**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 March 31, 2007**
 
 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**
                **(270)
                  926-8686***(Address
                  and Telephone Number of Registrant’s Principal Executive
                  Office)*
 
 
 Indicate
        by check mark whether the registrant (1) has filed all reports required to
        be
        filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
        the
        preceding 12 months (or for such shorter period that the registrant was required
        to file such reports), and (2) has been subject to such filing requirements
        for
        the past 90 days. Yes x No o
 
 
 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 x   Non-accelerated
        filer o
 
 Indicate
        by check mark whether the registrant is a shell company (as defined in Rule
        12b-2 of the Exchange Act). Yes  ̈ No x
 
 As
        of
        April 20, 2007, the registrant had 83,156,122 common units outstanding and
        33,093,878 subordinated units outstanding.
 
 1
   **TABLE
        OF CONTENTS**
 
 **FORM
        10-Q**
 
 **MARCH
        31, 2007**
 
 **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 Partners’
Capital**
 **Condensed
        Consolidated Statements of 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
        2.  Unregistered Sales of Equity Securities and Use of
        Proceeds**
 **Item
        6.
        Exhibits**
 **Signature****s**
 
 
 
  2
  **PART
        I** **- FINANCIAL INFORMATION**
 
 **Item
        1.****Financial
        Statements**
 
 **BOARDWALK
        PIPELINE PARTNERS, LP**
 
 **CONDENSED
        CONSOLIDATED BALANCE SHEETS**
 **(Thousands
        of Dollars)**
 **(Unaudited)**
 
 
 **ASSETS**
              
              **March
                  31, 2007**
              
              **December
                  31, 2006**Current
                  Assets:Cash
                  and cash equivalents
              
              $
              563,179
              
              $
              399,032Receivables:Trade,
                  net
              
              
              54,011
              
              
              54,082Other
              
              
              9,344
              
              
              12,759Gas
                  Receivables:Transportation
                  and exchange
              
              
              10,518
              
              
              9,115Storage
              
              
              12,498
              
              
              11,704Inventories
              
              
              14,270
              
              
              14,110Costs
                  recoverable from customers
              
              
              7,742
              
              
              11,236Gas
                  stored underground
              
              
              15,108
              
              
              14,001Prepaid
                  expenses and other current assets
              
              
              8,739
              
              
              22,117Total
                  current assets
              
              
              695,409
              
              
              548,156Property,
                  Plant and Equipment:Natural
                  gas transmission plant
              
              
              2,176,231
              
              
              1,997,922Other
                  natural gas plant
              
              
              221,330
              
              
              213,9262,397,561
              
              
              2,211,848Less—Accumulated
                  depreciation and amortization
              
              
              206,353
              
              
              187,412Property,
                  plant and equipment, net
              
              
              2,191,208
              
              
              2,024,436Other
                  Assets:Goodwill
              
              
              163,474
              
              
              163,474Gas
                  stored underground
              
              
              139,055
              
              
              161,537Costs
                  recoverable from customers
              
              
              18,198
              
              
              19,767Other
              
              
              29,497
              
              
              33,929Total
                  other assets
              
              
              350,224
              
              
              378,707Total
                  Assets
              
              $
              3,236,841
              
              $
              2,951,299
 
 
 The
        accompanying notes are an integral part of these condensed consolidated
        financial statements.
  3
  **BOARDWALK
        PIPELINE PARTNERS, LP**
  **CONDENSED
        CONSOLIDATED BALANCE SHEETS**
 **(Thousands
        of Dollars, except number of units)**
 **(Unaudited)**
 
 **LIABILITIES
                  AND PARTNERS’ CAPITAL**
              
              **March
                  31, 2007**
              
              **December
                  31, 2006**Current
                  Liabilities:Payables:Trade
              
              $
              65,462
              
              $
              56,604Affiliates
              
              
              1,341
              
              
              3,014Other
              
              
              10,629
              
              
              14,459Gas
                  Payables:Transportation
                  and exchange
              
              
              8,996
              
              
              15,485Storage
              
              
              20,934
              
              
              42,127Other
                  accrued taxes
              
              
              17,233
              
              
              16,082Accrued
                  interest
              
              
              18,919
              
              
              19,376Accrued
                  payroll and employee benefits
              
              
              13,388
              
              
              18,198Deferred
                  income
              
              
              12,075
              
              
              22,147Other
                  current liabilities
              
              
              20,530
              
              
              20,926Total
                  current liabilities
              
              
              189,507
              
              
              228,418Long
                  -Term Debt
              
              
              1,351,152
              
              
              1,350,920Other
                  Liabilities and Deferred Credits:Pension
                  and postretirement benefits
              
              
              16,458
              
              
              15,761Asset
                  retirement obligation
              
              
              14,490
              
              
              14,307Provision
                  for other asset retirement
              
              
              40,228
              
              
              39,644Other
              
              
              33,551
              
              
              29,742Total
                  other liabilities and deferred credits
              
              
              104,727
              
              
              99,454Commitments
                  and ContingenciesPartners’
                  Capital:Common
                  units - 83,156,122 units and 75,156,122 units issued and outstanding
                  as of
                  March 31, 2007 and December 31, 2006
              
              
              1,253,099
              
              
              941,792Subordinated
                  units - 33,093,878 units issued and outstanding as of March 31,
                  2007 and
                  December 31, 2006
              
              
              295,628
              
              
              285,543General
                  partner
              
              
              28,702
              
              
              22,060Accumulated
                  other comprehensive income
              
              
              14,026
              
              
              23,112Total
                  partners’ capital
              
              
              1,591,455
              
              
              1,272,507Total
                  Liabilities and Partners’ Capital
              
              $
              3,236,841
              
              $
              2,951,299
 
 
 The
        accompanying notes are an integral part of these condensed consolidated
        financial statements.
 4
  **BOARDWALK
        PIPELINE PARTNERS, LP**
 
 **CONDENSED
        CONSOLIDATED STATEMENTS OF INCOME**
 **(Thousands
        of Dollars, except number of units and per unit amounts)**
 **(Unaudited)**
 **For
                  the Three Months Ended**
                **March
                  31,****2007**
              
              **2006**Operating
                  Revenues:Gas
                  transportation
              
              $
              152,913
              
              $
              151,012Parking
                  and lending
              
              
              18,382
              
              
              13,517Gas
                  storage
              
              
              7,711
              
              
              9,618Other
              
              
              9,106
              
              
              299Total
                  operating revenues
              
              
              188,112
              
              
              174,446Operating
                  Costs and Expenses:Operation
                  and maintenance
              
              
              39,459
              
              
              38,327Administrative
                  and general
              
              
              25,792
              
              
              27,388Depreciation
                  and amortization
              
              
              19,915
              
              
              18,683Taxes
                  other than income taxes
              
              
              7,961
              
              
              5,229Net
                  loss on disposal of operating assetsand related contracts
              
              
              2,639
              
              
              186Total
                  operating costs and expenses
              
              
              95,766
              
              
              89,813Operating
                  income
              
              
              92,346
              
              
              84,633Other
                  (Income) Deductions:Interest
                  expense
              
              
              16,797
              
              
              15,632Interest
                  income
              
              
              (4,574
              )
              
              (544
              )Interest
                  income from affiliates, net
              
              
              (7
              )
              
              -Miscellaneous
                  other income, net
              
              
              (334
              )
              
              (185
              )Total
                  other (income) deductions
              
              
              11,882
              
              
              14,903Income
                  before income taxes
              
              
              80,464
              
              
              69,730Income
                  taxes
              
              
              230
              
              
              -Net
                  income
              
              $
              80,234
              
              $
              69,730
 
 **For
                  the Three Months Ended**
                **March
                  31,****2007**
              
              **2006****Calculation
                  of limited partners’ interest in Net income:**Net
                  income
              
              $
              80,234
              
              $
              69,730Less
                  general partner’s interest in Net income
              
              
              1,811
              
              
              1,395Limited
                  partners’ interest in Net income
              
              $
              78,423
              
              $
              68,335Basic
                  and diluted net income per limited partner unit:Common
                  and subordinated units
              
              $
              0.61
              
              $
              0.58Cash
                  distribution to common and subordinated unitholders
              
              $
              0.415
              
              $
              0.179Weighted-average
                  number of limited partner units outstanding:Common
                  units
              
              
              75,956,122
              
              
              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 Three Months Ended**
                  **March
                    31,****2007**
                
                **2006**OPERATING
                    ACTIVITIES:Net
                    income
                
                $
                80,234
                
                $
                69,730Adjustments
                    to reconcile to cash providedby
                    operations:Depreciation
                    and amortization
                
                
                19,915
                
                
                18,683Amortization
                    of deferred costs
                
                
                1,823
                
                
                2,809Amortization
                    of acquired executory contracts
                
                
                (783
                )
                
                (1,852
                )Loss
                    on disposal of operating assets
                
                
                2,639
                
                
                186Changes
                    in operating assets and liabilities:Trade
                    and other receivables
                
                
                3,486
                
                
                617Gas
                    receivables and storage assets
                
                
                19,178
                
                
                41,626Costs
                    recoverable from customers
                
                
                3,606
                
                
                1,697Other
                    assets
                
                
                633
                
                
                (1,370
                )Trade
                    and other payables
                
                
                (14,537
                )
                
                (2,035
                )Gas
                    payables
                
                
                (24,188
                )
                
                (45,901
                )Accrued
                    liabilities
                
                
                (4,116
                )
                
                (14,316
                )Other
                    liabilities
                
                
                (10,548
                )
                
                3,399Net
                    cash provided by operating activities
                
                
                77,342
                
                
                73,273INVESTING
                    ACTIVITIES:Capital
                    expenditures
                
                
                (162,086
                )
                
                (21,779
                )Proceeds
                    from sale of operating assets
                
                
                429
                
                
                1,417Proceeds
                    from insurance reimbursements and other recoveries
                
                
                -
                
                
                960Advances
                    to affiliates, net
                
                
                662
                
                
                -Net
                    cash used in investing activities
                
                
                (160,995
                )
                
                (19,402
                )FINANCING
                    ACTIVITIES:Payments
                    of notes payable
                
                
                -
                
                
                (42,100
                )Distributions
                
                
                (46,052
                )
                
                (18,491
                )Proceeds
                    from sale of common units, net of related transaction
                    costs
                
                
                287,893
                
                
                -Capital
                    contribution from general partner
                
                
                5,959
                
                
                -Net
                    cash provided by (used in) financing activities
                
                
                247,800
                
                
                (60,591
                )Increase
                    (decrease) in cash and cash equivalents
                
                
                164,147
                
                
                (6,720
                )Cash
                    and cash equivalents at beginning of period
                
                
                399,032
                
                
                65,792Cash
                    and cash equivalents at end of period
                
                $
                563,179
                
                $
                59,072
 
 The
          accompanying notes are an integral part of these condensed consolidated
          financial statements.
 
