**UNITED
        STATES SECURITIES AND EXCHANGE COMMISSION**
 **WASHINGTON,
        D.C.  20549**
 
 **FORM
        10-Q**
 
 (Mark
        One)
 **xQUARTERLY
        REPORT PURSUANT TO SECTION 13
        OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**
 
 **For
        the quarterly period ended June 30, 2007**
 
 OR
 
 **oTRANSITION
        REPORT PURSUANT TO SECTION
        13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**
 ****
 **For
        the transition period from _______________ to
        _______________**
 
 *Commission
                  file number:*      01-32665**BOARDWALK
                  PIPELINE PARTNERS, LP***(Exact
                  name of registrant as specified in its charter)***DELAWARE***(State
                  or other jurisdiction of incorporation or
                  organization)***20-3265614***(I.R.S.
                  Employer Identification No.)***3800
                  Frederica Street, Owensboro, Kentucky 42301**
                **(270)
                  926-8686***(Address
                  and Telephone Number of Registrant’s Principal Executive
                  Office)*
 
 
 Indicate
        by check mark whether the registrant (1) has filed all reports required to
        be
        filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
        the
        preceding 12 months (or for such shorter period that the registrant was required
        to file such reports), and (2) has been subject to such filing requirements
        for
        the past 90
        days.        Yes  x    Noo
 
 
 Indicate
        by check mark whether the registrant is a large accelerated filer, an
        accelerated filer, or a non-accelerated filer.
 See
        definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of
        the Exchange Act. (check one:)
 
 Large
        accelerated filer  x                                                                Accelerated
        filer  o                                                      Non-accelerated
        filer  o
 
 Indicate
        by check mark whether the registrant is a shell company (as defined in Rule
        12b-2 of the Exchange Act).  Yes  ̈  No x
 
 As
        of
        July 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**
 
 **JUNE
        30, 2007**
 
 **BOARDWALK
        PIPELINE PARTNERS, LP**
 
 
 **PART
        I - FINANCIAL INFORMATION**
  **Item
        1.  Financial Statements ......................................................................................................................................................................................................................................................................3**
  **Condensed
        Consolidated Balance
        Sheets...............................................................................................................................................................................................................................................3**
  **Condensed
        Consolidated Statements of
        Income....................................................................................................................................................................................................................................5**
  **Condensed
        Consolidated Statements of Cash
        Flows.............................................................................................................................................................................................................................6**
  **Condensed
        Consolidated Statements of Changes in Partners’
Capital.............................................................................................................................................................................................7**
  **Condensed
        Consolidated Statements of Comprehensive
        Income........................................................................................................................................................................................................8**
  **Notes
        to Condensed Consolidated Financial
        Statements..........................................................................................................................................................................................................................9**
  **Item
        2.   Management's Discussion and Analysis
        of Financial Condition and Results of
        Operations...........................................................................................................................................19**
  **Item
        3.  Quantitative and Qualitative Disclosures
        About Market
        Risk.............................................................................................................................................................................................. 26**
  **Item
        4.  Controls and
        Procedures................................................................................................................................................................................................................................................................28**
 
  **PART
        II - OTHER INFORMATION**
  **Item
        1.Legal
        Proceedings............................................................................................................................................................................................................................................................................29**
  **Item
        1 A.  Risk
        Factors..................................................................................................................................................................................................................................................................................29**
  **Item
        2.  Unregistered Sales of Equity Securities
        and Use of
        Proceeds.................................................................................................................................................................................................30**
  **Item
        6.  Exhibits...............................................................................................................................................................................................................................................................................................31**
  **Signatures........................................................................................................................................................................................................................................................................................................32**
 
 
  2
  **PART
        I – FINANCIAL INFORMATION**
 
 **Item
        1.  Financial Statements**
 
 
 **BOARDWALK
        PIPELINE PARTNERS, LP**
 
 **CONDENSED
        CONSOLIDATED BALANCE SHEETS**
 **(Thousands
        of Dollars)**
 **(Unaudited)**
 
 
 **ASSETS**
              
              **June
                  30, 2007**
              
              
              **December
                  31, 2006**Current
                  Assets:Cash
                  and cash equivalents
              
              $
              387,746
              
              
              $
              399,032Receivables:Trade,
                  net
              
              
              41,581
              
              
              
              54,082Other
              
              
              6,405
              
              
              
              12,759Gas
                  Receivables:Transportation
                  and exchange
              
              
              11,185
              
              
              
              9,115Storage
              
              
              16
              
              
              
              11,704Inventories
              
              
              14,062
              
              
              
              14,110Costs
                  recoverable from customers
              
              
              7,381
              
              
              
              11,236Gas
                  stored underground
              
              
              12,108
              
              
              
              14,001Prepaid
                  expenses and other current assets
              
              
              18,320
              
              
              
              22,117Total
                  current assets
              
              
              498,804
              
              
              
              548,156Property,
                  Plant and Equipment:Natural
                  gas transmission plant
              
              
              2,359,683
              
              
              
              1,997,922Other
                  natural gas plant
              
              
              229,146
              
              
              
              213,9262,588,829
              
              
              
              2,211,848Less—Accumulated
                  depreciation and amortization
              
              
              225,033
              
              
              
              187,412Property,
                  plant and equipment, net
              
              
              2,363,796
              
              
              
              2,024,436Other
                  Assets:Goodwill
              
              
              163,474
              
              
              
              163,474Gas
                  stored underground
              
              
              174,570
              
              
              
              161,537Costs
                  recoverable from customers
              
              
              16,428
              
              
              
              19,767Other
              
              
              29,818
              
              
              
              33,929Total
                  other assets
              
              
              384,290
              
              
              
              378,707Total
                  Assets
              
              $
              3,246,890
              
              
              $
              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**
              
              **June
                  30, 2007**
              
              
              **December
                  31, 2006**Current
                  Liabilities:Payables:Trade
              
              $
              54,549
              
              
              $
              56,604Affiliates
              
              
              813
              
              
              
              3,014Other
              
              
              14,333
              
              
              
              14,459Gas
                  Payables:Transportation
                  and exchange
              
              
              19,508
              
              
              
              15,485Storage
              
              
              40,047
              
              
              
              42,127Other
                  accrued taxes
              
              
              27,977
              
              
              
              16,082Accrued
                  interest
              
              
              19,621
              
              
              
              19,376Accrued
                  payroll and employee benefits
              
              
              16,141
              
              
              
              18,198Deferred
                  income
              
              
              5,193
              
              
              
              22,147Other
                  current liabilities
              
              
              17,483
              
              
              
              20,926Total
                  current liabilities
              
              
              215,665
              
              
              
              228,418Long
                  –Term Debt
              
              
              1,351,384
              
              
              
              1,350,920Other
                  Liabilities and Deferred Credits:Pension
                  and postretirement benefits
              
              
              17,271
              
              
              
              15,761Asset
                  retirement obligation
              
              
              14,668
              
              
              
              14,307Provision
                  for other asset retirement
              
              
              40,924
              
              
              
              39,644Other
              
              
              26,245
              
              
              
              29,742Total
                  other liabilities and deferred credits
              
              
              99,108
              
              
              
              99,454Commitments
                  and ContingenciesPartners’
                  Capital:Common
                  units - 83,156,122 units and 75,156,122 units issued and outstanding
                  as of
                  June 30, 2007 and December 31, 2006
              
              
              1,241,806
              
              
              
              941,792Subordinated
                  units - 33,093,878 units issued and outstanding as of June 30,
                  2007 and
                  December 31, 2006
              
              
              291,148
              
              
              
              285,543General
                  partner
              
              
              28,381
              
              
              
              22,060Accumulated
                  other comprehensive income
              
              
              19,398
              
              
              
              23,112Total
                  partners’ capital
              
              
              1,580,733
              
              
              
              1,272,507Total
                  Liabilities and Partners’ Capital
              
              $
              3,246,890
              
              
              $
              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**
                **June
                  30,**
              
              
              **For
                  the**
                **Six
                  Months Ended**
                **June
                  30,****2007**
              
              
              **2006**
              
              
              **2007**
              
              
              **2006**Operating
                  Revenues:Gas
                  transportation
              
              $
              115,008
              
              
              $
              105,390
              
              
              $
              267,922
              
              
              $
              256,402Parking
                  and lending
              
              
              12,796
              
              
              
              9,414
              
              
              
              31,178
              
              
              
              22,931Gas
                  storage
              
              
              10,489
              
              
              
              7,196
              
              
              
              18,199
              
              
              
              16,814Other
              
              
              12,249
              
              
              
              6,662
              
              
              
              21,355
              
              
              
              6,961Total
                  operating revenues
              
              
              150,542
              
              
              
              128,662
              
              
              
              338,654
              
              
              
              303,108Operating
                  Costs and Expenses:Operation
                  and maintenance
              
              
              42,995
              
              
              
              36,833
              
              
              
              82,454
              
              
              
              75,160Administrative
                  and general
              
              
              22,116
              
              
              
              22,844
              
              
              
              47,909
              
              
              
              50,232Depreciation
                  and amortization
              
              
              20,219
              
              
              
              18,727
              
              
              
              40,134
              
              
              
              37,410Taxes
                  other than income taxes
              
              
              7,209
              
              
              
              6,785
              
              
              
              15,169
              
              
              
              12,014Asset
                  impairment
              
              
              14,698
              
              
              
              -
              
              
              
              14,698
              
              
              
              -Net
                  (gain) loss on disposal of operating assets and related
                  contracts
              
              
              (1,001
              )
              
              
              (2,391
              )
              
              
              1,638
              
              
              
              (2,205
              )Total
                  operating costs and expenses
              
              
              106,236
              
              
              
              82,798
              
              
              
