 Substantially
        all of Texas Gas' employees are covered under a non-contributory, defined
        benefit pension plan. Texas Gas also provides postretirement life insurance
        and
        postretirement health care benefits to certain retired employees. Texas Gas
        uses
        a measurement date of December 31 for its pension and postretirement benefits
        plans.
 
 During
          the
          first quarter 2006, Texas Gas began recognizing pension expense based on
          the
          actuarially determined net periodic pension cost pursuant to the settlement
          of
          its rate case. Based on the annual actuarial study, pension expense for
          2006 was
          determined to be approximately $4.6 million. During the nine months ended
          September 30, 2006, Texas Gas recorded pension expense retroactive to November
          1, 2005, the date on which Texas Gas’ new general rate case became effective. As
          of September 30, 2006, Texas Gas contributed $3.0 million to its pension
          plan.
          The contribution for 2006 is expected to be approximately $5.2 million.
 Net
        periodic benefit cost components were as follows (expressed in
        thousands):
 
 **Pension
                  Benefits**
                **For
                  the**
                **Three
                  Months Ended**
                **September
                  30,**
              
              **Other
                  Benefits**
                **For
                  the**
                **Three
                  Months Ended**
                **September
                  30,****2006**
              
              **2005**
              
              **2006**
              
              **2005**Service
                  cost
              $     
                  1,147
              
              $          
                  975
              
              $          108
              
              $      
                   519Interest
                  cost
              1,765
              1,500
              858
              1,806Expected
                  return on plan assets
              (1,799)
              (1,725)
              (1,134)
              (1,158)Amortization
                  of prior service cost
              -
              
              -
              
              (1,939)
              
              -Amortization
                  of accumulated loss
              332
              
              -
              
              110
              
              90Special
                  termination benefit
              5,600
              -
              900
              -Regulatory
                  accrual/amortization
              (3,045)
              (750)
              1,354
              68Estimated
                  net periodic benefit cost
              $     4,000
              $           
                   -
              $        257
              $ 
                   1,325
 
  12
  
 **Pension
                  Benefits**
                **For
                  the**
                **Nine
                  Months Ended**
                **September
                  30,**
              
              **Other
                  Benefits**
                **For
                  the**
                **Nine
                  Months Ended**
                **September
                  30,****2006**
              
              **2005**
              
              **2006**
              
              **2005**Service
                  cost
              $      3,971
              
              $      2,925
              
              $    
                   1,194
              
              $     1,557Interest
                  cost
              6,001
              4,500
              4,319
              5,418Expected
                  return on plan assets
              (6,492)
              (5,175)
              (3,418)
              (3,474)Amortization
                  of prior service cost
              -
              -
              (2,587)
              -Amortization
                  of accumulated loss
              584
              -
              876
              270Special
                  termination benefit
              5,600
              -
              900
              -Regulatory
                  accrual/amortization
              (3,045)
              (2,250)
              4,964
              204Estimated
                  net periodic benefit cost
              $      6,619
              $           -
              $  
                   6,248
              $    3,975
 
  ***Defined
        Contribution Plans***
  
 Subsidiaries
        of the Partnership maintain defined contribution plans covering substantially
        all of its employees. Costs related to these plans were $1.2 million and
        $3.7
        million, respectively, for the three and nine months ended September 30,
        2006
        and $1.3 million and $3.6 million, respectively, for the three and nine months
        ended September 30, 2005.
  ***Postretirement
        Benefits other than Pensions***
  In
        May
        2006, as part of an overall cost reduction program, Texas Gas announced to
        its
        employees and retirees a plan to make changes to its postretirement benefits
        plan beginning January 1, 2007. Under the revised plan, Texas Gas will cap
        its
        contributions toward medical benefit coverage for retirees younger than age
        65
        to the amount contributed for each retiree in 2006. For retirees age 65 and
        older, Texas Gas will cap its contribution at three times the 2006 amount.
        In
        addition, Texas Gas will no longer cover prescription drug costs for retirees
        age 65 and older. In conjunction with the plan amendments, Texas Gas increased
        the discount rate used in determining the accumulated postretirement benefit
        obligation (APBO) and net periodic postretirement benefit cost from 5.88%
        to
        6.38%, effective June 1, 2006 to accomodate changes in market interest rates
        since the end of 2005. The changes will result in an estimated reduction
        in the
        APBO of approximately $75.3 million for the plan amendment and $13.5 million
        for
        the increase in the discount rate. In accordance with SFAS No. 106, *Employers’*  *Accounting
        for Postretirement Benefits other than Pension* s,
        the
        decrease in the APBO from the plan amendment will be recognized as a reduction
        to net periodic postretirement benefit cost over the average remaining service
        lives of active employees covered under the plan, or approximately nine years.
        For the nine months ended September 30, 2006, the change resulted in a reduction
        of $5.1 million for net periodic benefit cost from the amount that would
        otherwise have been recognized.
 
  ***Early
        Retirement Incentive Program***
  In
        2006,
        Texas Gas implemented an early retirement incentive program (ERIP) which
        was
        made available to approximately 240 non-executive employees age 52 and older
        with at least five years of service. Under the program, Texas Gas would provide
        eligible employees three additional years for purposes of age-based vesting
        under the postretirement medical plan and three additional years of pay credits
        under the pension plan. Retirements under the program would generally be
        effective January 1, 2007. Approximately 100 of the eligible employees indicated
        their intent to participate in the program.
 