  6
  **BOARDWALK
        PIPELINE PARTNERS, LP**
 
 **CONDENSED
        CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’
CAPITAL**
 **(Thousands
        of Dollars, except units)**
 **(Unaudited)**
 
 **Common**
                **Units**
              
              **Subordinated
                  Units**
              
              **General
                  Partner**
              
              **Accumulated
                  Other Comprehensive (Loss) Income**
              
              **Total
                  Partners’ Capital****Balance,
                  January 1, 2006**
              
              $
              705,609
              
              $
              266,578
              
              $
              16,661
              
              $
              (174
              )
              $
              988,674Add
                  (deduct):Net
                  income
              
              
              46,022
              
              
              22,313
              
              
              1,395
              
              
              -
              
              
              69,730Distributions
                  paid
              
              
              (12,204
              )
              
              (5,917
              )
              
              (370
              )
              
              -
              
              
              (18,491
              )Other
                  comprehensive income
              
              
              -
              
              
              -
              
              
              -
              
              
              4,226
              
              
              4,226Transaction
                  costs related to sale of common units
              
              
              (14
              )
              
              -
              
              
              -
              
              
              -
              
              
              (14
              )**Balance,
                  March 31, 2006**
              
              $
              739,413
              
              $
              282,974
              
              $
              17,686
              
              $
              4,052
              
              $
              1,044,125
 
 
  **Balance,
                  January 1, 2007**
              
              $
              941,792
              
              $
              285,543
              
              $
              22,060
              
              $
              23,112
              
              $
              1,272,507Add
                  (deduct):Net
                  income
              
              
              54,604
              
              
              23,819
              
              
              1,811
              
              
              -
              
              
              80,234Distributions
                  paid
              
              
              (31,190
              )
              
              (13,734
              )
              
              (1,128
              )
              
              -
              
              
              (46,052
              )Other
                  comprehensive income
              
              
              -
              
              
              -
              
              
              -
              
              
              (9,086
              )
              
              (9,086
              )Sale
                  of common units, net of related transaction costs (8,000,000
                  units)
              
              
              287,893
              
              
              -
              
              
              -
              
              
              -
              
              
              287,893Capital
                  contribution from general partner
              
              
              -
              
              
              -
              
              
              5,959
              
              
              -
              
              
              5,959**Balance,
                  March 31, 2007**
              
              $
              1,253,099
              
              $
              295,628
              
              $
              28,702
              
              $
              14,026
              
              $
              1,591,455
 
 The
        accompanying notes are an integral part of these condensed consolidated
        financial statements.
 
 
  7
  **BOARDWALK
        PIPELINE PARTNERS, LP**
 
 **CONDENSED
          CONSOLIDATED STATEMENTS OF COMPREHENSIVE
          INCOME**
 **(Thousands
          of Dollars)**
 **(Unaudited)** ****
 
 
 **For
                    the Three Months Ended**
                  **March
                    31,****2007**
                
                **2006**Net
                    income
                
                $
                80,234
                
                $
                69,730Other
                    comprehensive income:(Loss)
                    gain on cash flow hedges
                
                
                (7,537
                )
                
                7,018Reclassification
                    adjustment transferred to Net income
                
                
                (1,549
                )
                
                (2,792
                )Total
                    comprehensive income
                
                $
                71,148
                
                $
                73,956
  The
          accompanying notes are an integral part of these condensed consolidated
          financial statements.
  8
  
 **BOARDWALK
        PIPELINE PARTNERS, LP**
 
 **NOTES
        TO CONDENSED CONSOLIDATED FINANCIAL
        STATEMENTS**
 
 **(Unaudited)**
 
 
 **Note
        1:** **Basis
        of Presentation**
 
 Boardwalk
        Pipeline Partners, LP (the Partnership) is a Delaware limited partnership
        formed
        to own and operate the business conducted by Boardwalk Pipelines, LP (Boardwalk
        Pipelines) and its subsidiaries, Gulf South Pipeline Company, LP (Gulf South)
        and Texas Gas Transmission, LLC (Texas Gas) (together, the operating
        subsidiaries). The Partnership is a 74.8% owned subsidiary of Boardwalk
        Pipelines Holding Corp. (BPHC), which is wholly owned by Loews Corporation
        (Loews).
 
 The
        accompanying unaudited condensed consolidated financial statements of the
        Partnership were prepared pursuant to the rules and regulations of the United
        States Securities and Exchange Commission (SEC). Certain information and
        footnote disclosures normally included in financial statements prepared in
        accordance with accounting principles generally accepted in the United States
        of
        America (GAAP) have been condensed or omitted pursuant to such rules and
        regulations. In the
        opinion of management, t he
        accompanying condensed consolidated financial statements reflect
        all adjustments (consisting of only normal recurring accruals) necessary
        to
        present fairly the financial position as of March 31, 2007 and December 31,
        2006, and the results of operations and changes in cash flow for the three
        months ended March 31, 2007 and 2006. Reference is made to the Notes to
        Consolidated Financial Statements in the 2006 Annual Report on Form 10-K,
        which
        should be read in conjunction with these unaudited condensed consolidated
        financial statements. The
        accounting policies described in Note 2 to the Consolidated Financial Statements
        included in such Annual Report on Form 10-K are the same used in preparing
        the
        accompanying 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 2006 financial statements to conform
        to
        the 2007 presentation, primarily related to individual amounts and captions
        within the Operating Activities section of the Condensed Consolidated Statements
        of Cash Flows.
 
  **Note
        2:** **Gas
        in Storage and Gas Receivables/Payables**
 
 Gas
        receivables and payables reflect amounts of customer-owned gas at the Texas
        Gas
        facilities. Consistent
        with the method of storage accounting elected by Texas Gas and the risk-of-loss
        provisions included in its tariff, Texas
        Gas reflects an equal and offsetting receivable and payable for customer-owned
        gas in its facilities for storage and related services. The gas payables
        amount
        is reflected in Gas Payables on the Condensed Consolidated Balance Sheets
        and is
        valued at a historical cost of gas of $21.9 million and $45.7 million at
        March
        31, 2007 and December 31, 2006. Due to the method of storage accounting elected
        by Gulf South, the Partnership does not reflect volumes held by Gulf South
        on
        behalf of others on its Condensed Consolidated Balance Sheets. As of March
        31,
        2007 and December 31, 2006, Gulf South held 44.4 trillion British thermal
        units
        (TBtu) and 61.0 TBtu of gas owned by shippers. No gas was loaned by Gulf
        South
        to shippers as of March 31, 2007 and December 31, 2006.
 
 
 **Note
        3: Derivative Financial Instruments**
 
 Subsidiaries
        of the Partnership use futures, swaps, and option contracts (collectively,
        derivatives) to hedge exposure to various risks, including natural gas commodity
        risk and interest rate risk. These hedge contracts are reported at fair value
        in
        accordance with Statement of Financial Accounting Standards (SFAS) No. 133, *Accounting
        for Derivative Instruments and Hedging Activities,* as
        amended. The
        related unrealized gains and losses resulting from changes in fair values
        of the
        derivatives contracts designated as cash flow hedges are deferred as a component
        of Accumulated other comprehensive income. The deferred gains and losses
        are
        recognized in the Condensed Consolidated Statements of Income when the hedged
        anticipated transactions affect earnings.
 
 Certain
        volumes of gas stored underground are available for sale and subject to
        commodity price risk. At March 31, 2007 and December 31, 2006, approximately
        $15.1 million and $14.0 million, of Gulf South's gas stored underground,
        which
        the Partnership owns and carries as current Gas stored underground, is exposed
        to commodity price risk. Gulf South utilizes derivatives to hedge certain
        exposures to market price fluctuations on the anticipated operational sales
        of
        gas.
 
 9
 As
        a
        result of the
        Texas
        Gas Western Kentucky storage expansion project, approximately 4.8 billion
        cubic
        feet (Bcf) of gas stored underground with a book value of $11.3 million is
        available for sale. Approximately 3.0 Bcf of this gas is subject to forward
        sales agreements under which the ultimate sales price was determined in March
        2007, based on the price of New York Mercantile Exchange (NYMEX) natural
        gas
        futures. Texas Gas entered into derivatives to hedge the price exposure related
        to the storage gas. The derivatives associated with the volumes subject to
        forward sales agreements were designated as cash flow hedges during February
        2007, concurrent with the designation of the forward sales agreements as
        normal
        sales. Prior to the designation, these derivatives were marked to fair value
        through earnings along with the related forward sales agreements, resulting
        in a
        loss of $0.1 million in the first quarter 2007. The derivatives related to
        the
        remaining 1.8 Bcf of storage gas were also marked to fair value through earnings
        resulting in a loss of $2.0 million in the first quarter 2007.
 