              202,002
              
              
              
              172,611Operating
                  income
              
              
              44,306
              
              
              
              45,864
              
              
              
              136,652
              
              
              
              130,497Other
                  Deductions (Income):Interest
                  expense
              
              
              14,548
              
              
              
              15,215
              
              
              
              31,345
              
              
              
              30,847Interest
                  income
              
              
              (5,968
              )
              
              
              (698
              )
              
              
              (10,542
              )
              
              
              (1,242
              )Interest
                  income from affiliates, net
              
              
              (13
              )
              
              
              (7
              )
              
              
              (20
              )
              
              
              (7
              )Miscellaneous
                  other deductions (income), net
              
              
              159
              
              
              
              (792
              )
              
              
              (175
              )
              
              
              (977
              )Total
                  other deductions
              
              
              8,726
              
              
              
              13,718
              
              
              
              20,608
              
              
              
              28,621Income
                  before income taxes
              
              
              35,580
              
              
              
              32,146
              
              
              
              116,044
              
              
              
              101,876Income
                  taxes
              
              
              132
              
              
              
              246
              
              
              
              362
              
              
              
              246Net
                  income
              
              $
              35,448
              
              
              $
              31,900
              
              
              $
              115,682
              
              
              $
              101,630
 
 
 **Calculation
                  of limited partners’ interest in Net income:**Net
                  income
              
              $
              35,448
              
              
              $
              31,900
              
              
              $
              115,682
              
              
              $
              101,630Less
                  general partner’s interest in Net income
              
              
              1,199
              
              
              
              638
              
              
              
              3,010
              
              
              
              2,033Limited
                  partners’ interest in Net income
              
              $
              34,249
              
              
              $
              31,262
              
              
              $
              112,672
              
              
              $
              99,597Basic
                  and diluted net income per limited partner unit:Common
                  units
              
              $
              0.35
              
              
              $
              0.35
              
              
              $
              0.97
              
              
              $
              0.95Subordinated
                  units
              
              $
              0.17
              
              
              $
              0.22
              
              
              $
              0.97
              
              
              $
              0.95Cash
                  distribution to common and subordinated unitholders
              
              $
              0.43
              
              
              $
              0.36
              
              
              $
              0.845
              
              
              $
              0.54Weighted-average
                  number of limited partner units outstanding:Common
                  units
              
              
              83,156,122
              
              
              
              68,256,122
              
              
              
              79,576,012
              
              
              
              68,256,122Subordinated
                  units
              
              
              33,093,878
              
              
              
              33,093,878
              
              
              
              33,093,878
              
              
              
              33,093,878
 
 
 The
        accompanying notes are an integral part of these condensed consolidated
        financial statements.
  5
  **BOARDWALK
        PIPELINE PARTNERS, LP**
 
 **CONDENSED
        CONSOLIDATED STATEMENTS OF CASH FLOWS**
 **(Thousands
        of Dollars)**
 **(Unaudited)**
 
 **For
                  the**
                **Six
                  Months Ended**
                **June
                  30,****2007**
              
              
              **2006**OPERATING
                  ACTIVITIES:Net
                  income
              
              $
              115,682
              
              
              $
              101,630Adjustments
                  to reconcile to cash providedby
                  operations:Depreciation
                  and amortization
              
              
              40,134
              
              
              
              37,410Amortization
                  of deferred costs
              
              
              3,803
              
              
              
              1,106Amortization
                  of acquired executory contracts
              
              
              (889
              )
              
              
              (2,561
              )Asset
                  impairment
              
              
              14,698
              
              
              
              -Loss
                  (gain) on disposal of operating assets
              
              
              1,638
              
              
              
              (2,205
              )Changes
                  in operating assets and liabilities:Trade
                  and other receivables
              
              
              17,129
              
              
              
              12,791Gas
                  receivables and storage assets
              
              
              (1,887
              )
              
              
              22,178Costs
                  recoverable from customers
              
              
              4,281
              
              
              
              4,065Other
                  assets
              
              
              (6,129
              )
              
              
              (10,232
              )Trade
                  and other payables
              
              
              (11,632
              )
              
              
              7,643Gas
                  payables
              
              
              (5,350
              )
              
              
              (44,050
              )Accrued
                  liabilities
              
              
              10,084
              
              
              
              (8,262
              )Other
                  liabilities
              
              
              (9,896
              )
              
              
              17,028Net
                  cash provided by operating activities
              
              
              171,666
              
              
              
              136,541INVESTING
                  ACTIVITIES:Capital
                  expenditures
              
              
              (380,062
              )
              
              
              (55,200
              )Proceeds
                  from sale of operating assets
              
              
              328
              
              
              
              4,178Proceeds
                  from insurance reimbursements and other recoveries
              
              
              1,726
              
              
              
              4,960Advances
                  to affiliates, net
              
              
              (1,202
              )
              
              
              (623
              )Net
                  cash used in investing activities
              
              
              (379,210
              )
              
              
              (46,685
              )FINANCING
                  ACTIVITIES:Payments
                  of notes payable
              
              
              -
              
              
              
              (42,100
              )Distributions
              
              
              (97,559
              )
              
              
              (55,722
              )Proceeds
                  from sale of common units,
                net
                  of related transaction costs
              
              
              287,858
              
              
              
              13Capital
                  contribution from general partner
              
              
              5,959
              
              
              
              -Net
                  cash provided by (used in) financing activities
              
              
              196,258
              
              
              
              (97,809
              )Increase
                  (decrease) in cash and cash equivalents
              
              
              (11,286
              )
              
              
              (7,953
              )Cash
                  and cash equivalents at beginning of period
              
              
              399,032
              
              
              
              65,792Cash
                  and cash equivalents at end of period
              
              $
              387,746
              
              
              $
              57,839
 
 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
              
              
              67,075
              
              
              
              32,522
              
              
              
              2,033
              
              
              
              -
              
              
              
              101,630Distributions
                  paid
              
              
              (36,776
              )
              
              
              (17,831
              )
              
              
              (1,115
              )
              
              
              -
              
              
              
              (55,722
              )Other
                  comprehensive income
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              4,814
              
              
              
              4,814Transaction
                  costs related to sale of common units
              
              
              13
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              13**Balance,
                  June 30, 2006**
              
              $
              735,921
              
              
              $
              281,269
              
              
              $
              17,579
              
              
              $
              4,640
              
              
              $
              1,039,409
 
 
 
 
 **Balance,
                  January 1, 2007**
              
              $
              941,792
              
              
              $
              285,543
              
              
              $
              22,060
              
              
              $
              23,112
              
              
              $
              1,272,507Add
                  (deduct):Net
                  income
              
              
              79,103
              
              
              
              33,569
              
              
              
              3,010
              
              
              
              -
              
              
              
              115,682Distributions
                  paid
              
              
              (66,947
              )
              
              
              (27,964
              )
              
              
              (2,648
              )
              
              
              -
              
              
              
              (97,559
              )Other
                  comprehensive income
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (3,714
              )
              
              
              (3,714
              )Sale
                  of common units, net of related transaction costs (8,000,000
                  units)
              
              
              287,858
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              287,858Capital
                  contribution from general partner
              
              
              -
              
              
              
              -
              
              
              
              5,959
              
              
              
              -
              
              
              
              5,959**Balance,
                  June 30, 2007**
              
              $
              1,241,806
              
              
              $
              291,148
              
              
              $
              28,381
              
              
              $
              19,398
              
              
              $
              1,580,733
 
 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**
                **June
                  30,**
              
              
              **For
                  the**
                **Six
                  Months Ended**
                **June
                  30,****2007**
              
              
              **2006**
              
              
              **2007**
              
              
              **2006**Net
                  income
              
              $
              35,448
              
              
              $
              31,900
              
              
              $
              115,682
              
              
              $
              101,630Other
                  comprehensive income:Gain
                  (Loss) on cash flow hedges
              
              
              8,433
              
              
              
              3,390
              
              
              
              896
              
              
              
              10,408Reclassification
                  adjustment transferred to Net income
              
              
              (3,061
              )
              
              
              (2,802
              )
              
              
              (4,610
              )
              
              
              (5,594
              )Total
                  comprehensive income
              
              $
              40,820
              
              
              $
              32,488
              
              
              $
              111,968
              
              
              $
              106,444
 
 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,
        the accompanying condensed consolidated financial statements reflect all
        adjustments (consisting of only normal recurring accruals) necessary to present
        fairly the financial position as of June 30, 2007 and December 31, 2006,
        and the
        results of operations for the three and six months ended June 30, 2007 and
        2006 and changes in cash flow for the six months ended June 30, 2007 and
        2006.  Reference is made to the Notes to Consolidated Financial
        Statements in the 2006 Annual Report on Form 10-K, which should be read in
        conjunction with these unaudited condensed consolidated financial statements.
        The accounting policies described in Note 2 to the Consolidated Financial
        Statements included in such Annual Report on Form 10-K are the same used
        in
        preparing the accompanying unaudited condensed consolidated financial
        statements.
 
 Net
        income for interim periods may not necessarily be indicative of results for
        the
        calendar year. All 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 $41.4 million and $45.7 million at June 30, 2007 and December 31, 2006.
        Due
        to the method of storage accounting elected by Gulf South, the Partnership
        does
        not reflect volumes held by Gulf South on behalf of others on its Condensed
        Consolidated Balance Sheets. As of June 30, 2007 and December 31, 2006, Gulf
        South held 49.1 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 June
        30, 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 effective component of related unrealized gains and
        losses resulting from changes in fair values of the derivatives contracts
        designated as cash flow hedges are deferred as a component of Accumulated
        other
        comprehensive income.  The deferred gains and losses are recognized in
        the Condensed Consolidated Statements of Income when the hedged anticipated
        transactions affect earnings.
 