 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 PBOP. In accordance
        with the regulatory treatment for Texas Gas’ pension expense, $2.6 million of
        the special termination benefit for pension was recognized in Administrative
        and
        general expense and the remainder was deferred as a regulatory asset. The
        charge
        for PBOP was recognized in Administrative and general expense.
  13
   ***Strategic
        Long Term Incentive Plan***
  On
        July
        24, 2006 the Partnership approved the Boardwalk Pipeline Partners Strategic
        Long
        Term Incentive Plan (the Plan). The Plan provides for the issuance of up
        to 500
        General Partner (GP) Phantom Units to key executives of the Partnership and
        its
        subsidiaries. Each GP Phantom Unit entitles the holder thereof, upon vesting,
        to
        a lump sum cash payment in an amount determined by a formula based on cash
        distributions made by the Partnership to its general partner during the four
        quarters preceding the vesting date.
 
 Concurrent
        with the approval of the Plan, 125 GP Phantom Units were awarded to employees
        that would vest in 3.5 years. The fair value of the awards was determined
        as of
        the date of grant and remeasured at the end of the third quarter 2006 in
        accordance with the treatment of awards classified as liabilities prescribed
        in
        SFAS No. 123 (revised 2004), *Share-Based
        Payment.* The fair
        value of the awards will be recognized ratably over the vesting period. The
        fair
        value will be remeasured each quarter until settlement. Any change to the
        fair
        value at the end of a particular quarter would be recognized over the remaining
        vesting period. For the third quarter 2006, the Partnership recognized a
        liability and concurrent charge to Administrative and general expenses of
        $0.2
        million related to the fair value of the GP Phantom Unit awards.
 
  **Note
        11: Related Parties**
  Loews
        has
        a policy of charging its subsidiary companies for management services provided
        by Loews. The
        Partnership recorded $2.1 million and $8.6 million, respectively, for the
        three
        and nine months ended September 30, 2006 and $3.6 million and $7.6 million,
        respectively, for the three and nine month periods ended September 30,
        2005 for
        management services.
 
  **Note
        12: Distributions**
  T he
        Partnership has declared quarterly distributions per unit to unitholders
        of
        record, including common and subordinated units and the 2% general partner
        interest held by its general partner as follows:
 
 Record
                  Date
              
              Payable
                  Date
              
              Distribution
                  per UnitOctober
                  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
              
              $  0.1788*
 
 *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 from November 15, 2005 through December 31,
                  2005.
 
  **Note
        13: Recently Issued Accounting Pronouncements**
  In
        September of 2006, the Securities and Exchange Commission (SEC) issued Staff
        Accounting Bulletin (SAB) No. 108, *Considering
        the Effects of Prior Year Misstatements when Quantifying Misstatements in
        Current Year Financial Statements.* This
        bulletin summarizes the SEC staff’s views regarding the process of quantifying
        financial statement misstatements. SAB No. 108 is effective for reporting
        periods ending after November 15, 2006. SAB No. 108 is not expected to have
        a
        material impact on the Partnership’s financial condition, results of operation
        or cash flows.
 
 On
        September 29, 2006 the FASB issued SFAS No. 158 , *Employers'
        Accounting for Defined Benefit Pension and Other Postretirement
        Plans* .
        Under
        SFAS No. 158 ,
        a
        defined benefit postretirement plan sponsor must (a) recognize in its statement
        of financial position an asset for a plan's overfunded status or a liability
        for
        the plan's underfunded status, (b) measure the plan's assets and its obligations
        that determine its funded status as of the end of the employer's fiscal year
        (with limited exceptions), and (c) recognize, as a component of other
        comprehensive income, the changes in the funded status of the plan that arise
        during the year but are not recognized as components of net periodic benefit
        cost pursuant to SFAS No. 87 , *Employers'
        Accounting for Pensions,* or
        SFAS
        No. 106 , *Employers'
        Accounting for Postretirement Benefits Other Than Pensions.* Previous
        standards required an employer to disclose the complete funded status of
        its
        plan only in the notes to the financial statements. Moreover, because those
        standards allowed an employer to delay recognition of certain changes in
        plan
        assets and obligations that affected the costs of providing benefits, employers
        reported an asset or liability that almost always differed from the plan's
        funded status. ** SFAS
        No.
        158 is initially effective for fiscal years ending after December 15, 2006,
        except for (b), measurement of plan assets and benefit obligations which
        will be
        effective for fiscal years ending after December 15, 2008. The Partnership
        is
        currently evaluating the impact, if any, that SFAS No. 158 would have on
        its
        financial statements.
  On
          September 15, 2006, the FASB issued SFAS No. 157, *Fair
          Value Measurements* .
          Under
          the standard , 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 Partnership is currently evaluating the
          impact,
          if any, that SFAS No. 157 would have on its financial statements.
 14
   **Item
        2. Management’s Discussion and Analysis of Financial
        Condition and Results of Operations**
  