 With
        the
        exception of the storage gas volumes referred to above, the derivatives related
        to the sale of natural gas and cash for fuel reimbursement generally qualify
        for
        cash flow hedge accounting under SFAS No. 133 and are designated as such.
        Generally, for gas sales and cash for fuel reimbursement, any gains and
        losses on the related derivatives would be recognized in Operating
        Revenues.  For the sale of gas related to the Western Kentucky storage
        expansion project, any gains and losses on the related derivatives would
        be
        recognized in Net loss on disposal of operating assets and related
        contracts.
 
 In
        August
        2006, the Partnership entered into Treasury rate locks with two counterparties
        each for a notional amount of $100.0 million of principal to hedge the risk
        attributable to changes in the risk-free component of forward 10-year interest
        rates through August 1, 2007. The reference rates on the rate locks are 5.00%
        and 4.96%. Under the terms of the rate locks, the counterparties would pay
        the
        Partnership settlement amounts if the 10-year Treasury rate is greater than
        the
        reference rates on August 1, 2007. Conversely, the Partnership would pay
        the
        counterparties settlement amounts if the 10-year Treasury rate is less than
        the
        reference rates. The Treasury rate locks were designated as cash flow hedges
        in
        accordance with SFAS No. 133. As of March 31, 2007, the Partnership reported
        a
        liability of $5.0 million, and a reduction in Accumulated other comprehensive
        income in an equal and offsetting amount less ineffectiveness recognized
        in 2007
        of less than $0.1 million, for the fair values of the rate locks.
 
 The
        fair
        values of derivatives existing as of March 31, 2007 and December 31, 2006,
        were
        included in the following captions in the Condensed Consolidated Balance
        Sheets
        (in millions):
 
 **March
                  31, 2007**
              
              **December
                  31, 2006**Prepaid
                  expenses and other current assets
              
              $
              2.3
              
              $
              13.7Other
                  current liabilities
              
              
              8.1
              
              
              5.1Accumulated
                  other comprehensive (loss) income
              
              
              (2.2
              )
              
              8.5
 
 The
        changes in fair values of the derivatives designated as cash flow hedges
        are
        expected to, and do, have a high correlation to changes in value of the
        anticipated transactions. Each reporting period the Partnership measures
        the
        effectiveness of the cash flow hedge contracts. To the extent the changes
        in the
        fair values of the hedge contracts do not effectively offset the changes
        in the
        estimated cash flows of the anticipated transactions, the ineffective portion
        of
        the hedge contracts is currently recognized in earnings. If the anticipated
        transactions are deemed no longer probable to occur, hedge accounting would
        be
        terminated and changes in the fair values of the associated derivative financial
        instruments would be recognized currently in the Condensed Consolidated
        Statements of Income.  Ineffectiveness recorded during the three month
        periods ended March 31, 2007 and 2006 was $0.4 million favorable and $0.5
        million unfavorable. No cash flow hedges were discontinued during the three
        month periods ended March 31, 2007 and 2006.
 
 
 **Note
        4: Income Taxes**
 
 The
        Partnership is not a taxable entity for federal income tax purposes. As such,
        it
        does not directly pay federal income tax. The Partnership’s taxable income or
        loss, which may vary substantially from the net income or loss reported in
        the
        Condensed Consolidated Statements of Income, is includable in the federal
        income
        tax returns of each partner. The aggregate difference in the basis of the
        Partnership’s net assets for financial and income tax purposes cannot be readily
        determined as it does not have access to the information about each partner’s
        tax attributes related to the Partnership. The
        Partnership’s subsidiaries directly incur some income-based state taxes which
        are presented in Income taxes on the Condensed Consolidated Statements of
        Income.
 
 
 
 
 10
 
 
 **Note
        5: Commitments and Contingencies**
 
 **A.
        Impact of Hurricanes Katrina and Rita**
 
 In
        August
        and September 2005, Hurricanes Katrina and Rita and related storm activity
        caused extensive and catastrophic physical damage to the offshore, coastal
        and
        inland areas in the Gulf Coast region of the United States. A substantial
        portion of the Gulf South assets and a smaller portion of the Texas Gas assets
        are located in the area directly impacted by the hurricanes.
  In
        the
        fourth quarter 2006, the Partnership recognized a receivable of $4.6 million
        associated with insurance claims deemed probable of recovery. Of this amount,
        approximately $0.5 million was received during the first quarter 2007. During
        the first quarter 2006, the Partnership accrued additional expenses of $2.1
        million and recognized $2.7 million of insurance proceeds related to Hurricane
        Katrina, which were received in the fourth quarter 2006. Through March 31,
        2007,
        the Partnership has received approximately $6.5 million in insurance proceeds
        related to the hurricanes. As of March 31, 2007 and December 31, 2006, the
        remaining liability for both hurricanes was $0.8 million and $1.0 million.
 
 **B.
        Legal Proceedings**
 
 ***Napoleonville
        Salt Dome Matter***
 
 In
        December 2003, natural gas leaks were observed near two natural gas storage
        caverns that were being leased and operated by Gulf South for natural gas
        storage in Napoleonville, Louisiana. Gulf South commenced remediation efforts
        immediately and ceased using those storage caverns. Several actions have
        been
        filed against Gulf South and other defendants by local residents and businesses
        as well as the lessor of the property; seeking monetary damages. Gulf South
        continues to vigorously defend each of these actions; however, it is not
        possible to predict the outcome of this litigation as the cases remain in
        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 *.*
 
 The
        remediation work related to the incident was completed in November 2006.
        Gulf
        South incurred $7.3 million for remediation costs, root cause investigation
        and
        legal fees. Gulf South has made demand for reimbursement from its insurance
        carriers and will continue to pursue recoveries of the costs incurred, including
        legal expenses. To date the insurance carriers have not taken any definitive
        coverage positions on all of the issues raised in the various lawsuits. Through
        March 31, 2007, Gulf South has received $0.8 million of insurance reimbursements
        for legal expenses and root cause investigation.
 
 ***Other
        Legal Matters***
  The
        Partnership's subsidiaries are parties to various other legal actions arising
        in
        the normal course of business. Management believes the disposition of all
        known
        outstanding legal actions will not have a material adverse impact on the
        Partnership's financial condition, results of operations or cash
        flows.
 
 
 **C.
        Regulatory and Rate Matters**
 
 ***Expansion
        Projects***
 
 *East
        Texas to Mississippi 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 Partnership’s 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 project is supported by binding precedent agreements
        with customers who have contracted, on a long-term basis (with a weighted
        average term of approximately 7 years), for 1.3 Bcf per day from Carthage,
        Texas
        with an option for an additional 100 million cubic feet (MMcf) per day. On
        September 1, 2006, the Partnership filed a certificate application relating
        to
        this project with the Federal Energy Regulatory Commission (FERC). The
        Partnership expects this project to be in service during the fall of 2007.
 
 11
 *Gulf
        Crossing Project.* The
        Partnership is pursuing construction of a new interstate pipeline that will
        begin near Sherman, Texas and proceed to the Perryville, Louisiana area.
        The
        project will be owned by a new subsidiary, Gulf Crossing Pipeline Company
        LLC
        (Gulf Crossing), and will consist of approximately 355 miles of 42-inch pipeline
        having capacity of up to approximately 1.6 Bcf per day. Additionally, Gulf
        Crossing will enter into: (i) a lease for at least 1.1 Bcf per day of capacity
        on the Partnership’s Gulf South pipeline system (including on the Southeast
        Expansion and a portion of the East Texas to Mississippi Expansion) to make
        deliveries to an interconnect with Transcontinental Pipe Line Company (Transco)
        in Choctaw County, Alabama; and (ii) a lease with a third-party intrastate
        pipeline which will bring certain gas supplies to the Partnership’s system. This
        project is supported by binding agreements with customers who have contracted
        for 1.1 Bcf per day of capacity under firm contracts having terms of 5 to
        10
        years (with a weighted average term of approximately 9.8 years), and options
        with certain of these customers for an additional 350 MMcf per day of capacity.
        The Partnership anticipates making the required filings with the FERC by
        July
        2007 and for the project to be in service during the fourth quarter 2008.
        The
        Partnership continues to engage in negotiations with one of the foundation
        shippers supporting this project concerning the possible purchase of up to
        a
        49.0% equity interest in Gulf Crossing.
 
 *Southeast
        Expansion* .
        The
        Partnership is pursuing a pipeline expansion extending its Gulf South pipeline
        system from near Harrisville, Mississippi to an interconnect with Transco
        in
        Choctaw County, Alabama which will enhance its ability to deliver gas to
        the
        Northeast through other pipeline interconnects. This expansion will consist
        of
        approximately 112 miles of 42-inch pipeline having initial capacity of
        approximately 1.2 Bcf per day, expandable to as much as 2.0 Bcf per day to
        accommodate volumes expected to come from the Gulf Crossing leased capacity
        discussed above. In addition, Gulf South has executed a lease with Destin
        Pipeline Company to access markets in Florida. This project is supported
        by
        binding agreements with customers who have contracted for 660 MMcf per day
        of
        capacity under firm contracts having terms of 5 to 10 years (with a
        weighted-average term of 8.7 years), as well as the capacity leased to Gulf
        Crossing discussed above. The certificate filing was made with the FERC in
        December 2006 and the project is anticipated to be in service during the
        first
        quarter 2008. The FERC issued a draft environmental impact statement for
        the
        expansion project on April 13, 2007.
  *Fayetteville
        Shale* .
        The
        Partnership is pursuing the construction of two laterals connected to the
        Partnership’s pipeline system to transport gas from the Fayetteville Shale area
        in Arkansas to markets directly and indirectly served by the Partnership’s
        pipelines. The Fayetteville Lateral, consisting of approximately 165 miles
        of
        36-inch pipeline, is anticipated to have an initial design capacity of 800
        MMcf
        per day. This lateral will originate in Conway County, Arkansas and proceed
        southeast through the Bald Knob, Arkansas area to an interconnect with the
        Partnership’s mainline in Coahoma County, Mississippi. The Greenville Lateral,
        consisting of approximately 95 miles of pipeline with an initial design capacity
        of 750 MMcf per day, will originate at the Partnership’s mainline near
        Greenville, Mississippi and proceed east to the Kosciusko, Mississippi area.
        The
        Greenville Lateral will allow customers to access additional markets, primarily
        in the Midwest, Northeast and Southeast. Construction of both laterals is
        supported by a binding precedent agreement with Southwestern Energy Services
        Company, a wholly-owned subsidiary of Southwestern Energy Company. In December
        2006, the Partnership initiated the pre-filing process with FERC for this
        project and anticipate making the required certificate filings with the FERC
        by
        July 2007. The Partnership expects the project to be in service during the
        first
        quarter 2009.
 