 Certain
        volumes of gas stored underground are available for sale and subject to
        commodity price risk. At June 30, 2007 and December 31, 2006, approximately
        $12.1 million and $14.0 million of gas stored underground at the Gulf South
        facilities, which the Partnership owns and carries as current Gas stored
        underground, is exposed to commodity price risk. The Partnership utilizes
        derivatives to hedge certain exposures to market price fluctuations on the
        anticipated operational sales of gas.
 
 9
 As
        a
        result of the approval of Phase II of the Western Kentucky storage expansion
        project, approximately 4.8 billion cubic feet (Bcf) of gas stored underground
        with a book value of $11.3 million 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.  The Partnership
        entered into derivatives to hedge the price exposure related to the storage
        gas.  The derivatives associated with the volumes subject to forward
        sales agreements were designated as cash flow hedges during February 2007,
        concurrent with the designation of the forward sales agreements as normal
        sales.  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 for 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 gain of $1.4 million and a loss
        of
        $0.6 million for the three and six months ended June 30, 2007.
 
 In
        the
        second quarter 2007, the Partnership entered into natural gas price swaps
        to
        hedge exposure to prices associated with the purchase of 2.1 Bcf of natural
        gas
        to be used for line pack for the Partnership’s Gulf Crossing expansion project
        and the Southeast expansion project.  The derivatives were not
        designated as hedges in accordance with SFAS No. 133 and were marked to fair
        value through earnings resulting in a loss of $0.7 million in the second
        quarter
        2007.
 
 With
        the
        exception of the storage gas volumes and line pack gas purchases referred
        to
        above, the derivatives related to the sale or purchase 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.  Any gains and losses on the derivatives related to
        the line pack gas purchases would be recognized in Miscellaneous other income,
        net.
 
 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 June 30, 2007, the Partnership
        reported a receivable of $1.6 million, and an increase 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 June 30, 2007 and December 31, 2006,
        were
        included in the following captions in the Condensed Consolidated Balance
        Sheets
        (in millions):
 
 **June
                  30, 2007**
              
              
              **December
                  31, 2006**Prepaid
                  expenses and other current assets
              
              $
              4.3
              
              
              $
              13.7Other
                  current liabilities
              
              
              0.4
              
              
              
              5.1Other
                  Liabilities and Deferred Credits - Other
              
              
              0.6
              
              
              
              -Accumulated
                  other comprehensive income
              
              
              4.6
              
              
              
              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 and six month periods ended June
        30,
        2007 was $0.1 million favorable and $0.4 million favorable. The Partnership
        did
        not record any ineffectiveness during the three and six month periods ending
        June 30, 2006. The Partnership did not have any cash flow hedges discontinued
        during the three and six months ended June 30, 2007 and 2006.
 
 
 **Note
        4:  Income Taxes**
 
 The
        Partnership is not a taxable entity
        for federal income tax purposes.  As such, it does not directly pay
        federal income tax.  The Partnership’s taxable income or loss, which
        may vary substantially from the net income or loss reported in the Condensed
        Consolidated Statements of Income, is includable in the federal income tax
        returns of each partner.  The aggregate difference in the basis of the
        Partnership’s net assets for financial and income tax purposes cannot be readily
        determined as 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 $4.7 million associated with insurance
        claims deemed probable of recovery.  In 2007, the Partnership received
        a final cash payment of $6.2 million related to damages incurred during
        Hurricane Katrina, $4.7 million of which was applied against the receivable
        and
        $1.5 million of which was recognized in Gas transportation
        revenue.  Through June 30, 2007, the Partnership has received
        approximately $12.2 million in insurance proceeds related to the hurricanes
        and
        continues to work with the insurance carriers and claims adjusters regarding
        recovery of its property damage losses associated with Hurricane
        Rita.  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.  During the second quarter 2006, as a result of a change in
        estimate primarily related to property retirements, the Partnership reduced
        the
        liability accrued for damage incurred during Hurricane Rita by $2.9
        million.  This decrease resulted in a reduction in overall expense
        related to the hurricanes of $0.8 million for the six months ended June 30,
        2006
        on its Condensed Consolidated Statements of Income. The remaining liability
        for
        the hurricanes was $0.8 million and $1.0 million as of June 30, 2007 and
        December 31, 2006.
 
 **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
        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 $7.6 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 June 30, 2007, Gulf South has received $0.8
        million of insurance reimbursements for legal expenses and root cause
        investigation.
 
 ***The
        NET Complaint***
 
 On
        June 2, 2007 a complaint was filed
        by National Energy & Trade, LP (NET) at the Federal Energy Regulatory
        Commission (FERC) against Texas Gas and Gulf South.  In its complaint
        NET alleges that Texas Gas failed to follow its tariff in awarding capacity,
        Texas Gas violated the Natural Gas Act in awarding transportation capacity
        to
        Gulf South, and Texas Gas and Gulf South engaged in market manipulation in
        violation of the Energy Policy Act of 2005.  Texas Gas and Gulf South
        have filed a response to this complaint categorically denying each of the
        allegations and intend to vigorously defend the Partnership against this
        complaint.  Since litigation is subject to many uncertainties it is
        possible that this action could be decided unfavorably.  The
        Partnership does not believe that this complaint will have a material effect
        on
        Partners’ Capital, cash flows or earnings.
 
 
 
 11
 
 ***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.*  On June 18, 2007 the FERC granted Gulf South the
        primary authority to construct, own and operate a pipeline expansion consisting
        of approximately 242 miles of 42-inch pipeline from DeSoto Parish in western
        Louisiana to near Harrisville, Mississippi and approximately 110,000 horsepower
        of new compression.  The expansion will add approximately 1.7 Bcf per
        day of new transmission capacity to the Gulf South pipeline
        system.  This project is supported by firm transportation agreements
        with customers who have contracted, on a long-term basis (with a weighted
        average term of approximately 7 years), for 1.4 Bcf per day of capacity from
        Carthage, Texas. Construction of this project has commenced and the Partnership
        expects this project to be in service during the fourth quarter
        2007.
 
 *Gulf
        Crossing Project.*The Partnership is pursuing construction of a new
        interstate pipeline that will begin near Sherman, Texas and proceed to the
        Perryville, Louisiana area.  The project will be owned by Gulf
        Crossing Pipeline Company LLC (Gulf Crossing), a subsidiary of the Partnership,
        and will consist of approximately 357 miles of 42-inch pipeline having capacity
        of up to approximately 1.7 Bcf per day.  Additionally, Gulf Crossing
        will enter into: (i) a lease for up to 1.4 Bcf per day of capacity on the
        Partnership’s Gulf South pipeline system (including capacity on the Southeast
        Expansion and capacity on a portion of the East Texas to Mississippi Expansion)
        to make deliveries to an interconnect with Transcontinental Pipe Line Company
        (Transco) in Choctaw County, Alabama (Transco 85); and (ii) a lease with
        a
        third-party intrastate pipeline which will bring certain gas supplies to
        the
        Partnership’s system.  This project is supported by firm
        transportation agreements with customers who have contracted, on a long-term
        basis (with a weighted average term of approximately 9.5 years), for 1.1
        Bcf per
        day of capacity and options with certain of these customers for an additional
        350 MMcf per day of firm transportation capacity.  The certificate
        application for this project was filed with the FERC on June 19, 2007 and
        the
        project is expected to be in service during the fourth quarter
        2008.  The Partnership continues to engage in negotiations concerning
        the possible sale 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 85, 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 2.2
        Bcf per day to accommodate volumes expected to come from the Gulf Crossing
        leased capacity discussed above.  In addition, Gulf South has executed
        a lease with Destin Pipeline Company to access markets in
        Florida.  This project is supported by firm
        transportation  agreements with customers who have contracted, on a
        long-term basis (with a weighted-average term of 8.7 years), for 660 MMcf
        per
        day of capacity as well as the capacity leased to Gulf Crossing discussed
        above.  The certificate application for this project was filed with
        the FERC in December 2006 and the project is expected 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
        and Greenville
        Laterals*.   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 existing interstate pipelines.  The
        Fayetteville Lateral, consisting of approximately 165 miles of 36-inch pipeline,
        has an initial design capacity of approximately 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
        Texas Gas’ mainline in Coahoma County, Mississippi. The Greenville Lateral,
        consisting of approximately 95 miles of pipeline with an initial design capacity
        of 750 MMcf 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.  The certificate application for this project was
        filed with the FERC on July 11, 2007.  The Partnership expects that
        the first 60 miles of the Fayetteville Lateral will be in service during
        the
        third quarter of 2008 and the remainder of the Fayetteville and Greenville
        Laterals to be in service during the first quarter 2009.
 
 12
 The
        total cost of the pipeline
        expansion projects discussed above, before taking into account any potential
        equity contribution by a third party in Gulf Crossing Pipeline, is estimated
        to
        be approximately $3.7 billion which is an increase from the $3.4 billion
        reported in the first quarter 2007.  This increase reflects the
        expanded pipeline capacity necessary to accommodate additional volumes from
        assumed capacity options that are considered probable of exercise, contractor
        penalties incurred as a result of delays in construction and higher labor
        and
        materials costs due to the large number of pipeline projects under way
        throughout the industry.  Actual costs may exceed the current estimate
        due to a variety of factors, including awaiting receipt of regulatory approvals,
        the timing of which the Partnership cannot control, weather-related costs
        and
        further delays in construction which could result in additional contractor
        and
        shipper penalties and stand-by costs.
 
 *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 certificate application for this project was filed with
        the FERC on June 25, 2007 seeking up to 8.3 Bcf of new storage capacity if
        Texas
        Gas is granted market-based rate authority for the new storage capacity being
        proposed.
 