 *The
        following discussion and analysis of our financial condition and results
        of
        operations should be read in conjunction with (i) 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 (GAAP), (ii) 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, 2005, and
        (iii)
        the Risk Factors described in Item 1A of Part II of this
        report.*
 
 We
        are a
        Delaware limited partnership formed in 2005 to own and operate the business
        conducted by Boardwalk Pipelines, LP (Boardwalk Pipelines) and its subsidiaries,
        Texas Gas Transmission, LLC (Texas Gas) and Gulf South Pipeline Company,
        LP
        (Gulf South). We are engaged through our subsidiaries in the interstate
        transportation and storage of natural gas and operate in one reportable segment
        - the operation of interstate natural gas pipeline systems. Our pipeline
        systems
        are comprised of an aggregate of 13,470 miles of pipe and integrated storage
        originating in the Gulf Coast area and running north and east through Texas,
        Louisiana, Mississippi, Alabama, Florida, Arkansas, Tennessee, Kentucky,
        Indiana, Ohio and Illinois.
  In
        connection with our initial public offering (IPO) ,
        Boardwalk Pipelines Holding Corp. ( BPHC)
        contributed all of the equity interests of Boardwalk
        Pipelines to us
        in
        exchange for limited partner and general partner units. This
        contribution was accounted for as a transfer of assets between entities under
        common control in accordance with Statement of Financial Accounting Standards
        (SFAS) No. 141, *Business
        Combinations* .
        Therefore, the consolidated results of Boardwalk Pipelines for the periods
        prior
        to the IPO have been presented in this report as our consolidated results.
   **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 in the
        period in which the facts that give rise to the revision become known.
  We
        calculate 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 Financial Accounting Standards
        Board
        (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:
 
 **Net
                  Income per Unit**
              **Limited
                  Partner Units**
                **(and
                  Subordinated Units*)**
              **General
                  Partner Units**Up
                  to $0.4025
              98%
              2%From
                  $0.4026 to $0.4375
              85%
              15%From
                  $0.4376 to $0.5250
              75%
              25%Greater
                  than $0.5250
              50%
              50%
  *
        Under
        the terms of the partnership agreement, distributions during the subordination
        period are first made to the common unitholders and general partner, and
        then to
        the subordinated unitholders and general partner to the extent the total
        distributed amount is greater than the minimum quarterly distribution of
        $0.35
        per unit to the common unitholders.
 
 The amount
        reported for net income per limited partner unit on the Condensed
        Consolidated Statements of Income for the nine month period ended September
        30, 2006 was reduced to take into account an assumed allocation to the general
        partner’s incentive distribution rights. However, we have not paid, nor has the
        general partner authorized the payment of, any amounts to the general partner
        on
        account of its incentive distribution rights.
 
 Further
        information regarding our accounting policies and estimates that we considered
        to be critical can be found in our Annual Report on Form 10-K for the year
        ended
        December 31, 2005. There have not been any significant changes in these policies
        and estimates during 2006.
 
  15
   **Results
        of Operations - Business Overview**
  The
        Partnership derives its 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 discount to the maximum tariff rates due to competition in the
        marketplace.
 
 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
        firm services are generally higher in winter peak periods (November through
        March) than off-peak periods resulting in a seasonal earnings pattern where
        the
        majority of earnings are generated in the first and fourth quarters of a
        calendar year. 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 service
        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.
 
  **Results
        of Operations for the Three Months Ended September 30, 2006 and 2005**
  Total
        Operating Revenues increased by $12.1 million, or 10%, to $133.0 million
        for the
        three months ended September 30, 2006, compared to $120.9 million for the
        three
        months ended September 30, 2005 primarily due to:
 
 ·
            $9.0
                million increase in storage and parking-and-lending services due
                to
                favorable natural gas price spreads and volatility in forward gas
                prices;
                and ·
            $7.7
                million increase in transportation services primarily from higher
                reservation rates and additional capacity reserved by shippers due
                to
                increased production in the East Texas region; partially
        offset by,
 ·
            $3.6
                million decrease in usage fees on interruptible services due to 2006
                volumes being transported on new firm contracts;
                and ·
            $1.1
                million decrease in revenues for a reduction in the amortization
                of
                acquired executory contracts. 
 Total
        Operating Costs and Expenses decreased by $11.6 million, or 11.6%, to $88.3
        million for the three months ended September 30, 2006, compared to $99.9
        million
        for the three months ended September 30, 2005 primarily due to:
 ·
              $8.1
                  million decrease in company-used gas due to lower natural gas prices
                  and
                  operational efficiencies resulting in decreased usage;
                  and ·
              $4.6
                  million decrease from charges recognized in 2005 for hurricanes
                  Katrina
                  and Rita;
 partially
          offset by,
 ·
              $1.2
                  million increase in labor and benefits consisting of the recognition
                  of a
                  $3.5 million special termination benefit charge as a result of
                  the Texas
                  Gas early retirement incentive program (ERIP), reduced by the effects
                  of a
                  cost-reduction program implemented at Texas Gas.
  Total
        Other (Income) Deductions increased by $0.6 million, or 4.4%, to $14.0 million
        for the three months ended September 2006, compared to $13.4 million for
        the
        comparable 2005 period. The increase is primarily due to a reduction in interest
        income.
 