 The
        total
        cost of the pipeline expansion projects discussed above, before taking into
        account any potential equity contribution by the foundation shipper in Gulf
        Crossing or the exercise of customer options for additional capacity also
        discussed above, is estimated to be approximately $3.4 billion. The actual
        cost
        to complete these projects may exceed the current estimate as a result of,
        among
        other things, higher labor and materials costs due to the large number of
        pipeline projects under way throughout the industry, the need to expand pipeline
        capacity if the Partnership contracts for additional volumes, including as
        a
        result of option exercises, or design modifications.  For example, the cost
        estimate set forth above reflects the Partnership’s recent decision to increase
        the pipeline diameter for a portion of the Fayetteville Shale project to
        provide additional operational flexibility on that line.
 
 *Western
        Kentucky Storage Expansion.* In
        December 2006, the FERC issued a certificate approving the Phase II storage
        expansion project which will expand the working gas capacity in the
        Partnership’s western Kentucky storage complex by approximately 9.0 Bcf. This
        project is supported by binding commitments from customers to contract on
        a
        long-term basis for the full additional capacity at Texas Gas’ maximum
        applicable rate. The Partnership expects this project to cost approximately
        $40.7 million and to be in service by November 2007. In December 2006, Texas
        Gas
        commenced an open season related to a potential third expansion of its storage
        facilities and has signed one precedent agreement for 2.0 Bcf of storage
        capacity. The Phase III storage expansion is subject to the FERC approvals,
        including potential market-based rate authority for the additional new storage
        capacity being created.
 
 *Magnolia
        Storage Facility.* The
        Partnership is currently developing an additional storage cavern near
        Napoleonville, Louisiana. During mining operations, certain issues arose
        causing
        the mining of the cavern to be suspended. Operational integrity tests on
        the
        caverns are under way. Assuming favorable testing results, the Partnership
        expects the storage facilities to be in service perhaps as early as mid-2008
        with working gas capacity of approximately 2.0 Bcf, reduced from the original
        design capacity of 6.0 Bcf. The total book value of the project at March
        31,
        2007 and December 31, 2006 was $43.7 million and $42.7 million, respectively.
        The Partnership has tested 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 testing.
 
 
 
 12
 
 
 ***Pipeline
        Integrity***
 
 The
        Office of Pipeline Safety (OPS) has issued a final rule that requires natural
        gas pipeline operators to develop integrity management programs. Pursuant
        to the
        rule, pipelines were required to identify high consequence areas (HCAs) on
        their
        systems and develop a written integrity management program providing for
        a
        baseline assessment and periodic reassessments to be completed within specified
        timeframes. The Partnership has complied with these requirements. Its estimated
        costs to comply with the rule during the initial ten-year baseline period
        ending
        in 2012 range from $105.0 to $125.0 million. As of March 31, 2007, the
        Partnership has invested approximately $22.4 million to develop and implement
        integrity management programs that allow it to dynamically assess various
        pipeline risks on an integrated basis. The Partnership has systematically
        used
        smart, in-line inspection tools to verify the integrity of certain of its
        pipelines. **
  
 **D.
        Environmental and Safety Matters**
 
 The
        operating subsidiaries are subject to federal, state and local environmental
        laws and regulations in connection with the operation and remediation of
        various
        operating sites. The Partnership accrues for environmental expenses resulting
        from existing conditions that relate to past operations when the costs are
        probable and can be reasonably estimated. In addition to federal and state
        mandated remediation requirements, the Partnership often enters into voluntary
        remediation programs with the agencies.
 
 As
        of
        March 31, 2007 and December 31, 2006, the Partnership had an accrued liability
        of approximately $18.0 million and $18.4 million related to assessment and/or
        remediation costs associated with the historical use of polychlorinated
        biphenyls, petroleum hydrocarbons and mercury, enhancement of groundwater
        protection measures and other costs. These costs are expected to occur over
        approximately the next seven years. The accrual represents management’s estimate
        of the undiscounted future obligations based on evaluations and discussions
        with
        counsel and independent consultants and the current facts and circumstances
        related to these matters. As of March 31, 2007 and December 31, 2006,
        approximately $3.5 million was recorded in Other current liabilities. As
        of
        March 31, 2007 and December 31, 2006, approximately $14.5 million and $14.9
        million was recorded in Other Liabilities and Deferred Credits.
 
 On
        October 20, 2006, Texas Gas received notice from the Environmental Protection
        Agency (EPA) that Texas Gas is a potentially responsible party under the
        Comprehensive Environmental Response, Compensation, and Liability Act of
        1980
        with respect to the LWD, Inc. Superfund Site in Calvert City, 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.
 
 The
        Partnership’s pipelines are subject to the Clean Air Act (CAA) and the CAA
        Amendments of 1990 (Amendments) which added significant provisions to the
        CAA.
        The Amendments require the EPA to promulgate new regulations pertaining to
        mobile sources, air toxins, areas of ozone non-attainment and acid rain.
        The
        Partnership operates two facilities in areas affected by non-attainment
        requirements for the current ozone standard (eight-hour standard). As of
        March
        31, 2007, the Partnership had incurred costs of approximately $14.1 million
        for
        emission control modifications of compression equipment located at facilities
        required to comply with current CAA provisions, the Amendments and state
        implementation plans for nitrogen oxide reductions. These costs are being
        recorded as additions to property, plant and equipment (PPE) as the
        modifications are added. If the EPA designates additional new non-attainment
        areas where the Partnership operates, the cost of additions to PPE is expected
        to increase, however the Partnership is unable at this time to estimate with
        any
        certainty the cost of any additions that may be required.
  The
        Partnership considers environmental assessment, remediation costs, and costs
        associated with compliance with environmental standards to be recoverable
        through base rates, as they are prudent costs incurred in the ordinary course
        of
        business and, therefore, no regulatory asset has been recorded to defer these
        costs. The actual costs incurred will depend on the actual amount and extent
        of
        contamination discovered, the final cleanup standards mandated by the EPA
        or
        other governmental authorities and other factors.
 
 
 
 
 
 
 
 13
 
 
 
 
 **E.
        Commitments for Construction**
 
 The
        Partnership’s future capital commitments as of March 31, 2007, for contracts
        already authorized are expected to approximate the following amounts (in
        millions):
 
 Less
                  than 1 year
              
              $
              547.71-3
                  years
              
              
              231.14-5
                  years
              
              
              -More
                  than 5 years
              
              
              -Total
              
              $
              778.8
 
 The
        construction work in progress included in PPE, net in the Condensed Consolidated
        Balance Sheets was $369.2 million and $205.1 million as of March 31, 2007
        and
        December 31, 2006.
 
 
 **Note
        6: Net Income per Limited Partner Unit and Cash
        Distributions**
 
 The
        Partnership calculates net income per limited partner unit in accordance
        with
        Emerging Issues Task Force Issue No. 03-6 (EITF No. 03-6), *Participating Securities and the Two-Class Method under FASB Statement No.
        128* .  In
        Issue 3 of EITF No. 03-6, the EITF reached a consensus that undistributed
        earnings for a period should be allocated to a participating security based
        on the contractual participation rights of the security to share in those
        earnings as if all of the earnings for the period had been distributed. 
The Partnership's general partner holds contractual participation rights
        which
        are incentive distribution rights in accordance with the partnership agreement
        as follows:
 
 **Total
                  Quarterly Distribution**
              
              **Marginal Percentage Interest in**
                **Distributions****Target
                  Amount**
              **Common
                  and**
                **Subordinated**
                **Unitholders**
              
              **General Partner**Minimum
                  Quarterly Distribution
              
              $0.3500
              
              98%
              2%First
                  Target Distribution
              
              up to $0.4025
              
              98%
              2%Second
                  Target Distribution
              
              Above $0.4025 up to $0.4375
              
              85%
              15%Third
                  Target Distribution
              
              Above
                  $0.4375 up to $0.5250
              
              75%
              25%Thereafter
              
              above
                  $0.5250
              
              50%
              50%
 
 
 The amounts
        reported for net income per limited partner unit on the Condensed
        Consolidated Statements of Income for the three month periods ended March
        31, 2007 and 2006, were reduced to take into account an assumed allocation
        to the general partner's incentive distribution rights. Payments made on
        account
        of the incentive distribution rights are determined in relation to actual
        declared distributions and not based on the assumed allocation required by
        EITF
        No. 03-6.  A
        reconciliation of the limited partners' interest in net income and net income
        available to limited partners used in computing net income per limited partner
        unit is as follows (in thousands, except weighted average units and per unit
        data):
 
 **For
                    the Three Months Ended**
                  **March
                    31,****2007**
                
                **2006**Limited
                    partners' interest in net income
                
                $
                78,423
                
                $
                68,335Less
                    assumed allocation to incentive distribution rights
                
                
                12,055
                
                
                9,073Net
                    income available to limited partners
                
                $
                66,368
                
                $
                59,262Less
                    assumed allocation to subordinated units
                
                
                20,141
                
                
                19,351Net
                    income available to common units
                
                $
                46,227
                
                $
                39,911Weighted
                    average common units
                
                
                75,956,122
                
                
                68,256,122Weighted
                    average subordinated units
                
                
                33,093,878
                
                
                33,093,878Net
                    income per limited partner unit - common and subordinated
                    units
                
                $
                0.61
                
                $
                0.58
 
 14
 
 **Note
        7: Financing**
 
 In
        April
        2007, the Partnership’s revolving credit facility was amended to increase the
        aggregate commitments from $400.0 million to $700.0 million and to extend
        the
        term to June 29, 2012, among other modifications. As of March 31, 2007 and
        December 31, 2006, no funds were drawn under the facility. During
        April 2007, the Partnership issued letters of credit for $221.5 million to
        support certain obligations associated with the Fayetteville Shale expansion
        project which reduced the available capacity under the facility.
 