 *Magnolia
        Storage Facility.* The
        Partnership has been in the process of developing a salt dome storage cavern
        near Napoleonville, Louisiana.  Operational tests which began in May
        2007 and were completed in July have indicated that due to anomalies that
        could
        not be corrected, the Partnership will be unable to place the cavern in service
        as expected.  As a result, the Partnership has elected to abandon that
        cavern and is exploring the possibility of securing a new site on which a
        new
        cavern could be developed.  In accordance with the requirements of
        Statement of Financial Accounting Standards No. 144, *Accounting for the
        Impairment or Disposal of Long-Lived Assets,* the carrying value of the
        cavern and related facilities of approximately $45.1 million was tested for
        recoverability.  In the second quarter 2007, the Partnership
        recognized an impairment charge to earnings of approximately $14.7 million,
        representing the carrying value of the cavern, the fair value of which was
        determined to be zero based on discounted expected future cash flows. The
        charge
        was presented as Asset impairment on the Condensed Consolidated Statements
        of
        Income.  The Partnership expects to use the other assets associated
        with the project, which include pipeline, compressors, base gas and other
        equipment and facilities, in conjunction with a replacement storage cavern
        to be
        developed. If it is determined in the future that the assets cannot be used
        in
        conjunction with a new cavern, the Partnership may be required to record
        an
        additional impairment charge at the time that determination is
        made.
 
 
 ***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 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 June 30, 2007, the
        Partnership has invested approximately $10.4 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
        June 30, 2007 and December 31, 2006, the Partnership had an accrued liability
        of
        approximately $17.9 million and $18.4 million related to assessment and/or
        remediation costs associated with the historical use of polychlorinated
        biphenyls, petroleum hydrocarbons and mercury, enhancement of groundwater
        protection measures and other costs.  The expenditures are expected to
        occur over approximately the next 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 June
        30, 2007 and December 31, 2006, approximately $3.5 million was recorded in
        Other
        current liabilities.  As of June 30, 2007 and December 31, 2006,
        approximately $14.4 million and $14.9 million was recorded in Other Liabilities
        and Deferred Credits.
 
 13
 On
        October 20, 2006, Texas Gas received notice from the Environmental Protection
        Agency (EPA) that Texas Gas is a potentially responsible party under the
        Comprehensive Environmental Response, Compensation, and Liability Act of
        1980
        with respect to the LWD, Inc. Superfund Site in Calvert City,
        Kentucky.  The Partnership is unable to estimate with any certainty at
        this time any potential liability it may incur related to this notice; however,
        the Partnership does not expect this to have a material effect on its financial
        condition.
  The
        Partnership’s pipelines are subject
        to the Clean Air Act (CAA) and the CAA Amendments of 1990 (Amendments) which
        added significant provisions to the CAA. The Amendments require the EPA to
        promulgate new regulations pertaining to mobile sources, air toxins, areas
        of
        ozone non-attainment and acid rain. The Partnership operates two facilities
        in
        areas affected by non-attainment requirements for the current ozone standard
        (eight-hour standard). As of June 30, 2007, the Partnership had incurred
        costs
        of approximately $15.6 million for emission control modifications of compression
        equipment located at facilities required to comply with current CAA provisions,
        the Amendments and state implementation plans for nitrogen oxide
        reductions.  These costs are being recorded as additions to property,
        plant and equipment (PPE) as the modifications are added.  If the EPA
        designates additional new non-attainment areas or promulgates new air
        regulations where the Partnership operates, the cost of additions to PPE
        is
        expected to increase, however the Partnership is unable at this time to estimate
        with any certainty the cost of any additions that may be required.
 
 The
        Partnership considers environmental
        assessment, remediation costs, and costs associated with compliance with
        environmental standards to be recoverable through base rates, as they are
        prudent costs incurred in the ordinary course of business and, therefore,
        no
        regulatory asset has been recorded to defer these costs.  The actual
        costs incurred will depend on the actual amount and extent of contamination
        discovered, the final cleanup standards mandated by the EPA or other
        governmental authorities and other factors.
 
 **E.  Commitments
        for Construction**
 
 The
        Partnership’s future capital
        commitments as of June 30, 2007, for contracts already authorized are expected
        to approximate the following amounts (in millions):
 
 Less
                  than 1 year
              
              $
              647.61-3
                  years
              
              
              99.04-5
                  years
              
              
              -More
                  than 5 years
              
              
              -Total
              
              $
              746.6
 
 The
        construction work in progress
        included in Property, plant and equipment, net in the Condensed Consolidated
        Balance Sheets was $544.2 million and $205.1 million as of June 30, 2007
        and
        December 31, 2006.
 
 
 **Note
        6:  Net Income per Limited Partner Unit and Cash
        Distributions**
 
 The
        Partnership calculates net income per limited partner unit in accordance
        with
        Emerging Issues Task Force Issue No. 03-6 (EITF No.
        03-6),*Participating Securities and the Two-Class Method under
        FASB Statement No. 128*.  In Issue 3 of EITF No. 03-6, the EITF
        reached a consensus that undistributed earnings for a period should be
        allocated to a participating security based on the contractual
        participation rights of the security to share in those earnings as if all
        of the
        earnings for the period had been distributed.  The Partnership's general
        partner holds contractual participation rights which are incentive distribution
        rights in accordance with the partnership agreement as follows:
 
 
 **Total
                  Quarterly Distribution**
              
              **Marginal Percentage Interest in**
                **Distributions****Target
                  Amount**
              **Common
                  and**
                **Subordinated**
                **Unitholders**
              
              **General Partner**Minimum
                  Quarterly Distribution
              
              $0.3500
              
              98%
              2%First
                  Target Distribution
              
              up to $0.4025
              
              98%
              2%Second
                  Target Distribution
              
              Above $0.4025 up to $0.4375
              
              85%
              15%Third
                  Target Distribution
              
              Above
                  $0.4375 up to $0.5250
              
              75%
              25%Thereafter
              
              above
                  $0.5250
              
              50%
              50%
 
 The amounts
        reported for net income per limited partner unit on the Condensed
        Consolidated Statements of Income for the three and six month periods ended
        June 30, 2007 and 2006, were adjusted to take into account an assumed
        allocation to the general partner's incentive distribution rights. Payments
        made
        on account of the incentive distribution rights are determined in relation
        to
        actual declared distributions and not based on the assumed allocation required
        by EITF No. 03-6. A reconciliation of the limited partners' interest in net
        income and net income available to limited partners used in computing net
        income
        per limited partner unit follows (in thousands, except weighted average units
        and per unit data):
 
 14
 
 **For
                  the**
                **Three
                  Months Ended**
                **June
                  30,**
              
              
              **For
                  the**
                **Six
                  Months Ended**
                **June
                  30,****2007**
              
              
              **2006**
              
              
              **2007**
              
              
              **2006**Limited
                  partners' interest in net income
              
              $
              34,249
              
              
              $
              31,262
              
              
              $
              112,672
              
              
              $
              99,597Less
                  assumed allocation to incentive distribution rights
              
              
              (491
              )
              
              
              -
              
              
              
              3,696
              
              
              
              3,503Net
                  income available to limited partners
              
              $
              34,740
              
              
              $
              31,262
              
              
              $
              108,976
              
              
              $
              96,094Less
                  assumed allocation to subordinated units
              
              
              5,635
              
              
              
              7,372
              
              
              
              32,009
              
              
              
              31,378Net
                  income available to common units
              
              $
              29,105
              
              
              $
              23,890
              
              
              $
              76,967
              
              
              $
              64,716Weighted
                  average common units
              
              
              83,156,122
              
              
              
              68,256,122
              
              
              
              79,576,012
              
              
              
              68,256,122Weighted
                  average subordinated units
              
              
              33,093,878
              
              
              
              33,093,878
              
              
              
              33,093,878
              
              
              
              33,093,878Net
                  income per limited partner unit - common units
              
              $
              0.35
              
              
              $
              0.35
              
              
              $
              0.97
              
              
              $
              0.95Net
                  income per limited partner unit – subordinated units
              
              $
              0.17
              
              
              $
              0.22
              
              
              $
              0.97
              
              
              $
              0.95
 
 
 
 **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 June 30, 2007
        and December 31, 2006, no funds were drawn under the
        facility.  Through June 30, 2007, the Partnership had 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 $293.8 million, net of underwriting discounts and
        offering expenses, and including approximately $6.0 million from the general
        partner to maintain its 2.0% general partner interest.  After the
        offering, the Partnership has 83.2 million common units issued and outstanding,
        of which 29.9 million are held by the public.  The balance of the
        common units and all of the subordinated units are held by BPHC.
 
 As
        of
        June 30, 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 June 30, 2007.
 
 During
        the three and six months ended June 30, 2007, the Partnership capitalized
        interest of $4.2 million and $6.3 million.  During the three and six months
        ended June 30, 2006, the Partnership capitalized interest of approximately
        $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 $0.7 million and
        $1.2
        million of AFUDC for the three and six months ended June 30,
        2007.  The Partnership capitalized $0.3 million and $0.6 million of
        AFUDC for the three and six months ended June 30, 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
        June
        30, 2007, the amount of gas loaned out by the Partnership’s subsidiaries was
        approximately 15.0 TBtu and, assuming an average market price during June
        2007
        of $7.33 per million British thermal units (MMBtu), the market value of gas
        loaned out at June 30, 2007 would have been approximately $110.0
        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.
 
 
 15
 
 
 **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.  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.  An
        additional settlement charge of $0.7 million was recorded in the second quarter
        2007, to recognize the effects of retirements associated with the ERIP that
        were
        initiated during the period.
 