 Income
        Taxes and Charge-In-Lieu of Income Taxes decreased by $2.9 million, to $0.1
        million for the third quarter 2006, due to the change in tax status and
        conversion to a limited partnership concurrent with the IPO.
 
 16
  **Results
        of Operations for the Nine Months Ended September 30, 2006 and
        2005**
  Total
        Operating Revenues increased by $46.6 million, or 12%, to $436.2 million
        for the
        nine months ended September 30, 2006, compared to $389.6 million for the
        nine
        months ended September 30, 2005 primarily due to:
 ·
              $25.5
                  million increase in storage and parking-and-lending services due
                  to
                  favorable natural gas price spreads and volatility in forward gas
                  prices; ·
              $20.0
                  million increase in transportation services due primarily to higher
                  reservation rates and additional capacity reserved by shippers
                  due to
                  increased production in the East Texas region;
                  and ·
              $5.5
                  million increase in fuel related revenues due to an increase in
                  realized
                  gas prices including revenues locked in through hedging activities
                  and
                  additional system volumes; partially
          offset by,
 ·
              $4.5
                  million decrease in revenues for a reduction in the amortization
                  of
                  acquired executory contracts. 
 Total
          Operating Costs and Expenses increased by $5.3 million, or 2.1%, to $260.9
          million for the nine months ended September 30, 2006, compared to $255.6
          million
          for the nine months ended September 30, 2005 primarily due to:
 ·
                $6.9
                    million increase in labor and outside services primarily due
                    to growth in
                    operations; ·
                $6.5
                    million increase due to the amortization of a regulatory asset
                    related to
                    postretirement benefits other than pensions and pension expense
                    recognition as a result of the settled rate case, reduced by
                    the impact of
                    other postretirement benefit plan
                    changes; ·
                $3.5
                    million increase in benefits expense due to the recognition of
                    a special
                    termination benefit charge as a result of the Texas Gas ERIP
                    and expense
                    recognition as a result of the settled Texas Gas rate
                    case; ·
                $3.1
                    million increase in depreciation and amortization due to the
                    increased
                    asset base from additions to plant and purchase accounting adjustments
                    in
                    2005; and ·
                $2.8
                    million increase in costs for transportation of gas on third-party
                    pipelines to provide additional deliveries to the market area; partially
            offset by,
 ·
                $8.7
                    million decrease from charges recognized in 2005 for hurricanes
                    Katrina
                    and Rita; ·
                $6.1
                    million decrease in company-used gas due to operational efficiencies
                    resulting in decreased usage; and ·
                $2.4
                    million decrease in expenses for state franchise taxes due to
                    the change
                    in tax status to a limited partnership concurrent with the
                    IPO.
  Total
        Other (Income) Deductions increased by $1.9 million, or 4.7%, to $42.6 million
        for the nine months ended September 30, 2006, compared to $40.7 million for
        the
        comparable 2005 period. The increase is primarily due to interest expense
        related to borrowings under a credit facility that occurred after the IPO
        in
        2005 of $1.1 million and a reduction in interest income of $1.0 million.
 
 Income
        Taxes and Charge-In-Lieu of Income Taxes decreased by $36.8 million, to $0.4
        million for the nine months ended September 30, 2006, due to the change in
        tax
        status and conversion to a limited partnership concurrent with the
        IPO.
  17
  **Capital
        Expenditures**
  Capital
        expenditures, net of amounts received for retirements and salvage and accrued
        amounts for the nine months ended September 30, 2006 and 2005 were $120.2
        million and $50.4 million, respectively.
  For
          the
          year ending December 31, 2006, we expect to make capital expenditures of
          approximately $275.0 million, of which we expect approximately $221.0 million
          to
          be for expansion capital, including approximately $170.0 million to fund
          our East
          Texas and Mississippi pipeline expansion project ,
          discussed below, and $54.0 million to be for maintenance capital. The amount
          of
          expansion capital we expend in 2006 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
        currently
        expect to fund our 2006 maintenance capital expenditures from operating cash
        flows. We expect to fund our 2006 expansion capital expenditures on an interim
        basis with borrowings under our revolving credit facility. We expect to pay
        off
        any borrowings under our revolving credit facility with the issuance of debt
        and
        equity during the fourth quarter 2006. Thereafter, we expect to fund the
        balance
        of the cost of our pipeline expansion projects with a combination of cash
        from
        operations, borrowings under our revolving credit facility, and proceeds
        from
        sales of our debt and equity securities.
 