 In
        March
        2007, the Partnership completed a public offering of 8.0 million of its common
        units at a price of $36.50 per unit. The Partnership received proceeds of
        approximately $293.9 million, net of underwriting discounts and offering
        expenses, and including approximately $6.0 million from the general partner
        to
        maintain its 2.0% general partner interest. After the offering, the Partnership
        has 83.2 million common units issued and outstanding, of which 29.9 million
        are
        held by the public. The balance of the common units and all of the subordinated
        units are held by BPHC.
 
 As
        of
        March 31, 2007 and December 31, 2006 the weighted average interest rate of
        the
        Partnership’s long-term debt was 5.41%. The Partnership was in compliance with
        all loan covenants at March 31, 2007.
 
 During
        the three months ended March 31, 2007 and 2006, the Partnership capitalized
        interest of $2.1 million and less than $0.1 million.  In accordance
        with SFAS No. 71, *Accounting
        for the Effect of Certain Types of Regulation* ,
        the
        Partnership’s Texas Gas subsidiary capitalizes allowance for funds used during
        construction (AFUDC), comprised of debt and equity components. The Partnership
        capitalized $0.4 million and $0.2 million of AFUDC for the three months ended
        March 31, 2007 and 2006.
 
 
 **Note
        8: 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
        March
        31, 2007, the amount of gas loaned out by the Partnership’s subsidiaries was
        approximately 36.9 TBtu and, assuming an average market price during March
        2007
        of $7.07 per million British thermal units (MMBtu), the market value of gas
        loaned out at March 31, 2007 would have been approximately $260.9 million.
        If
        any significant customer of the Partnership should have credit or financial
        problems resulting in a delay or failure to repay the gas they owe to it
        this
        could have a material adverse effect on the Partnership’s financial condition,
        results of operations and cash flows.
 
 
 **Note
        9: Employee Benefits**
 
 Substantially
        all of Texas Gas' employees are covered under a non-contributory, defined
        benefit pension plan. Additionally, the Texas Gas Supplemental Retirement
        Plan
        provides pension benefits for the portion of an eligible employee’s pension
        benefit that becomes subject to compensation limitations under the Internal
        Revenue Code (IRC). Effective in November 2006, the defined benefit retirement
        plan was closed to new participants and new employees will be provided benefits
        under a defined contribution money purchase plan. All Gulf South employees
        are
        provided retirement benefits under a similar defined contribution money purchase
        plan. Texas Gas also provides postretirement life insurance and postretirement
        health care benefits to certain retired employees. The Partnership uses a
        measurement date of December 31 for its benefits plans.
 
 
 ***Early
        Retirement Incentive Program***
 
 In
        2006,
        Texas Gas implemented an early retirement incentive program (ERIP) which
        was
        made available to approximately 240 eligible non-executive employees.
        Retirements under the program were generally effective January 1, 2007.
        Approximately 100 of the eligible employees elected to participate in the
        program. In the first quarter 2007, the Partnership recognized a pension
        settlement charge related to the ERIP of approximately $3.1 million which
        was
        recorded in Administrative and general expense.
 
 
 
 15
 
 
 ***Components
        of Net Periodic Benefit Cost***
 
 Components
        of net periodic benefit cost for both the retirement plans and post retirement
        benefits other than pensions (PBOP) for the years ended March 31, 2007 and
        2006
        were the following (in thousands):
 
  **Retirement
                  Plans**
              
              **PBOP****For
                  the Year Ended March 31,**
              
              **For
                  the Year Ended March 31,****2007**
              
              **2006**
              
              **2007**
              
              **2006**Service
                  cost
              
              $
              930
              
              $
              1,079
              
              $
              155
              
              $
              641Interest
                  cost
              
              
              1,682
              
              
              1,614
              
              
              900
              
              
              1,944Expected
                  return on plan assets
              
              
              (1,885
              )
              
              (1,775
              )
              
              (1,168
              )
              
              (1,169
              )Amortization
                  of prior service credit
              
              
              1
              
              
              -
              
              
              (1,940
              )
              
              -Amortization
                  of unrecognized net loss
              
              
              77
              
              
              100
              
              
              298
              
              
              440Settlement
                  charge (ERIP)
              
              
              3,100
              
              
              -
              
              
              -
              
              
              -Regulatory
                  asset decrease
              
              
              -
              
              
              250
              
              
              1,354
              
              
              3,266Net
                  periodic pension expense
              
              $
              3,905
              
              $
              1,268
              
              $
              (401
              )
              $
              5,122
 
 The
        decrease in the regulatory asset for PBOP is due primarily to the amortization
        of costs incurred in prior years.
 
 
 ***Defined
        Contribution Plans***
 
 The
        Partnership maintains defined contribution plans covering substantially all
        of
        its employees. Costs related to these plans were $1.2 million for each of
        the
        three months ended March 31, 2007 and 2006.
 
 
 **Note
        10: Related Parties**
 
 Loews
        provides a variety of corporate services to the Partnership and its subsidiaries
        under services agreements. Services provided by Loews include, among others,
        information technology, tax, risk management, internal audit and corporate
        development services. Loews charged $4.2 million and $4.1 million for the
        three
        months ended March 31, 2007 and 2006, respectively, to the Partnership based
        on
        the actual time spent by Loews personnel performing these services, plus
        related
        expenses.
  Distributions
        paid on common and subordinated units held by BPHC and the 2.0% general partner
        interest and incentive distribution rights held by Boardwalk GP, LP were
        $37.0
        million and $15.8 million during the first quarter 2007 and 2006. In addition,
        as a result of the public offering of common units in March 2007, the general
        partner contributed approximately $6.0 million to maintain its general partner
        interest.
 
 
 **Note
        11: Distributions**
 
 T he
        Partnership has declared quarterly distributions per unit to unitholders
        of
        record, including common and subordinated units and the 2.0% general partner
        interest held by its general partner as follows:
 
 **Record
                  Date**
              
              **Payable
                  Date**
              
              **Distribution
                  per Unit**May
                  7, 2007
              
              May
                  14, 2007
              
              0.43February
                  20, 2007
              
              February
                  27, 2007
              
              0.415October
                  30, 2006
              
              November
                  6, 2006
              
              0.40August
                  11, 2006
              
              August
                  18, 2006
              
              0.38May
                  12, 2006
              
              May
                  19, 2006
              
              0.36February
                  16, 2006
              
              February
                  23, 2006
              
              0.179*
 
 *Distribution
                  represented a prorated portion of the $0.35 per unit “minimum quarterly
                  distribution” (as defined in the Partnership’s partnership agreement) for
                  the period November 15, 2005 through December 31,
                  2005.
 
 16
 The
        Partnership also pays cash distributions to its general partner on account
        of
        its incentive distribution rights with respect to that portion of a quarterly
        distribution in excess of $0.4025 per unit. These payments were $0.2 million
        in
        February 2007 and will be $0.5 million in May 2007.
 
 
 **Note
        12: Accumulated Other Comprehensive Income**
 
 The
        following table shows the components of Accumulated other comprehensive income
        at March 31, 2007 and December 31, 2006 (in thousands):
 
 **As
                  of March 31, 2007**
              
              **As
                  of December 31, 2006**(Loss)
                  gain on cash flow hedges
              
              $
              (2,197
              )
              $
              8,309Deferred
                  components of net periodic benefit cost
              
              
              16,223
              
              
              14,803Total
                  Accumulated other comprehensive income
              
              $
              14,026
              
              $
              23,112
 
 
 **Note
        13: Guarantee of Securities of Subsidiaries**
 
 The
        Partnership has no independent assets or operations other than its investment
        in
        its subsidiaries. The Partnership’s operating subsidiaries have issued
        securities which have all been fully and unconditionally guaranteed by the
        Partnership. The Partnership does have separate partners’ capital including
        publicly traded limited partner common units.
 
 The
        Partnership’s subsidiaries have no significant restrictions on their ability to
        pay distributions or loans to the Partnership and have no restricted assets
        at
        March 31, 2007.
 
 
 **Note
        14: Recently Issued Accounting Pronouncements**
 
 *SFAS
        No. 157*
 
 On
        September 15, 2006, the Financial Accounting Standards Board (FASB) issued
        SFAS
        No. 157, *Fair
        Value Measurements* .
        Fair
        value refers to the price that would be received to sell an asset or paid
        to
        transfer a liability in an orderly transaction between market participants
        in
        the market in which the reporting entity transacts. The standard clarifies
        the
        principle that fair value should be based on the assumptions market participants
        would use when pricing the asset or liability. In support of this principle,
        the
        standard establishes a fair value hierarchy that prioritizes the information
        used to develop those assumptions. The fair value hierarchy gives the highest
        priority to quoted prices in active markets and the lowest priority to
        unobservable data, for example, the reporting entity's own data. Under the
        standard, fair value measurements would be separately disclosed by level
        within
        the fair value hierarchy. The Statement is effective for financial statements
        issued for fiscal years beginning after November 15, 2007, and interim periods
        within those fiscal years. The Partnership is currently evaluating the
        impact, if any, that SFAS No. 157 would have on its financial condition,
        results of operations or cash flows.
 