 
 ***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 three and six months ended June 30, 2007 and 2006 were the
        following (in thousands):
 
 **Retirement
                  Plans**
              
              
              **PBOP****For
                  the**
                **Three
                  Months Ended**
                **June
                  30,**
              
              
              **For
                  the**
                **Three
                  Months Ended**
                **June
                  30,****2007**
              
              
              **2006**
              
              
              **2007**
              
              
              **2006**Service
                  cost
              
              $
              935
              
              
              $
              1,079
              
              
              $
              149
              
              
              $
              464Interest
                  cost
              
              
              1,542
              
              
              
              1,614
              
              
              
              737
              
              
              
              1,582Expected
                  return on plan assets
              
              
              (1,695
              )
              
              
              (1,775
              )
              
              
              (1,199
              )
              
              
              (1,157
              )Amortization
                  of prior service credit
              
              
              1
              
              
              
              -
              
              
              
              (1,940
              )
              
              
              (647
              )Amortization
                  of unrecognized net loss
              
              
              69
              
              
              
              100
              
              
              
              36
              
              
              
              330Settlement
                  charge (ERIP)
              
              
              700
              
              
              
              -
              
              
              
              -
              
              
              
              -Regulatory
                  asset decrease
              
              
              -
              
              
              
              -
              
              
              
              1,354
              
              
              
              1,353Net
                  periodic expense
              
              $
              1,552
              
              
              $
              1,018
              
              
              $
              (863
              )
              
              $
              1,925
 
 
 **Retirement
                  Plans**
              
              
              **PBOP****For
                  the**
                **Six
                  Months Ended**
                **June
                  30,**
              
              
              **For
                  the**
                **Six
                  Months Ended**
                **June
                  30,****2007**
              
              
              **2006**
              
              
              **2007**
              
              
              **2006**Service
                  cost
              
              $
              1,865
              
              
              $
              2,159
              
              
              $
              304
              
              
              $
              1,105Interest
                  cost
              
              
              3,225
              
              
              
              3,229
              
              
              
              1,637
              
              
              
              3,526Expected
                  return on plan assets
              
              
              (3,580
              )
              
              
              (3,550
              )
              
              
              (2,367
              )
              
              
              (2,326
              )Amortization
                  of prior service credit
              
              
              2
              
              
              
              1
              
              
              
              (3,880
              )
              
              
              (647
              )Amortization
                  of unrecognized net loss
              
              
              146
              
              
              
              200
              
              
              
              334
              
              
              
              770Settlement
                  charge (ERIP)
              
              
              3,800
              
              
              
              -
              
              
              
              -
              
              
              
              -Regulatory
                  asset decrease
              
              
              -
              
              
              
              250
              
              
              
              2,708
              
              
              
              4,619Net
                  periodic expense
              
              $
              5,458
              
              
              $
              2,289
              
              
              $
              (1,264
              )
              
              $
              7,047
 
 The
        decrease in the regulatory asset
        for PBOP is due primarily to the amortization of costs incurred in prior
        years.
 
 
 
 16
 
 ***Defined
        Contribution Plans***
 
 The
        Partnership maintains defined contribution plans covering substantially all
        of
        its employees.  Costs related to these plans were $1.3 million and
        $2.6 million for the three and six months ended June 30, 2007 and $1.3 million
        and $2.5 million for the three and six months ended June 30, 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 $2.4 million and $6.6 million for the three and six months ended
        June
        30, 2007 and $2.4 million and $6.5 million for the three and six months ended
        June 30, 2006 to the Partnership based on the actual time spent by Loews
        personnel performing these services, plus related expenses.
 
 Distributions
        paid on common and
        subordinated units held by BPHC and the 2.0% general partner interest and
        incentive distribution rights held by Boardwalk GP, LP were $75.6 and $47.6
        million during the six months ended June 30, 2007 and 2006.  In
        addition, as a result of the public offering of common units in March 2007,
        the
        general partner contributed approximately $6.0 million to maintain its general
        partner interest.
 
 
 **Note
        11: Distributions**
 
 The
        Partnership has declared quarterly
        distributions per unit to unitholders of record, including common and
        subordinated units and the 2.0% general partner interest held by its general
        partner as follows:
 
 **Record
                  Date**
              
              **Payable
                  Date**
              
              **Distribution
                  per Unit**August
                  6, 2007
              
              August
                  13, 2007
              
              0.44May
                  7, 2007
              
              May
                  14, 2007
              
              0.43February
                  20, 2007
              
              February
                  27, 2007
              
              0.415October
                  30, 2006
              
              November
                  6, 2006
              
              0.40August
                  11, 2006
              
              August
                  18, 2006
              
              0.38May
                  12, 2006
              
              May
                  19, 2006
              
              0.36February
                  16, 2006
              
              February
                  23, 2006
              
              0.179*
 
 *Distribution
                  represented a prorated portion of the $0.35 per unit “minimum quarterly
                  distribution” (as defined in the Partnership’s partnership agreement) for
                  the period November 15, 2005 through December 31,
                  2005.
 
 The
        Partnership also pays cash
        distributions to its general partner on account of its incentive distribution
        rights with respect to that portion of a quarterly distribution in excess
        of
        $0.4025 per unit.  These payments were $0.7 million for the six months
        ended June 30, 2007 and will be $0.7 million in the third quarter 2007 based
        on
        the declared distribution.
 
 
 **Note
        12:  Accumulated Other Comprehensive Income**
 
 The
        following table shows the
        components of Accumulated other comprehensive income at June 30, 2007 and
        December 31, 2006 (in thousands):
 
 **As
                  of**
                **June
                  30, 2007**
              
              
              **As
                  of**
                **December
                  31, 2006**Gain
                  on cash flow hedges
              
              $
              4,619
              
              
              $
              8,309Deferred
                  components of net periodic benefit cost
              
              
              14,779
              
              
              
              14,803Total
                  Accumulated other comprehensive income
              
              $
              19,398
              
              
              $
              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 June 30, 2007.
 
 
 17
 
 **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
        effective date for the Partnership is January 1, 2008.  The
        Partnership is currently evaluating the impact, if any, that SFAS No. 157
        would
        have on its financial condition, results of operations or cash
        flows.
 
 
 *SFAS
        No. 159*
 
 In
        February 2007, the FASB issued SFAS
        No. 159, *The Fair Value Option for Financial Assets and Financial
        Liabilities- including an amendment of SFAS No. 115.*SFAS No.
        159 allows companies to elect to measure financial assets and financial
        liabilities at fair value.  Unrealized gains and losses on items for
        which the fair value option has been chosen are reported in
        earnings.  SFAS No. 159 is effective for fiscal years beginning after
        November 15, 2007.  The effective date for the Partnership is January
        1, 2008.  The Partnership is currently evaluating the impact, if any,
        of adopting SFAS No. 159 on its financial condition, results of operations
        or
        cash flows.
  18
  
 **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 rate lower than the maximum
        tariff rates due to competition in the marketplace.Our
        Gulf
        South subsidiary is authorized to charge market-based rates for its firm
        and
        interruptible storage services.
 
 We
        are
        not in the business of buying and selling natural gas other than for system
        management and operational purposes, but changes in the price of natural
        gas can
        affect the overall supply and demand of natural gas which in turn does affect
        our results of operations.  We deliver gas to a broad mix of customers
        including local distribution companies, municipalities, interstate and
        intrastate pipelines, direct industrial users, electric power generation
        plants,
        marketers and producers.  In addition to serving directly connected
        markets, our pipeline systems have indirect market access to the northeastern
        and southeastern United States through interconnections with unaffiliated
        pipelines.
 
 Under
        firm transportation agreements, customers generally pay a fixed “demand” or
“capacity reservation” charge to reserve pipeline capacity at certain receipt
        and delivery points, plus a commodity and fuel charge paid on the volume
        of gas
        actually transported. Firm storage customers reserve a specific amount of
        storage capacity and injection and withdrawal capability and generally pay
        a
        capacity reservation charge based on the amount of capacity being reserved
        plus
        an injection and/or withdrawal fee. Capacity reservation revenues derived
        from a
        firm service contract (including no-notice storage service) are generally
        consistent during the contract term, but can be higher in winter peak periods,
        especially related to no-notice storage agreements, than in off-peak periods.
        The seasonal effect is also impacted by increased revenues generated from
        usage
        during the winter peak periods.
 
 Interruptible
        transportation and storage services are typically short-term in nature and
        are
        generally used by customers that do not require the certainty of delivery
        that
        is provided with firm services. Customers pay for interruptible services
        when
        the service is used.
 
 Revenues
        for our parking and lending (PAL) services and certain of our storage services
        for which we are authorized to charge market-based rates are affected by
        period-to-period natural gas price spreads (for example, summer to
        winter).  In recent periods, these price spreads have been wider and
        more volatile than in previous years, resulting in significant
        increases in parking and lending and storage revenues.  We are uncertain if
        these recent favorable trends in period-to-period natural gas price spreads
        will
        continue. A reversal of this trend could result in lower revenues and profits
        from these services in future periods.
 
 Operating
        expenses typically do not vary significantly based upon the amount of gas
        transported with the exception of gas consumed by Gulf South’s compressor
        stations. Gulf South’s fuel recoveries are included as part of transportation
        revenues.
 
 **Results
        of Operations for the Three Months Ended June 30, 2007 and
        2006**
 
 Our
        net
        income for the second quarter 2007 increased $3.5 million or 11.1% from the
        comparable 2006 period.  The primary drivers for the increase were higher
        revenues from strong demand for firm transportation services, pipeline
        system expansion and a continued strong environment for PAL and storage
        services resulting in higher reservation rates.  The increased revenues
        were partly offset by a $14.7 million impairment charge associated with a
        portion of our Magnolia storage project and slightly higher operating
        expenses.
 