 We
        are
        currently engaged in the following expansion projects:
 ·
              *Carthage
                  to Keatchie Loop*.
                  We have begun construction on a 20.5 mile segment of 42-inch pipeline
                  from
                  Carthage, Texas to Keatchie, Louisiana. The capacity of the segment
                  will
                  be 120 MMcf per day and we expect it to be in service by the end
                  of
                  November 2006.
 ·
              *East
                  Texas and Mississippi Pipeline Expansion.*We
                  are pursuing a pipeline expansion project consisting of 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 would add approximately 1.7 Bcf per
                  day of new
                  transmission capacity to the Gulf South pipeline system. The natural
                  gas
                  to be transported on this expansion will originate primarily from
                  the
                  Barnett Shale and Bossier Sands producing regions of East Texas.
                  The
                  expansion will transport natural gas to new interstate pipeline
                  interconnects in the Perryville, Louisiana area and existing pipeline
                  interconnects with other pipelines east of the Mississippi River.
                  This
                  expansion is supported by binding precedent agreements with customers
                  who
                  have contracted, on a long-term basis (with a weighted average
                  life of
                  approximately 7 years), for 1.3 Bcf with an option for an additional
                  100
                  MMcf of the approximately 1.7 Bcf per day capacity. On September
                  1, 2006,
                  Gulf South filed a certificate application relating to this project
                  with
                  FERC. Gulf South has ordered the pipeline and compression materials
                  needed
                  to construct this project. We expect this project to be in service
                  during
                  September 2007. The total cost of this expansion and the Carthage
                  to
                  Keatchie Loop is expected to be approximately $800
                  million.
 *·*
              *Western
                  Kentucky Storage Expansion.*We
                  are pursuing a project to expand the working gas capacity in Texas
                  Gas’
                  western Kentucky storage complex by approximately 9 Bcf. This project
                  is
                  supported by binding commitments from customers to contract on
                  a long-term
                  firm basis for the full additional capacity at Texas Gas’ maximum
                  applicable rate. On April 14, 2006, Texas Gas filed a certificate
                  application relating to this project with FERC. We expect this
                  project to
                  cost approximately $36 million and to be in service during November
                  2007.
  ·
              *Magnolia
                  Storage Expansion*.
                  Gulf South has leased a gas storage facility near Napoleonville,
                  Louisiana, and is currently developing an additional storage cavern.
                  During recent mining operations, certain issues have arisen causing
                  the
                  mining of the caverns to be suspended. Gulf South has conducted
                  and is
                  continuing during the fourth quarter 2006 to conduct operational
                  integrity
                  tests on the caverns and associated facilities. If the test results
                  are
                  favorable, Gulf South expects the storage facilities to be in service
                  during 2009. If the test results are not favorable, management
                  will
                  consider the options it has available, including developing a new
                  cavern,
                  sale or abandonment of the project. The total book value of the
                  project at
                  September 30, 2006 was $42.2 million. We test the investment in
                  Magnolia
                  for recoverability in accordance with the requirements of SFAS
                  No. 144,*Accounting
                  for the Impairment or Disposal of Long-Lived Assets*.
                  No impairment loss has been recognized as a result of the recoverability
                  tests.
  We
            are
            also engaged in discussions on other proposed future expansion projects,
            which
            would connect our pipeline system to growing supplies of gas in the
            Mid-Continent region. We previously announced the signing of a letter
            of intent
            to pursue the formation of a joint venture to construct a new interstate
            pipeline that would connect gas supplies originating in the Fayetteville
            Shale
            region of Arkansas, in North Central Texas and Oklahoma to a new interconnect
            with Texas Gas. One of the original participants has withdrawn from the
            project,
            alleging that we breached the terms of the letter of intent based on
            its belief
            that we are pursuing a competing project. We strongly disagree with these
            allegations. We and the remaining participant continue to pursue this
            project.
 
 The
            completion of all of these projects is subject to risks and uncertainties
            including market conditions, signing of definitive agreements, obtaining
            appropriate regulatory approvals (including FERC’s review of requests for
            authorization), obtaining the necessary financing for the projects and
            other
            factors beyond our control.
 
 18
  **Distributions**
  We have
        declared quarterly distributions per unit to unitholders of record, including
        common and subordinated units and the 2% general partner interest held by
        its
        general partner as follows:
 
 Record
                  Date
              
              Payable
                  Date
              
              Distribution
                  per UnitOctober
                  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
              
              $0.1788*
 
 *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 from November 15, 2005 through December 31,
                  2005.
 
 The
        distributions have been paid, or will be paid, from our available cash pursuant
        to the partnership agreement and funded by cash from
        operations.
   **Cost
        Reduction Program**
  In
        2006,
        Texas Gas implemented a program that will reduce labor and benefits costs
        by
        approximately $15 million on an annualized basis. The components of the program
        included changes to postretirement benefits other than pensions (PBOP), the
        ERIP, a reduction in the annual cash incentive program and the elimination
        of
        the 2006 broad-based merit increase pool for 2006. Refer to Note 10 of the
        Notes
        to Condensed Consolidated Financial Statements in Part I, Item 1 of this
        report
        for additional information regarding the changes to PBOP and the
        ERIP.
 
  19
   **Liquidity
        and Capital Resources**
  We
        are a
        limited partnership holding company and derive all of our operating cash
        flow
        from our subsidiaries, Texas Gas and Gulf South. Our subsidiaries use funds
        from
        their respective operations to fund their operating activities and maintenance
        and expansion capital requirements, service their indebtedness and make advances
        or distributions to Boardwalk Pipelines. Boardwalk Pipelines uses cash provided
        from Texas Gas and Gulf South and, as needed, borrowings under its revolving
        credit facility, to service its indebtedness and make distributions or advances
        to us to fund our distributions to unitholders and our general
        partner.
 