 
 *SFAS
        No. 159*
 
 In
        February 2007, the FASB issued SFAS No. 159, *The
        Fair Value Option for Financial Assets and Financial Liabilities- including
        an
        amendment of SFAS No. 115.* SFAS
        No.
        159 allows companies to elect to measure many financial assets and financial
        liabilities at fair value. Unrealized gains and losses on items for which
        the
        fair value option has been chosen are reported in earnings. SFAS No. 159
        is
        effective for fiscal years beginning after November 15, 2007. The Partnership
        is
        currently evaluating the impact, if any, of adopting SFAS No. 159 on its
        financial condition, results of operations or cash flows.
  17
  
 **Item
        2. Management's Discussion and Analysis of Financial Condition
        and Results of Operations**
 
 *The
        following discussion and analysis of financial condition and results of
        operations should be read in conjunction with our accompanying interim condensed
        consolidated financial statements and related Notes, included elsewhere in
        this
        report and prepared in accordance with accounting principles generally accepted
        in the United States of America (GAAP) and our consolidated financial
        statements, related notes, management's discussion and analysis of financial
        condition and results of operations and Risk Factors included* *in
        our Annual Report on Form 10-K for the year ended December 31,
        2006.*
 
 We
        are a
        Delaware limited partnership formed to own and operate the business conducted
        by
        Boardwalk Pipelines, LP (Boardwalk Pipelines) and its subsidiaries, Gulf
        South
        Pipeline Company, LP (Gulf South) and Texas Gas Transmission, LLC (Texas
        Gas)
        (together, the operating subsidiaries). We own and operate pipeline systems
        in
        the Gulf Coast states of Texas, Louisiana, Mississippi, Alabama, and Florida
        and
        which extend northward through Arkansas to the Midwestern states of Tennessee,
        Kentucky, Illinois, Indiana, and Ohio.
 
  **Results
        of Operations - Business Overview**
  We
        derive
        our revenues primarily from the interstate transportation and storage of
        natural
        gas for third parties. Transportation and storage services are provided under
        firm and interruptible service agreements. Transportation rates are subject
        to
        maximum tariff rates established by the Federal Energy Regulatory Commission
        (FERC), although many services are provided at a discount to the maximum
        tariff
        rates due to competition in the marketplace.  Our
        Gulf
        South subsidiary is authorized to charge market-based rates for its firm
        and
        interruptible storage services.
 
 We
        are
        not in the business of buying and selling natural gas other than for system
        management and operational purposes, but changes in the price of natural
        gas can
        affect the overall supply and demand of natural gas which in turn does affect
        our results of operations. We deliver to a broad mix of customers including
        local distribution companies (LDCs), municipalities, interstate and intrastate
        pipelines, direct industrial users, electric power generation plants, marketers
        and producers. In addition to serving directly connected markets, our pipeline
        systems have indirect market access to the northeastern and southeastern
        United
        States through interconnections with unaffiliated pipelines.
 
 Under
        firm transportation agreements, customers generally pay a fixed “demand” or
“capacity reservation” charge to reserve pipeline capacity at certain receipt
        and delivery points, plus a commodity and fuel charge paid on the volume
        of gas
        actually transported. Firm storage customers reserve a specific amount of
        storage capacity and injection and withdrawal capability and generally pay
        a
        capacity reservation charge based on the amount of capacity being reserved
        plus
        an injection and/or withdrawal fee. Capacity reservation revenues derived
        from a
        firm service contract (including no-notice storage service) are generally
        consistent during the contract term, but can be higher in winter peak periods,
        especially related to no-notice storage agreements, than in off-peak periods.
        The seasonal effect is also impacted by increased revenues generated from
        usage
        during the winter peak periods.
 
 Interruptible
        transportation and storage services are typically short-term in nature and
        are
        generally used by customers that do not require the certainty of delivery
        that
        is provided with firm services. Customers pay for interruptible services
        when
        the service is used.
 
 Revenues
        for our parking and lending (PAL) services and certain of our storage services
        for which we are authorized to charge market-based rates are affected by
        period-to-period natural gas price spreads (for example, summer to
        winter).  In recent periods, these price spreads have been wider and
        more volatile than in previous years, resulting in significant
        increases in parking and lending and storage revenues.  We are uncertain if
        these recent favorable trends in period-to-period natural gas price spreads
        will
        continue. A reversal of this trend could result in lower revenues and profits
        from these services in future periods.
 
 Operating
        expenses typically do not vary significantly based upon the amount of gas
        transported with the exception of gas consumed by Gulf South’s compressor
        stations. Gulf South’s fuel recoveries are included as part of transportation
        revenues.
 
 
 
 18
 
 
 
  **Results
        of Operations for the Three Months Ended March 31, 2007 and
        2006**
 
 Our
        net
        income for the first quarter 2007 increased $10.5 million or 15.1% from the
        comparable 2006 period.  The primary drivers for the increase were higher
        revenues from pipeline system expansion, strong demand for firm transportation
        services and increased utilization, and a continued strong environment
        for PAL and storage services.
 
 Operating
        revenues for the first quarter 2007 increased $13.7 million, or 7.9%, to
        $188.1
        million, compared to $174.4 million for the first quarter 2006 primarily
        due
        to:
 
 ·
            $5.9
                million increase in transportation fees due to revenues from the
                Carthage,
                Texas to Keatchie, Louisiana pipeline expansion project which was
                placed
                in service at the end of 2006, strong demand for firm transportation
                services due to wide natural gas basis differentials primarily between
                South and East Texas and other points on our system, and increased
                utilization; ·
            $5.9
                million increase in operating revenues driven primarily from higher
                fuel
                revenues from increased throughput and retained volumes;
                and ·
            $3.0
                million increase in PAL and storage services mainly due to favorable
                natural gas price spreads and volatility in forward natural gas prices. 
 These
        increases were partly offset by:
 
 ·
            a
                $1.1 million decrease in revenues from the amortization of acquired
                executory contracts. 
 Operating
        expenses for the first quarter 2007 increased $6.0 million, or 6.7%, to $95.8
        million, compared to $89.8 million for the first quarter 2006 primarily due
        to:
 
 ·
            $3.1
                million pension settlement charge related to the early retirement
                incentive program (ERIP); ·
            $2.8
                million increase in property and other taxes resulting primarily
                as a
                result of a reversal of a franchise tax accrual in the 2006
                period; ·
            $2.1
                million loss on mark-to-market adjustment associated with derivatives
                on
                storage gas volumes; ·
            $1.6
                million increase in administrative expenses and outside services
                mainly
                due to growth in operations and regulatory compliance;
                and ·
            $1.2
                million increase in depreciation and amortization resulting primarily
                from
                increased property, plant and equipment. 
 These
        increases were partly offset by:
 
 ·
            a
                $5.5 million decline in PBOP costs primarily as a result of plan
                changes
                in the second half of 2006. 
 Total
        other deductions for the first quarter 2007 declined by $3.0 million, or
        20.1%,
        to $11.9 million, compared to $14.9 million for the first quarter 2006. The
        decline is primarily due to an increase in interest income of $4.0 million
        as a
        result of higher levels of cash invested, partially offset by higher interest
        expense of $1.2 million driven by increased levels of outstanding long-term
        debt.
 
 
 **Capital
        Expenditures**
 
 Capital
        expenditures for the three months ended March 31, 2007 and 2006 were $162.1
        million and $21.8 million. For the year ending December 31, 2007, we expect
        to
        make capital expenditures of approximately $1.9 billion, of which we expect
        approximately $1.8 billion to be for the expansion projects discussed below
        and
        approximately $60.0 million to be for maintenance capital. The amount of
        expansion capital we expend in 2007 could vary significantly depending on
        the
        progress made with these projects, the number and types of other capital
        projects we decide to pursue, the timing of any of those projects and numerous
        other factors beyond our control.
 
 We
        expect
        to fund our expansion capital expenditures for 2007 and beyond with proceeds
        from sales of our debt and equity securities, borrowings under our revolving
        credit facility and operating cash flows, though we have not made any
        determination with regard to such financing. We expect to fund our maintenance
        capital expenditures from operating cash flows.
  19
 We
        are
        currently engaged in the following expansion projects:
 