 19
 Operating
        revenues for the second quarter 2007 increased $21.8 million, or 16.9%, to
        $150.5 million, compared to $128.7 million for the second quarter 2006 primarily
        due to:
 
 ·
              $7.9
                  million increase in transportation fees due to higher reservation
                  rates,
                  including $2.5 million from new contracts associated with the Carthage,
                  Texas to Keatchie, Louisiana pipeline expansion which was placed
                  in
                  service at the end of 2006;
 ·
              $7.9
                  million increase in fuel revenues from other system volumes and
                  higher
                  realized prices including hedging
                  activity;  and
 ·
              $6.7
                  million increase in PAL and storage revenues mainly due to gas
                  parked by
                  customers during summer and fall 2006 for withdrawal during
                  summer 2007.
 
 Operating
        expenses for the second quarter 2007 increased $23.4 million, or 28.3%, to
        $106.2 million, compared to $82.8 million for the second quarter 2006 primarily
        due to:
 
 ·
              $14.7
                  million loss due to impairment related to the Magnolia storage
                  facility in
                  the 2007 period;
 ·
              $4.1
                  million increase in fuel costs primarily due to an increase in
                  gas
                  usage;
 ·
              $2.9
                  million increase primarily due to a favorable hurricane accrual
                  adjustment
                  made in the 2006 period;
 ·
              $2.7
                  million increase in operation and maintenance expenses due to engine
                  overhauls, remediation and inline inspections at certain
                  locations;
 ·
              $1.7
                  million increase in employee compensation related to long-term
                  incentives;
                  and
 ·
              $1.5
                  million increase in depreciation and amortization resulting primarily
                  from
                  increased property, plant and
                  equipment.
 
 These
        increases were partly offset by:
 
 ·
              a
                  $2.8 million decline in post retirement benefits other than pensions
                  costs
                  primarily as a result of plan changes implemented in the second
                  half
                  2006.
 
 Total
        other deductions for the second quarter 2007 declined by $5.0 million, or
        36.5%,
        to $8.7 million, compared to $13.7 million for the second quarter 2006,
        primarily due to an increase in interest income of $5.3 million as a result
        of
        higher levels of invested cash.
 
 
 **Results
        of Operations for the Six Months Ended June 30, 2007 and
        2006**
 
 Our
        net
        income for the first six months of 2007 increased $14.1 million or 13.9%
        from
        the comparable 2006 period.  The primary drivers for the increase were
        higher revenues from increased utilization and strong demand for firm
        transportation services, pipeline system expansion and a continued strong
        environment for PAL and storage services resulting in higher reservation
        rates.  The higher revenues were partly offset by a $14.7 million
        impairment charge associated with a portion of our Magnolia storage project
        and
        slightly higher operating expenses.
 
 Operating
        revenues for the six months ended June 30, 2007 increased $35.6 million,
        or
        11.7%, to $338.7 million, compared to $303.1 million for the six months ended
        June 30, 2006 primarily due to:
 
 ·
              $13.9
                  million increase in fuel revenues due to an increase in other system
                  volumes and higher realized gas prices including hedging
                  activity;
 ·
              $13.8
                  million increase in transportation fees due to higher reservation
                  rates,
                  including $4.2 million from new contracts associated with the Carthage,
                  Texas to Keatchie, Louisiana pipeline expansion;
                  and
 ·
              $9.6
                  million increase in PAL and storage services mainly due to gas
                  parked by
                  customers during summer and fall 2006 for withdrawal during summer
                  2007.
 
 These
        increases were partly offset by:
 
 ·
              $1.6
                  million due to a decrease in the amortization of acquired executory
                  contracts.
 
 20
 Operating
        expenses for the six months ended June 30, 2007 increased $29.4 million,
        or
        17.0%, to $202.0 million, compared to $172.6 million for the six months ended
        June 30, 2006 primarily due to:
 
 ·
              $14.7
                  million loss due to impairment related to the Magnolia storage
                  facility
                  during 2007;
 ·
              $3.6
                  million increase in fuel costs primarily due to an increase in
                  gas
                  usage;
 ·
              $3.5
                  million increase primarily due to favorable items in the 2006 period
                  related to hurricane recoveries recognized and an adjustment related
                  to
                  the hurricane accrual;
 ·
              $3.2
                  million increase in property and other taxes primarily as a result
                  of a
                  reversal of a franchise tax accrual in the 2006
                  period;
 ·
              $3.0
                  million increase in operation and maintenance expenses due to engine
                  overhauls, remediation and inline inspections at certain
                  locations;
 ·
              $2.7
                  million increase in depreciation and amortization resulting from
                  increased
                  property, plant and equipment;
 ·
              $2.0
                  million increase in employee compensation related to long-term
                  incentives;
                  and
 ·
              $1.9
                  million loss on mark-to-market adjustments associated with hedges
                  on line
                  pack for pipeline expansion projects and storage gas
                  sales.
 
 These
        increases were partly offset by:
 
 ·
              $5.1
                  million net decrease in pension and postretirement benefits expenses,
                  mainly comprised of an $8.3 million reduction in postretirement
                  benefits
                  as a result of plan changes implemented in the second half 2006,
                  partly
                  offset by a $3.8 million pension settlement charge related to an
                  early
                  retirement incentive program
                  (ERIP).
 
 Total
        other deductions for the six months ended June 30, 2007 declined by $8.0
        million, or 28.0%, to $20.6 million, compared to $28.6 million for the six
        months ended June 30, 2006.  The decline is primarily due to an
        increase in interest income of $9.3 million as a result of higher levels
        of
        invested cash.
 
 
 **Capital
        Expenditures**
 
 Capital
        expenditures for the six months
        ended June 30, 2007 and 2006 were $380.1 million and $55.2
        million.  For the year ending December 31, 2007, we expect to make
        capital expenditures of approximately $1.5 billion, of which we expect
        approximately $1.47 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.
 
 We
        are currently engaged in the
        following expansion projects:
 
 ·
              *East
                  Texas to Mississippi Expansion.*  On June 18, 2007 the FERC
                  granted Gulf South the primary authority to construct, own and
                  operate a
                  pipeline expansion consisting of approximately 242 miles of 42-inch
                  pipeline from DeSoto Parish in western Louisiana to near Harrisville,
                  Mississippi and approximately 110,000 horsepower of new
                  compression.  The expansion will add approximately 1.7 Bcf per
                  day of new transmission capacity to the Gulf South pipeline
                  system.  This project is supported by firm transportation
                  agreements with customers who have contracted, on a long-term basis
                  (with
                  a weighted average term of approximately 7 years), for 1.4 Bcf
                  per day of
                  capacity from Carthage, Texas. Construction of this project has
                  commenced
                  and we expect this project to be in service during the fourth quarter
                  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 Gulf
                  Crossing Pipeline Company LLC (Gulf Crossing), a subsidiary of
                  ours, and
                  will consist of approximately 357 miles of 42-inch pipeline having
                  capacity of up to approximately 1.7 Bcf per day.  Additionally,
                  Gulf Crossing will enter into: (i) a lease for up to 1.4 Bcf per
                  day of
                  capacity on our Gulf South pipeline system (including capacity
                  on the
                  Southeast Expansion and capacity on a portion of the East Texas
                  to
                  Mississippi Expansion) to make deliveries to an interconnect with
                  Transcontinental Pipe Line Company (Transco) in Choctaw County,
                  Alabama
                  (Transco 85); and (ii) a lease with a third-party intrastate pipeline
                  which will bring certain gas supplies to our system.  This
                  project is supported by firm transportation agreements with customers
                  who
                  have contracted, on a long-term basis (with a weighted average
                  term of
                  approximately 9.5 years), for 1.1 Bcf per day of capacity and options
                  with
                  certain of these customers for an additional 350 MMcf per day of
                  firm
                  transportation capacity.  The certificate application for this
                  project was filed with the FERC on June 19, 2007 and the project
                  is
                  expected to be in service during the fourth quarter 2008.  We
                  continue to engage in negotiations concerning the possible sale
                  of up to a
                  49.0% equity interest in Gulf
                  Crossing.
 
 21
 ·
              *Southeast
                  Expansion*.  We are pursuing a pipeline expansion extending
                  our Gulf South pipeline system from near Harrisville, Mississippi
                  to an
                  interconnect with Transco 85, 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 2.2 Bcf
                  per day to
                  accommodate volumes expected to come from the Gulf Crossing leased
                  capacity discussed above.  In addition, Gulf South has executed
                  a lease with Destin Pipeline Company to access markets in
                  Florida.  This project is supported by firm
                  transportation  agreements with customers who have contracted,
                  on a long-term basis (with a weighted-average term of 8.7 years),
                  for 660
                  MMcf per day of capacity as well as the capacity leased to Gulf
                  Crossing
                  discussed above.  The certificate application for this project
                  was filed with the FERC in December 2006 and the project is expected
                  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
                  and Greenville Laterals*. 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 existing interstate pipelines.  The Fayetteville
                  Lateral, consisting of approximately 165 miles of 36-inch pipeline,
                  has an
                  initial design capacity of approximately 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 Texas
                  Gas’
                  mainline in Coahoma County, Mississippi. The Greenville Lateral,
                  consisting of approximately 95 miles of pipeline with an initial
                  design
                  capacity of 750 MMcf 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.  The certificate
                  application for this project was filed with the FERC on July 11,
                  2007.  We expect that the first 60 miles of the Fayetteville
                  Lateral will be in service during the third quarter of 2008 and
                  the
                  remainder of the Fayetteville and Greenville Laterals 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 a third party in Gulf Crossing Pipeline, is estimated
        to
        be approximately $3.7 billion which is an increase from the $3.4 billion
        reported in the first quarter 2007.  This increase reflects the
        expanded pipeline capacity necessary to accommodate additional volumes from
        assumed capacity options that are considered probable of exercise, contractor
        penalties incurred as a result of delays in construction and higher labor
        and
        materials costs due to the large number of pipeline projects under way
        throughout the industry.  Actual costs may exceed the current estimate
        due to a variety of factors, including awaiting receipt of regulatory approvals,
        the timing of which we cannot control, weather-related costs and further
        delays
        in construction which could result in additional contractor and shipper
        penalties and stand-by costs.
 