 We
        have
        filed registration statements on Form S-1 covering the offering and sale
        of: (i)
        $250 million of senior unsecured notes of our subsidiary, Boardwalk Pipelines,
        to be guaranteed by us; and (ii) up to 5,750,000 of our common units. The
        proceeds of such offerings, if consummated, will be used to finance our
        expansion activities and/or repay outstanding borrowings under our revolving
        credit facility which were used to finance such activities.
 
 To
        hedge
        the risk attributable to changes in the risk-free component of forward 10-year
        interest rates through December 1, 2006, on October 5, 2006 we entered into
        a
        Treasury rate lock for a notional amount of $250 million of principal. The
        reference rate on the Treasury rate lock was 4.6%. In addition, on August
        1 and
        August 3, 2006 we entered into Treasury rate locks with two counterparties
        each
        for a notional amount of $100 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 those Treasury rate
        locks
        were 5.00% and 4.96%. See Item 3 for more information regarding the Treasury
        rate locks and interest rate risk.
  In
          June
          2006, our revolving credit facility was amended and restated from a $200
          million
          facility to a $400 million facility. Under the amended and restated facility,
          which we have guaranteed, Boardwalk Pipelines, Texas Gas and Gulf South
          each may
          borrow funds up to applicable sub-limits. Interest on amounts drawn under
          the
          credit facility is payable at a floating rate equal to an applicable spread
          per
          annum over the London Interbank Offered Rate (or LIBOR) or a base rate
          defined
          as the greater of the prime rate or the Federal funds rate plus 50 basis
          points.
          Under the terms of the agreement, each of the borrowers must maintain a
          minimum
          ratio, as of the last day of each fiscal quarter, of consolidated total
          debt to
          consolidated earnings before interest, taxes, depreciation and amortization
          (EBITDA) (as defined in the agreement), measured for the preceding twelve
          months, of not more than five to one. As of September 30, 2006, we had
          drawn $60
          million under this facility at an interest rate of 5.73%. The revolving
          credit
          facility has a maturity date of June 29, 2011.
 20
  **Changes
        in cash flow from operating activities for the Nine Months Ended September
        30,
        2006 and September 30, 2005**
  Net
        cash
        provided by operating activities was $184.9 million for the nine months ended
        September 30, 2006, compared to $159.7 million in the comparable 2005 period.
        The increase of $25.2 million in cash flow from operating activities primarily
        consisted of:
 
 ·  $79.1
        million increase in net income, excluding non-cash items such as depreciation;
        and
 ·  $16.0
        million increase in cash inflows relative to net changes in working capital
        items; partially offset by
 ·  $50.5
        million decrease in the provision for deferred income taxes due to the change
        in
        entity structure; and
 ·  $19.5
        million increase in cash outflows relative to net changes in non-current
        assets
        and liabilities.
 
  **Changes
        in cash flow from investing activities:**
  Net
        cash
        used in investing activities increased $37.7 million, to $116.0 million for
        the
        nine month period ended September 30, 2006, from $78.2 million in the comparable
        2005 period, which was primarily attributable to:
  ·  $69.8
          million increase in capital expenditures; partially offset by
 ·  $27.1
          million decrease in advances to affiliates; and
 ·  $5.0
          million increase in insurance and other recoveries.
  **Changes
        in cash flow from financing activities:**
  Net
        cash
        used in financing activities amounted to $77.1 million for the nine months
        ended
        September 30, 2006, compared to $63.9 million during the same period in 2005.
        The increase of $13.2 million was primarily due to:
  ·  $30.0
          million increase in distributions paid; and
 ·  $6.7
          million decrease in capital contributions received in 2005 from our parent;
          partially offset by
 ·  $23.5
          million primarily due to a net increase in debt.
  21
  **Contractual
        Obligations**
  The
        table
        below is updated for significant changes in lease and capital commitments
        from
        those included in the Annual Report on Form 10-K for the year ended December
        31,
        2005 by period (expressed in millions):
  **Payments
                    due by Period****Total**
                
                **Less than
                    1 Year**
                
                **1-2 Years**
                
                **3-5 Years**
                
                **More than
                     5 Years**Lease
                    commitments
                
                $
                35.5
                
                $
                5.4
                
                $
                10.3
                
                $
                8.8
                
                $
                11.0Capital
                    commitments
                
                
                284.9
                
                
                277.9
                
                
                7.0
                
                
                -
                
                
                -Total
                
                $
                320.4
                
                $
                283.3
                
                $
                17.3
                
                $
                8.8
                
                $
                11.0
  The
        change in lease commitments was related to the signing of a ten-year lease
        for
        new office facilities at Gulf South. The estimated commencement date of the
        lease is May 1, 2007.
 
 The
        capital commitments for construction were primarily related to the East Texas
        and Mississippi pipeline expansion. For further discussion of the East Texas
        and
        Mississippi pipeline expansion please read Note 5C *Expansion
        Projects* in the
        Notes to Condensed Consolidated Financial Statements included in Part I,
        Item 1
        of this report.
 
 The
        2006
        funding requirement to the employee benefits retirement plan as a result
        of
        Texas Gas’ settled rate case is $5.2 million.
 