 ·
            *East
                Texas to Mississippi 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 billion cubic
                feet
                (Bcf) per day of new transmission capacity to our 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 project is supported by binding precedent agreements with customers
                who have contracted, on a long-term basis (with a weighted average
                term of
                approximately 7 years), for 1.3 Bcf per day from Carthage, Texas
                with an
                option for an additional 100 million cubic feet (MMcf) per day. On
                September 1, 2006, we filed a certificate application relating to
                this
                project with the FERC. We expect this project to be in service during
                the
                fall of 2007. 
 ·
            *Gulf
                Crossing Project.*We
                are pursuing construction of a new interstate pipeline that will
                begin
                near Sherman, Texas and proceed to the Perryville, Louisiana area.
                The
                project will be owned by a new subsidiary, Gulf Crossing Pipeline
                Company
                LLC (Gulf Crossing), and will consist of approximately 355 miles
                of
                42-inch pipeline having capacity of up to approximately 1.6 Bcf per
                day.
                Additionally, Gulf Crossing will enter into: (i) a lease for at least
                1.1
                Bcf per day of capacity on our Gulf South pipeline system (including
                on
                the Southeast Expansion and a portion of the East Texas to Mississippi
                Expansion) to make deliveries to an interconnect with Transcontinental
                Pipe Line Company (Transco) in Choctaw County, Alabama; and (ii)
                a lease
                with a third-party intrastate pipeline which will bring certain gas
                supplies to our system. This project is supported by binding agreements
                with customers who have contracted for 1.1 Bcf per day of capacity
                under
                firm contracts having terms of 5 to 10 years (with a weighted average
                term
                of approximately 9.8 years), and options with certain of these customers
                for an additional 350 MMcf per day of capacity. We anticipate making
                the
                required filings with the FERC by July 2007 and for the project to
                be in
                service during the fourth quarter 2008. We continue to engage in
                negotiations with one of the foundation shippers supporting this
                project
                concerning the possible purchase of up to a 49.0% equity interest
                in Gulf
                Crossing. 
 ·
            *Southeast
                Expansion*.
                We are pursuing a pipeline expansion extending our Gulf South pipeline
                system from near Harrisville, Mississippi to an interconnect with
                Transco
                in Choctaw County, Alabama which will enhance our ability to deliver
                gas
                to the Northeast through other pipeline interconnects. This expansion
                will
                consist of approximately 112 miles of 42-inch pipeline having initial
                capacity of approximately 1.2 Bcf per day, expandable to as much
                as 2.0
                Bcf per day to accommodate volumes expected to come from the Gulf
                Crossing
                leased capacity discussed above. In addition, Gulf South has executed
                a
                lease with Destin Pipeline Company to access markets in Florida.
                This
                project is supported by binding agreements with customers who have
                contracted for 660 MMcf per day of capacity under firm contracts
                having
                terms of 5 to 10 years (with a weighted-average term of 8.7 years),
                as
                well as the capacity leased to Gulf Crossing discussed above. The
                certificate filing was made with the FERC in December 2006 and the
                project
                is anticipated to be in service during the first quarter 2008. The
                FERC
                issued a draft environmental impact statement for the expansion project
                on
                April 13, 2007. 
 ·
            *Fayetteville
                Shale*.
                We are pursuing the construction of two laterals connected to our
                pipeline
                system to transport gas from the Fayetteville Shale area in Arkansas
                to
                markets directly and indirectly served by our pipelines. The Fayetteville
                Lateral, consisting of approximately 165 miles of 36-inch pipeline,
                is
                anticipated to have an initial design capacity of 800 MMcf per day.
                This
                lateral will originate in Conway County, Arkansas and proceed southeast
                through the Bald Knob, Arkansas area to an interconnect with our
                mainline
                in Coahoma County, Mississippi. The Greenville Lateral, consisting
                of
                approximately 95 miles of pipeline with an initial design capacity
                of 750
                MMcf per day, will originate at our mainline near Greenville, Mississippi
                and proceed east to the Kosciusko, Mississippi area. The Greenville
                Lateral will allow customers to access additional markets, primarily
                in
                the Midwest, Northeast and Southeast. Construction of both laterals
                is
                supported by a binding precedent agreement with Southwestern Energy
                Services Company, a wholly-owned subsidiary of Southwestern Energy
                Company. In December 2006, we initiated the pre-filing process with
                FERC
                for this project and anticipate making the required certificate filings
                with the FERC by July 2007. We expect the project to be in service
                during
                the first quarter 2009. 
 The
        total
        cost of the pipeline expansion projects discussed above, before taking into
        account any potential equity contribution by the foundation shipper in Gulf
        Crossing or the exercise of customer options for additional capacity also
        discussed above, is estimated to be approximately $3.4 billion. The actual
        cost
        to complete these projects may exceed the current estimate as a result of,
        among
        other things, higher labor and materials costs due to the large number of
        pipeline projects under way throughout the industry, the need to expand pipeline
        capacity if we contract for additional volumes, including as a result of
        option
        exercises, or design modifications.  For example, the cost estimate set
        forth above reflects our recent decision to increase the pipeline diameter
        for a
        portion of the Fayetteville Shale project to provide additional operational
        flexibility on that line.
 
 20
 ·
            *Western
                Kentucky Storage Expansion.*In
                December 2006, the FERC issued a certificate approving our Phase
                II
                storage expansion project which will expand the working gas capacity
                in
                our western Kentucky storage complex by approximately 9.0 Bcf. This
                project is supported by binding commitments from customers to contract
                on
                a long-term basis for the full additional capacity at Texas Gas’ maximum
                applicable rate. We expect this project to cost approximately $40.7
                million and to be in service by November 2007. In December 2006,
                Texas Gas
                commenced an open season related to a potential third expansion of
                its
                storage facilities and has signed one precedent agreement for 2.0
                Bcf of
                storage capacity. The Phase III storage expansion is subject to the
                FERC
                approvals, including potential market-based rate authority for the
                additional new storage capacity being created. 
 ·
            *Magnolia
                Storage Facility.*We
                are currently developing an additional storage cavern near Napoleonville,
                Louisiana. During mining operations, certain issues arose causing
                the
                mining of the cavern to be suspended. Operational integrity tests
                on the
                caverns are under way. Assuming favorable testing results, we expect
                the
                storage facilities to be in service perhaps as early as mid-2008
                with
                working gas capacity of approximately 2.0 Bcf, reduced from the original
                design capacity of 6.0 Bcf. The total book value of the project at
                March
                31, 2007 and December 31, 2006 was $43.7 million and $42.7 million,
                respectively. We tested 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 testing. 
 
 **Distributions**
 
 Note
        11
        in Item 1 of this Report contains information regarding our
        distributions.
 
  **Liquidity
        and Capital Resources**
 
 We
        are a
        limited partnership holding company and derive all of our operating cash
        flow
        from our operating subsidiaries. Boardwalk Pipelines uses cash provided from
        its
        subsidiaries 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.
 
 In
        April
        2007, our revolving credit facility was amended to increase the aggregate
        commitments from $400.0 million to $700.0 million and to extend the term
        to June
        29, 2012, among other modifications. As of March 31, 2007 and December 31,
        2006,
        no funds were drawn under the facility. During April 2007, we issued letters
        of
        credit for $221.5 million to support certain obligations associated with
        the
        Fayetteville Shale expansion project which reduced the available capacity
        under
        the facility.
 
 In
        March
        2007, we completed a public offering of 8.0 million of our common units.
        We
        received proceeds of approximately $293.9 million, net of underwriting discounts
        and offering expenses, and including approximately $6.0 million from our
        general
        partner to maintain its 2.0% general partner interest. The proceeds will
        primarily be used to fund capital expenditures associated with the expansion
        projects. After the offering, we have 83.2 million common units issued and
        outstanding, of which 29.9 million are held by the public. The balance of
        the
        common units plus all of the subordinated units are held by Boardwalk Pipelines
        Holding Corp. (BPHC).
 
 
 **Changes
        in cash flow from operating activities**
  Net
        cash
        provided by operating activities increased $4.1 million, or 5.6%, to $77.3
        million for the three months ended March 31, 2007, compared to $73.2 million
        for
        the comparable 2006 period, primarily due to:
 
 ·  $11.8
        million improvement in net income, excluding non-cash items such as depreciation
        and amortization was primarily driven by an increase in revenues;
 ·  $2.5
        million increase in the loss on disposal of operating assets; and
 ·  $10.1
        million decrease in deferred income primarily as a result of higher income
        on PAL agreements.
 
 **Changes
        in cash flow from investing activities**
  Net cash used in investing activities increased $141.6 million to $161.0
        million
        for the three months ended March 31, 2007, compared to $19.4 million for
        the
        comparable 2006 period, primarily due to a $140.3 million increase in capital
        expenditures mainly for our expansion projects.
 
 21
 **Changes
        in cash flow from financing activities**
 
 Net
        cash
        provided by (used in) financing activities increased $308.3 million to $247.8
        million for the three months ended March 31, 2007, compared to a use of $60.5
        million for the comparable 2006 period 2006, primarily due to  $293.9
        million in net equity offering proceeds from the sale of 8,000,000 units
        and
        related general partner capital contribution in March 2007.
 
 
 **Contractual
        Obligations**
 
 The
        table
        below is updated for significant changes in capital commitments from those
        included in the 2006 Annual Report on Form 10-K by period (in millions):
  **Payments
                  due by Period****Total**
              
              **Less than**
                **1
                  Year**
              
              **1-3 Years**
              
              **4-5 Years**
              
              **More than**
                **5
                  Years**Capital
                  commitments
              
              $
              778.8
              
              $
              547.7
              
              $
              231.1
              
              $
              -
              
              $
              -
 
 The
        capital commitments for construction were primarily related to the pipeline
        expansion projects. For further discussion of the expansion projects please
        read
        Note 5C *Expansion
        Projects* in the
        Notes to condensed consolidated financial statements included in Item 1.
 
 
 **Off
        Balance Sheet Arrangements**
  At
        March
        31, 2007, we had no guarantees of off balance sheet debt to third parties,
        no
        debt obligations that contain provisions requiring accelerated payment of
        the
        related obligations in the event of specified levels of declines in credit
        ratings, and no other off balance sheet arrangements.
 
 
 **Critical
        Accounting Policies and Estimates**
  Certain
        amounts included in or affecting our condensed consolidated financial statements
        and related disclosures must be estimated, requiring us to make certain
        assumptions with respect to values or conditions that cannot be known with
        certainty at the time the financial statements are prepared. These estimates
        and
        assumptions affect the amounts we report for assets and liabilities and our
        disclosure of contingent assets and liabilities at the date of our financial
        statements. We evaluate these estimates on an ongoing basis, utilizing
        historical experience, consultation with third parties and other methods
        we
        consider reasonable. Nevertheless, actual results may differ significantly
        from
        our estimates. Any effects on our business, financial position or results
        of
        operations resulting from revisions to these estimates are recorded in the
        period in which the facts that give rise to the revision become
        known.
 
 During
        the first quarter 2007, there were no significant changes to our critical
        accounting policies, judgments or estimates from those disclosed in our Annual
        Report on Form 10-K for the year ended December 31, 2006.
 