 ·
              *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 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 our storage facilities and has signed one precedent
                  agreement
                  for 2.0 Bcf of storage capacity.  The certificate application
                  for this project was filed with the FERC on June 25, 2007 seeking
                  up to
                  8.3 Bcf of new storage capacity if Texas Gas is granted market-based
                  rate
                  authority for the new storage capacity being
                  proposed.
 
 ·
              *Magnolia
                  Storage Facility.* We have been in the process of developing a salt
                  dome storage cavern near Napoleonville, Louisiana.  Operational
                  tests which began in May 2007 and were completed in July have indicated
                  that due to anomalies that could not be corrected, we will be unable
                  to
                  place the cavern in service as expected.  As a result, we have
                  elected to abandon that cavern and are exploring the possibility
                  of
                  securing a new site on which a new cavern could be
                  developed.  In accordance with the requirements of Statement of
                  Financial Accounting Standards No. 144, *Accounting for the Impairment
                  or Disposal of Long-Lived Assets,* the carrying value of the cavern
                  and related facilities of approximately $45.1 million was tested
                  for
                  recoverability.  In the second quarter 2007 we recognized an
                  impairment charge to earnings of approximately $14.7 million, representing
                  the carrying value of the cavern.  We expect to use the other
                  assets associated with the project, which include pipeline, compressors,
                  base gas and other equipment and facilities, in conjunction with
                  a
                  replacement storage cavern to be developed.  If it is determined
                  in the future that the assets cannot be used in conjunction with
                  a new
                  cavern, we may be required to record an additional impairment charge
                  at
                  the time that determination is
                  made.
 
 22
 
 **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 June 30, 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 $293.8 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 $35.2 million, or 25.8%, to $171.7
        million for the six months ended June 30, 2007, compared to $136.5 million
        for
        the comparable 2006 period, primarily due to:
 
 ·
              $35.8
                  million improvement in net income, excluding non-cash items such
                  as
                  depreciation and amortization and the Magnolia impairment charge
                  was
                  primarily driven by an increase in revenues partly offset by slightly
                  higher operating expenses; and
 ·
              $14.6
                  million increase in cash due to gas purchases made in 2006 to repay
                  gas
                  imbalances with shippers and other interstate
                  pipelines.
 
 These
        increases were partly offset by:
 
 ·
              $25.6
                  million reduction in cash due to recognition of deferred income
                  related to
                  PAL revenues.
 
 
 **Changes
        in cash flow from investing activities**
 
 Net
        cash
        used in investing activities increased $332.5 million to $379.2 million for
        the
        six months ended June 30, 2007, compared to $46.7 million for the comparable
        2006 period, primarily due to a $324.9 million increase in capital expenditures
        mainly for our expansion projects.
 
  **Changes
        in cash flow from financing activities**
 
 Net
        cash
        provided by (used in) financing activities increased $294.1 million to $196.3
        million for the six months ended June 30, 2007, compared to a use of $97.8
        million for the comparable 2006 period, primarily due to $293.8 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
              
              $
              746.6
              
              
              $
              647.6
              
              
              $
              99.0
              
              
              $
              -
              
              
              $
              -
 
 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.
 
 23
 
 **Off
        Balance Sheet Arrangements**
  At
        June 30, 2007, we had no guarantees
        of off balance sheet debt to third parties, no debt obligations that contain
        provisions requiring accelerated payment of the related obligations in the
        event
        of specified levels of declines in credit ratings, and no other off balance
        sheet arrangements.
 
 
 **Critical
        Accounting Policies and Estimates**
 
 Certain
        amounts included in or affecting our condensed consolidated financial statements
        and related disclosures must be estimated, requiring us to make certain
        assumptions with respect to values or conditions that cannot be known with
        certainty at the time the financial statements are prepared. These estimates
        and
        assumptions affect the amounts we report for assets and liabilities and our
        disclosure of contingent assets and liabilities at the date of our financial
        statements. We evaluate these estimates on an ongoing basis, utilizing
        historical experience, consultation with third parties and other methods
        we
        consider reasonable. Nevertheless, actual results may differ significantly
        from
        our estimates. Any effects on our business, financial position or results
        of
        operations resulting from revisions to these estimates are recorded in the
        period in which the facts that give rise to the revision become
        known.
 
 At
        June 30, 2007, the carrying value of
        our Magnolia storage expansion project was tested for impairment.  As
        a result of the impairment test, we recognized a $14.7 million impairment
        charge
        representing the carrying value of the cavern.  In determining that
        the fair value of the cavern was zero, estimates and assumptions were made
        regarding the cash flows associated with the cavern disposal through sale
        or
        abandonment.  Although we believe that alternative uses for the cavern
        may be possible in the hands of a third-party, and will pursue the sale of
        the
        cavern, we believe that the probability of a sale is unlikely.  In
        assessing the carrying value of the other associated facilities which include
        pipeline, compressors, base gas and other equipment and facilities, we assumed
        that the facilities would be used in conjunction with a replacement storage
        cavern to be developed.  Our expected cash flows related to the other
        facilities include the cost of developing a new cavern and revenues from
        the
        sale of storage services to third-parties over the useful life of the
        asset.  If storage spreads were to compress appreciably or significant
        difficulties were to arise in the development of the cavern, the actual cash
        flows could differ materially from the expected cash flows used in assessing
        the
        carrying value of the facilities.  If it is determined in the future
        that the assets cannot be used in conjunction with a new cavern, we may be
        required to record an additional impairment charge at the time that
        determination is made.
 
 During
        the six months ended June 30,
        2007, there were no significant changes to our critical accounting policies’
judgments or estimates disclosed in our Annual Report on Form 10-K for the
        year ended December 31, 2006.
 
 
 **Forward-Looking
        Statements**
 
 Investors
        are cautioned that certain
        statements contained in this report as well as some statements in periodic
        press
        releases and some oral statements made by our officials and our subsidiaries
        during presentations about us, are “forward-looking”
statements. Forward-looking statements include, without limitation, any
        statement that may project, indicate or imply future results, events,
        performance or achievements, and may contain the words “expect,” “intend,”
“plan,” “anticipate,” “estimate,” “believe,” “will likely result,” and similar
        expressions. In addition, any statement concerning future financial performance
        (including future revenues, earnings or growth rates), ongoing business
        strategies or prospects, and possible actions by our partnership or its
        subsidiaries, which may be provided by management, are also forward-looking
        statements.
 
 Forward-looking
        statements are based on
        current expectations and projections about future events and are inherently
        subject to a variety of risks and uncertainties, many of which are beyond
        our
        control that could cause actual results to differ materially from those
        anticipated or projected. These risks and uncertainties include, among
        others:
 
 24
 ·
              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, delayed approvals
                  by
                  regulatory bodies, land owner opposition, the lack of adequate
                  materials,
                  labor difficulties, difficulties we may encounter with partners
                  or
                  potential partners, expansion cost higher than anticipated and
                  numerous
                  other factors beyond our control.
 
 ·
              We
                  may not complete any future debt or equity financing transaction,
                  including any sale of an equity interest in Gulf Crossing
                  Pipeline.
 
 ·
              The
                  gas transmission and storage operations of our subsidiaries are
                  subject to
                  rate-making policies and actions by the FERC or customers that
                  could have
                  an adverse impact on the rates we charge and the revenues we collect
                  may
                  not cover our full cost of operating our pipelines and a reasonable
                  return.
 
 ·
              We
                  are subject to laws and regulations relating to the environment
                  and
                  pipeline operations which may expose us to significant costs, liabilities
                  and loss of revenues. Any changes in such regulations or their
                  application
                  could negatively affect our business, financial condition and results
                  of
                  operations.
 
 ·
              Our
                  operations are subject to operational hazards and unforeseen interruptions
                  for which we may not be adequately
                  insured.
 
 ·
              The
                  cost of insuring our assets may increase
                  dramatically.
 
 ·
              Because
                  of the natural decline in gas production from existing wells, our
                  success
                  depends on our ability to obtain access to new sources of natural
                  gas,
                  which is dependent on factors beyond our control. Any decrease
                  in supplies
                  of natural gas in our supply areas could adversely affect our business,
                  financial condition and results of
                  operations.
 
 ·
              Successful
                  development of LNG import terminals in the eastern or northeastern
                  United
                  States could reduce the demand for our
                  services.
 
 ·
              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.
 
  25
  
 **Item
        3.  Quantitative and Qualitative Disclosures About
        Market Risk**
 
 Our
        long-term debt is subject to
        interest rate risk. Total long-term debt at June 30, 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 June 30, 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 increase 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
        decrease 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 SFAS No. 133.  As of
        June 30, 2007, we reported a receivable of $1.6 million, and an increase 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.
 
 Certain
        volumes of our gas stored underground are available for sale and subject
        to
        commodity price risk. At June 30, 2007 and December 31, 2006, approximately
        $12.1 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 six
        months
        ended June 30, 2007.  The derivatives related to the remaining 1.8 Bcf
        of storage gas were also marked to fair value through earnings resulting
        in a
        gain of $1.4 million and a loss of $0.6 million in the three and six months
        ended June 30, 2007.
 