 For
        a
        detailed listing of our Contractual Obligations, please see our Annual
        Report on Form 10-K for the year ended December 31, 2005.
 
  **Off-Balance
        Sheet Arrangements**
  We
        have
        no off-balance sheet arrangements as defined by Regulation S-K.
   22
  **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 within the meaning of the Private Securities
        Litigation Reform Act of 1995 (Act). 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 us or our subsidiaries,
        which
        may be provided by management, are also forward-looking statements as defined
        by
        the Act.
 
 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:
  •
              the
                  gas transmission and storage operations of our subsidiaries are
                  subject to
                  rate-making policies and actions by FERC or customers that could
                  have an
                  adverse impact on the rates we charge and our ability to recover
                  our
                  income tax allowance and our full cost of operating our pipelines,
                  including a reasonable return;
  •
              the
                  impact of Hurricanes Katrina and Rita or any new hurricane could
                  have a
                  material adverse effect on our business, financial condition and
                  results
                  of operations because some of our damages may not be covered by
                  insurance;
  •
              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 the 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 liquefied natural gas import terminals in the eastern
                  or
                  northeastern United States could reduce the demand for our
                  services;
  •
              we
                  may not be able to maintain or replace expiring gas transportation
                  and
                  storage contracts at favorable
                  rates;
  •
              we
                  depend on certain key customers for a significant portion of our
                  revenues.
                  The loss of any of these key customers could result in a decline
                  in our
                  revenues;
  •
              significant
                  changes in natural gas prices could affect supply and demand, reducing
                  system throughput and adversely affecting our revenues;****
  •
              we
                  may not complete projects, including growth or expansion projects,
                  that we
                  commence, or we may complete projects on materially different terms
                  or
                  timing than anticipated and we may not be able to achieve the intended
                  benefits of any such project, if completed;
                  and
  •
              the
                  successful completion, timing, cost, scope and future financial
                  performance of our expansion projects could differ materially from
                  our
                  expectations due to weather, untimely regulatory approvals or denied
                  applications, land owner opposition, the lack of adequate materials,
                  or
                  labor, we may encounter difficulties with partners or potential
                  partners
                  and numerous other factors beyond our
                  control.
 
 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.
  23
   **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, 2006, had a carrying value of $1.2 billion and a fair value
        of
        $1.1 billion. The weighted-average interest rate of our long-term debt was
        5.13%
        at September 30, 2006, including the effect of the interest rate on $60 million
        borrowed against our revolving credit facility.
 
 We
        entered into a Treasury rate lock October 5, 2006 for a notional amount of
        $250
        million of principal to hedge the risk attributable to changes in the risk-free
        component of forward 10-year interest rates through December 1, 2006, the
        expected date of issuance of $250 million of Boardwalk Pipelines’ senior
        unsecured notes. The reference rate on the Treasury rate lock is 4.60%. Under
        the terms of the Treasury rate lock, the counterparty would pay us a settlement
        amount if the 10-year Treasury rate is greater than 4.60% on December 1,
        2006.
        Conversely, we would pay the counterparty a settlement amount if the 10-year
        Treasury rate is less than 4.60%.
 
 On
        August
        1 and August 3, 2006, we entered into Treasury rate locks with two
        counterparties each for a notional amount of $100 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 Treasury
        rate
        locks are 5.00% and 4.96%. Under the terms of the Treasury rate locks, the
        counterparties would pay us settlement amounts if the 10-year Treasury rate
        is
        greater than the reference rates at October 1, 2007. Conversely, we would
        pay
        the counterparties settlement amounts if the 10-year Treasury rate is less
        than
        the reference rates. As of September 30, 2006, the Partnership recognized
        a
        liability of $5.6 million related to the fair values of the August 2007 rate
        locks. In addition to the liability, the Partnership recognized a charge
        to
        Accumulated other comprehensive income in an equal and offsetting amount
        less
        ineffectiveness recognized of less than $0.1 million.
 
 The
        Treasury rate locks will be accounted for as cash flow hedges in accordance
        with
        SFAS No. 133, *Accounting
        for Derivative Instruments and Hedging Activities,* as
        amended. Under a cash flow hedge of expected future interest payments, gains
        and
        losses on the derivative would be recognized in Accumulated other comprehensive
        income. The balance of Accumulated other comprehensive income would be amortized
        to interest expense over the term of the related interest payments.
 
 Certain
        volumes of gas stored underground at Gulf South are available for sale under
        its
        tariff and subject to commodity price risk. At September 30, 2006 and December
        31, 2005, approximately $15.1 million and $6.5 million, respectively, of
        Gulf
        South’s gas stored underground, which we own and carry as inventory, is exposed
        to commodity price risk. In accordance with
        the
        Partnership’s risk management policy, Gulf South utilizes natural gas futures,
        swaps, and options contracts (collectively, derivatives) to hedge certain
        exposures to market price fluctuations on our anticipated operational sales
        of
        gas. The changes in fair values of the derivatives related to the anticipated
        sales of gas, are designated as cash flow hedges under SFAS No. 133 and are
        expected to, and do, have a high correlation to changes in the anticipated
        value
        of the hedged transactions. Pursuant to SFAS No. 133, the periodic changes
        in
        fair values of the derivatives are deferred
        as a component of Accumulated other comprehensive income (loss) and are
        recognized in the Condensed Consolidated Statements of Income when the hedged
        anticipated purchases or sales affect earnings.
 