 
 **Forward-Looking
        Statements**
 
 Investors
        are cautioned that certain statements contained in this report as well as
        some
        statements in periodic press releases and some oral statements made by our
        officials and our subsidiaries during presentations about us, are
“forward-looking” statements 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 our partnership or its
        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:
 
 22
 ·
            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. 
 ·
            The
                successful completion, timing, cost, scope and future financial
                performance of our expansion projects could differ materially from
                our
                expectations due to availability of contractors, weather, untimely
                regulatory approvals or denied applications, land owner opposition,
                the
                lack of adequate materials, labor difficulties, difficulties we may
                encounter with partners or potential partners, expansion cost higher
                than
                anticipated and numerous other factors beyond our
                control. 
 ·
            We
                may not complete any future debt or equity financing transaction,
                including any sale of an interest in Gulf Crossing
                Pipeline. 
 ·
            The
                gas transmission and storage operations of our subsidiaries are subject
                to
                rate-making policies and actions by the FERC or customers that could
                have
                an adverse impact on the rates we charge and the revenues we collect,
                including our ability to recover our income tax allowance, our full
                cost
                of operating our pipelines and a reasonable return. 
 ·
            We
                are subject to laws and regulations relating to the environment and
                pipeline operations which may expose us to significant costs, liabilities
                and loss of revenues. Any changes in such regulations or their application
                could negatively affect our business, financial condition and results
                of
                operations. 
 ·
            Our
                operations are subject to operational hazards and unforeseen interruptions
                for which we may not be adequately
                insured. 
 ·
            The
                cost of insuring our assets may increase
                dramatically. 
 ·
            Because
                of the natural decline in gas production from existing wells, our
                success
                depends on our ability to obtain access to new sources of natural
                gas,
                which is dependent on factors beyond our control. Any decrease in
                supplies
                of natural gas in our supply areas could adversely affect our business,
                financial condition and results of
                operations. 
 ·
            Successful
                development of LNG import terminals in the eastern or northeastern
                United
                States could reduce the demand for our
                services. 
 ·
            We
                may not be able to maintain or replace expiring gas transportation
                and
                storage contracts at favorable rates. 
 ·
            Significant
                changes in natural gas prices could affect supply and demand, reducing
                system throughput and adversely affecting our
                revenues. 
 Developments
        in any of these areas could cause our results to differ materially from results
        that have been or may be anticipated or projected. Forward-looking statements
        speak only as of the date of this report and we expressly disclaim any
        obligation or undertaking to update these statements to reflect any change
        in
        our expectations or beliefs or any change in events, conditions or circumstances
        on which any forward-looking statement is based.
 
  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
        March
        31, 2007, had a carrying value of $1.4 billion and a fair value of $1.3 billion.
        The weighted-average interest rate of our long-term debt was 5.41% at March
        31,
        2007.
 
 In
        August
        2006, we entered into Treasury rate locks with two counterparties each for
        a
        notional amount of $100.0 million of principal to hedge the risk attributable
        to
        changes in the risk-free component of forward 10-year interest rates through
        August 1, 2007. The reference rates on the rate locks are 5.00% and 4.96%.
        Under
        the terms of the 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. A 10 basis point
        decrease in the 10-year Treasury rate would result in a $1.6 million favorable
        change in the value of the rate locks. Conversely, a 10 basis point increase
        in
        the 10-year Treasury rate would result in a $1.6 million unfavorable change
        in
        the value of the rate locks. The Treasury rate locks were designated as cash
        flow hedges in accordance with Statement of Financial Accounting Standards
        (SFAS) No. 133. As of March 31, 2007, we reported a liability of $5.0 million,
        and a reduction in Accumulated other comprehensive income in an equal and
        offsetting amount less ineffectiveness recognized of less than $0.1 million,
        for
        the fair values of the rate locks.
 
 Certain
        volumes of our gas stored underground are available for sale and subject
        to
        commodity price risk. At March 31, 2007 and December 31, 2006, approximately
        $15.1 million and $14.0 million, of our gas stored underground, which we
        own and
        carry as current Gas stored underground, is exposed to commodity price risk.
        Our
        operating subsidiaries utilize derivatives to hedge certain exposures to
        market
        price fluctuations on the anticipated operational sales of gas and also for
        cash
        received for fuel reimbursement.
 
 As
        a
        result of the
        Texas
        Gas Western Kentucky storage expansion project, approximately 4.8 Bcf of
        gas
        stored underground with a book value of $11.3 million is available for sale.
        Approximately 3.0 Bcf of this gas is subject to forward sales agreements
        under
        which the ultimate sales price was determined in March 2007, based on the
        price
        of New York Mercantile Exchange (NYMEX) natural gas futures. Texas Gas entered
        into derivatives to hedge the price exposure related to the storage gas.
        The
        derivatives associated with the volumes subject to forward sales agreements
        were
        designated as cash flow hedges during February 2007. Prior to the designation,
        these derivatives were marked to fair value through earnings along with the
        related forward sales agreements, resulting in a loss of $0.1 million in
        the
        first quarter 2007. The derivatives related to the remaining 1.8 Bcf of storage
        gas were also marked to fair value through earnings resulting in a loss of
        $2.0
        million in the first quarter 2007.
 
 With
        the
        exception of the storage gas volumes referred to above, the derivatives related
        to the sale of natural gas and cash for fuel reimbursement generally qualify
        for
        cash flow hedge accounting under SFAS No. 133 and are designated as such.
        The
        related unrealized gains and losses resulting from changes in fair values
        of the
        derivatives contracts designated as cash flow hedges are deferred as a component
        of Accumulated other comprehensive income. The deferred gains and losses
        are
        recognized in the Condensed Consolidated Statements of Income when the hedged
        anticipated purchases or sales affect earnings.
 
 The
        changes in fair values of the derivatives designated as cash flow hedges
        are
        expected to, and do, have a high correlation to changes in value of the
        anticipated transactions. Each reporting period we measure the effectiveness
        of
        the cash flow hedge contracts. To the extent the changes in the fair values
        of
        the hedge contracts do not effectively offset the changes in the estimated
        cash
        flows of the anticipated transactions, the ineffective portion of the hedge
        contracts is currently recognized in earnings. If the anticipated transactions
        are deemed no longer probable to occur, hedge accounting would be terminated
        and
        changes in the fair values of the associated derivative financial instruments
        would be recognized currently in the Condensed Consolidated Statements of
        Income.
 
 We
        are exposed to credit risk relating to the risk of loss resulting from the
        nonperformance by a customer of its contractual obligations. Our exposure
        generally relates to receivables for services provided, as well as volumes
        owed
        by customers for imbalances or gas lent by us to them, generally under PAL
        and
        no-notice service (NNS). We maintain credit policies intended to minimize
        credit
        risk and actively monitor these policies.  Natural gas price volatility has
        increased dramatically in recent years, which has materially increased credit
        risk related to gas loaned to customers. As of March 31, 2007, the amount
        of gas
        loaned out by our subsidiaries was approximately 36.9 trillion British thermal
        units (TBtu) and, assuming an average market price during March 2007 of $7.07
        per million British thermal units (MMBtu), the market value of gas loaned
        out at
        March 31, 2007 would have been approximately $260.9 million. As of December
        31,
        2006, the amount of gas loaned out by our subsidiaries was approximately
        15.1
        TBtu and, assuming an average market price during December 2006 of $6.81
        per
        MMBtu, the market value of gas loaned out at December 31, 2006 would have
        been
        approximately $102.8 million. If any significant customer of ours should
        have
        credit or financial problems resulting in a delay or failure to repay the
        gas
        they owe to us, this could have a material adverse effect on our financial
        condition, results of operations and cash flows.
 
 As
        of
        March 31, 2007, our cash equivalents were invested primarily in money market
        investments. Due to the short-term nature and type of our investments, a
        hypothetical 10% increase in interest rates would not have a material effect
        on
        the fair market value of our portfolio. Since we have the ability to liquidate
        this portfolio, we do not expect our Condensed Consolidated Statements of
        Income
        or Cash Flows to be materially affected by the effect of a sudden change
        in
        market interest rates on our investment portfolio.
  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 officer and principal financial officer have conducted
        an
        evaluation of the disclosure controls and procedures as of the end of the
        period
        covered by this report. Based on this evaluation, the principal executive
        officer and principal financial officer have each concluded that the disclosure
        controls and procedures are effective for their intended purpose.
 
 There
        was
        no change in our internal control over financial reporting identified in
        connection with the foregoing evaluation that occurred during the first quarter
        2007 that has materially affected, or is reasonably likely to materially
        affect,
        our internal control over financial reporting.
 
 
 
 
 
  25
  **PART
        II** **- OTHER INFORMATION**
 
 
 **Item
        1****.****Legal Proceedings******
  For
        a
        discussion of certain of our current legal proceedings, please read Note
        5 of
        the Notes to condensed consolidated financial statements in Item 1 of this
        Report.
 
 
 **Item
        2.  Unregistered Sales of Equity Securities and Use of
        Proceeds**
  On
        March
        5, 2007, our general partner purchased 1,500 of our common units in the open
        market at a price of $36.67 per unit.  These units were granted to our
        independent directors on March 5, 2007 as part of their director
        compensation.
  26
  **Item
        6. Exhibits**
  
 Exhibit
                  Designation
              
              Nature
                  of Exhibit31.1*
              
              Certification
                  of Rolf A. Gafvert, Chief Executive Officer, pursuant to Section
                  302 of
                  the Sarbanes-Oxley Act of 2002.31.2*
              
              Certification
                  of Jamie L. Buskill, Chief Financial Officer, pursuant to Section
                  302 of
                  the Sarbanes-Oxley Act of 2002.32.1*
              
              Certification
                  of Rolf A. Gafvert, Chief Executive Officer, pursuant to Section
                  906 of
                  the Sarbanes-Oxley Act of 2002.32.2*
              
              Certification
                  of Jamie L. Buskill, Chief Financial Officer, pursuant to Section
                  906 of
                  the Sarbanes-Oxley Act of 2002.
 
 
 *
        Filed
        herewith
  27
  ******SIGNATURE****S**
 
 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:
                  April 30, 2007
              
              
              By:
              */s/
                  Jamie L. Buskill*Jamie
                  L. BuskillChief
                  Financial Officer
 
 28