 In
        the
        second quarter 2007, we entered into natural gas price swaps to hedge exposure
        to prices associated with the purchase of 2.1 Bcf of natural gas to be used
        for
        line pack for our Gulf Crossing expansion project and the Southeast expansion
        project, approximately 1.6 Bcf of which remained outstanding at June 30,
        2007.  The derivatives were not designated as hedges in accordance
        with SFAS No. 133 and were marked to fair value through earnings resulting
        in a
        loss of $0.7 million in the second quarter 2007.  Changes in the fair value
        of the derivatives will be recognized in earnings each quarter until
        settlement.  The changes in the fair value of the gas purchased for
        line pack will not be recognized in earnings each quarter.  When the
        gas is purchased, the ultimate cost will be recorded to Property, Plant and
        Equipment along with the other capital components of the projects and recognized
        in earnings as the property is depreciated.  A $1.00 increase in the
        price of NYMEX natural gas futures, would result in the recognition of a
        $1.6
        million gain in earnings.  Conversely, a $1.00 decrease would result
        in the recognition of a $1.6 million loss.
 
 With
        the
        exception of the storage gas volumes and line pack gas purchases referred
        to
        above, the derivatives related to the sale or purchase 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.
 
 26
 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 June 30, 2007, the amount
        of gas
        loaned out by our subsidiaries was approximately 15.0 trillion British thermal
        units (TBtu) and, assuming an average market price during June 2007 of $7.33
        per
        million British thermal units (MMBtu), the market value of gas loaned out
        at
        June 30, 2007 would have been approximately $110.0 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 June 30, 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.
  27
  **Item
        4.  Controls and
        Procedures**
 
 We
        maintain a system of disclosure controls and procedures which are designed
        to
        ensure that information required to be disclosed in reports filed or submitted
        under the federal securities laws, including this report, is recorded,
        processed, summarized and reported on a timely basis.  These
        disclosure controls and procedures are designed to ensure that information
        required to be disclosed under the federal securities laws is accumulated
        and
        communicated to management on a timely basis to allow assessment of required
        disclosures.
 
 Our
        principal executive officer and
        principal financial officer have conducted an evaluation of the disclosure
        controls and procedures as of the end of the period covered by this
        report.  Based on this evaluation, the principal executive officer and
        principal financial officer have each concluded that the disclosure controls
        and
        procedures are effective.
 
 There
        was
        no change in our internal control over financial reporting identified in
        connection with the foregoing evaluation that occurred during the six months
        ended June 30, 2007, that has materially affected, or is reasonably likely
        to
        materially affect, our internal control over financial reporting.
 
 
 
 
 
 
 
  28
  **PART
        II – OTHER INFORMATION**
 
 
 **Item
        1.  Legal
        Proceedings**
  For
        a discussion of certain of our
        current legal proceedings, please read Note 5 of the Notes to condensed
        consolidated financial statements in Item 1 of this Report.
 
 
 **Item****1
        A.  Risk
        Factors**
 
 *The
        following discussion supplements
        the Risk Factors in Item 1A “Risk Factors” of our Annual Report on Form 10-K for
        the year ended December 31, 2006.*
 
 
 ***We
        have adopted certain valuation methodologies that may result in a shift of
        income, gain, loss and deduction between the general partner and the
        unitholders.  The IRS may challenge this treatment, which could
        adversely affect the value of the common units.***
  When
        we
        issue additional units or engage in certain other transactions, we determine
        the
        fair market value of our assets and allocate any unrealized gain or loss
        attributable to our assets to the capital accounts of our unitholders and
        our
        general partner.  Our methodology may be viewed as understating the
        value of our assets.  In that case, there may be a shift of income,
        gain, loss and deduction between certain unitholders and the general partner,
        which may be unfavorable to such unitholders.  Moreover, subsequent
        purchasers of common units may have a greater portion of their Internal Revenue
        Code Section 743(b) adjustment allocated to our tangible assets and a lesser
        portion allocated to our intangible assets.  The IRS may challenge our
        valuation methods, or our allocation of the Section 743(b) adjustment
        attributable to our tangible and intangible assets, and allocations of income,
        gain, loss and deduction between the general partner and certain of our
        unitholders.
 
 A
        successful IRS challenge to these methods or allocations could adversely
        affect
        the amount of taxable income or loss being allocated to our unitholders.
        It also
        could affect the amount of gain from our unitholders’ sale of common units and
        could have a negative impact on the value of the common units or result in
        audit
        adjustments to our unitholders’ tax returns without the benefit of additional
        deductions.
 
 
 ***Our
        natural gas transportation, gathering and storage operations are subject
        to FERC
        rate-making policies that could have an adverse impact on our ability to
        establish rates that would allow us to recover the full cost of operating
        our
        pipelines including a reasonable return and our ability to service our
        debt.***
  Action
        by
        the FERC on currently pending matters as well as matters arising in the future
        could adversely affect our ability to establish rates, or to charge rates
        that
        would cover future increases in our costs, or even to continue to collect
        rates
        that cover current costs, including a reasonable return.  We cannot
        make assurances that we will be able to recover all of our costs through
        existing or future rates. An adverse determination in any future rate proceeding
        brought by or against Texas Gas or Gulf South could have a material adverse
        effect on our business, financial condition and results of operations that
        could
        have an adverse impact on our ability to service our debt.
  On
          July 20, 2004, the United
          States Court of Appeals for the District of Columbia Circuit (D.C. Circuit)
          issued its opinion in *BP West Coast Products, LLC v. FERC (BP West
          Coast)* and vacated the portion of the FERC’s decision applying the FERC’s
*Lakehead* policy to determine an allowance for income taxes in the
          regulated cost of service. In its *Lakehead*decision, the FERC allowed
          an oil pipeline limited partnership to include in its cost of service an
          income
          tax allowance to the extent that its unitholders were corporations subject
          to
          income tax. The D.C. Circuit emphasized that a regulated pipeline’s cost of
          service should include only “appropriate cost[s]” and compared income taxes paid
          by owners of equity interests in a pipeline to the costs of bookkeeping
          paid by
          such owners, indicating the court’s belief that such costs paid by an entity
          other than the regulated entity would not be recoverable in the rates of
          the
          pipeline. In May and June 2005, the FERC issued a statement of general
          policy
          and an order on remand of *BP West Coast*, respectively, in which the
          FERC stated it will permit pipelines to include in cost-of-service a tax
          allowance to reflect actual or potential tax liability on their public
          utility
          income attributable to all partnership or limited liability company interests,
          if the ultimate owner of the interest has an actual or potential income
          tax
          liability on such income. Whether a pipeline’s owners have such actual or
          potential income tax liability will be reviewed by the FERC on a case-by-case
          basis. Although the new policy is generally favorable for pipelines that
          are
          organized as pass-through entities, it still entails risk due to the
          case-by-case review requirement. On December 16, 2005, the FERC issued
          a
          case-specific review of the income tax allowance issue in the *SFPP,
          L.P.* proceeding. The FERC ruled favorably to SFPP, L.P. on all income
          tax
          issues and set forth guidelines regarding the type of evidence necessary
          for the
          pipeline to determine its income tax allowance. The FERC’s *BP West
          Coast* remand decision, the new tax allowance policy, and the December 16,
          2005 order were appealed to the D.C. Circuit. The D.C. Circuit issued an
          order
          on May 29, 2007, in which it denied these appeals and fully upheld FERC’s
          new tax allowance policy and the application of that policy in the
          December 16, 2005 order. We have no way of knowing whether any party will
          seek rehearing or appeal of the D.C. Circuit’s decision. However, it is possible
          that a party could request rehearing of the decision and/or petition for
          writ of
          certiorari to the United States Supreme Court. As a result, the ultimate
          outcome
          of these proceedings is not certain and could result in changes to the
          FERC’s
          treatment of income tax allowances in cost of service. If the FERC were
          to
          change its tax allowance policies in the future, or if current policy was
          reversed or changed on appeal by a court, such changes could materially
          and
          adversely impact the rates we are permitted to charge as future rates are
          approved for our interstate transportation services.
 29
 
 If
        Texas Gas or Gulf South were to file
        a rate case or if we were to be required to defend our rates, we would be
        required to establish pursuant to the new policy statement that the inclusion
        of
        an income tax allowance in our cost of service was just and reasonable. To
        establish that our tax allowance is just and reasonable, the Partnership’s
        general partner may elect to require owners of the Partnership’s units to
        recertify their status as being subject to United States federal income taxation
        on the income generated by Texas Gas or Gulf South. We can provide no assurance
        that the certification and re-certification procedures provided in the
        Partnership’s partnership agreement will be sufficient to establish that its
        unitholders, or its unitholders’ owners, are subject to United States federal
        income taxation on the income generated by us. If we are unable to establish
        that the master partnership’s unitholders, or its unitholders’ owners, are
        subject to United States federal income taxation on the income generated
        by us,
        the FERC could disallow a substantial portion of Texas Gas’ or Gulf South’s
        income tax allowance. If the FERC were to disallow a substantial portion
        of
        Texas Gas’ or Gulf South’s income tax allowance, it is likely that the level of
        maximum lawful rates could decrease from current levels.
 
 
 **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.
  30
  
 **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
  31
  **SIGNATURES**
 
 Pursuant
        to the requirements of the
        Securities Exchange Act of 1934, the registrant has duly caused this report
        to
        be signed on its behalf by the undersigned thereunto duly
        authorized.
 
 **Boardwalk
                  Pipeline Partners, LP**By:
                  Boardwalk GP, LPits
                  general partnerBy:
                  Boardwalk GP, LLCits
                  general partnerDated:
                  July 31, 2007
              
              
              By:
              */s/
                  Jamie L. Buskill*Jamie
                  L. BuskillChief
                  Financial Officer
 
 
 
 
 
  32