 Derivatives
        related to the value of company-owned storage capacity and the purchase of
        operational gas for the East Texas and Mississippi pipeline expansion project
        during the second quarter 2006 were not designated as hedges in accordance
        with
        SFAS No. 133. The changes in the values of the derivatives were recognized
        currently in earnings. We recognized $0.9 million and $1.3 million of credits
        to
        earnings, respectively, for the three and nine months ended September 30,
        2006
        related to the change in fair values associated with the derivatives.
 
 We
        are exposed to credit risk. Credit risk relates 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 parking-and-lending and no-notice services. 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, 2006, the amount of gas loaned out by our subsidiaries
        was
        approximately 5 Trillion British thermal units (Tbtu) and, assuming an average
        market price during September 2006 of $4.88 per million British thermal units
        (MMBtu), the market value of gas loaned out at September 30, 2006, would
        have
        been approximately $24.4 million. As of December 31, 2005, the amount of
        gas
        loaned out was approximately 15 TBtu and, assuming an average market price
        during December 2005 of $12.34 per MMBtu, the market value of that gas would
        be
        approximately $185.1 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, 2006, our cash and investment portfolio did not include
        fixed-income securities. Due to the short-term nature of our investment
        portfolio, 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 to any significant degree by the effect of a sudden change
        in market interest rates on our investment portfolio.
  24
   **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 officers 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
        officers and principal financial officer have each concluded that the disclosure
        controls and procedures are effective.
 
 Other
        than the matters discussed below, there was no change in our control over
        financial reporting identified in connection with the foregoing evaluation
        that
        occurred during the last fiscal quarter that has materially affected, or
        is
        reasonably likely to materially affect, our internal control over financial
        reporting.
 
 **Changes
        in Internal Control over Financial Reporting**
  During
        the
        third quarter 2006, we implemented a new
        financial consolidation and reporting system and our Gulf South subsidiary
        implemented a new procurement system. It is anticipated that these
        implementations will enhance internal controls through the automation of
        manual
        processes.
  25
  PART
        II-OTHER INFORMATION
   **Item
        1. Legal Proceedings**
  For
        further discussion of our legal proceedings, please read Note 5 Commitments
        and
        Contingencies—Legal Proceedings in the Notes to Condensed Consolidated Financial
        Statements included in Item 1.
 
  **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, 2005.*
 
 We
        may
        not complete expansion projects that we commence, or we may complete projects
        on
        materially different terms or timing than anticipated and we may not be able
        to
        achieve the intended benefits of any such projects, if completed.
  We
          have
          announced significant expansion projects and may consider additional expansion
          projects in the future. We anticipate that we will be required to seek
          additional financing in the future to fund our current and future expansion
          projects and may not be able to secure such financing on favorable terms,
          or at
          all. We may not be able to complete the expansion projects on time as a
          result
          of delays in obtaining regulatory approvals, delays in obtaining key materials
          and land owner opposition. Further, even if expansion projects are completed
          the
          total costs of the expansion projects may be higher than anticipated and
          the
          performance of our business following the expansion projects may not meet
          expectations. In addition, we may not be able to timely and effectively
          integrate the expansion projects into our operations, such integration
          may
          result in unforeseen operating difficulties or unanticipated costs and
          the
          expansion projects might divert the attention of management from our other
          business concerns. Any of these or other factors could adversely affect
          our
          ability to realize the anticipated benefits from the expansion projects
          and thus
          have a material adverse effect on our business, financial condition, results
          of
          operations and cash flows.
 26
   **** **Item
        6. Exhibits**
  Exhibit
                DesignationRegistrant
              Nature
                  of Exhibit31.1
              Boardwalk
                  Pipeline Partners, LP
              Certification
                  of Rolf A. Gafvert, Co-President, pursuant to Rule 13a-14(a) and
                  Rule
                  15d-14(a)31.2
              Boardwalk
                  Pipeline Partners, LP
              Certification
                  of H. Dean Jones II, Co-President, pursuant to Rule 13a-14(a) and
                  Rule
                  15d-14(a)31.3
              Boardwalk
                  Pipeline Partners, LP
              Certification
                  of Jamie L. Buskill, Vice President and Chief Financial Officer,
                  pursuant
                  to Rule 13a-14(a) and Rule 15d-14(a)32.1
              Boardwalk
                  Pipeline Partners, LP
              Certification
                  by Rolf A. Gafvert, Co-President and H. Dean Jones, II, Co-President,
                  pursuant to Section 906 of the Sarbanes-Oxley Act of
                  200232.2
              Boardwalk
                  Pipeline Partners, LP
              Certification
                  of Jamie L. Buskill, Vice President and Chief Financial Officer,
                  pursuant
                  to Section 906 of the Sarbanes-Oxley Act of
                  2002
 
   27
   **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:
                  November 8, 2006
              
              By:
              */s/
                  Jamie L. Buskill*Jamie
                  L. BuskillVice
                  President and Chief Financial
                  Officer
 
  28