UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
 WASHINGTON,
D.C.  20549
  FORM
10-Q
  (Mark
One)
 x  QUARTERLY REPORT PURSUANT TO SECTION 13
OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For
the quarterly period ended June 30, 2008
 
 OR
 
 o   TRANSITION REPORT PURSUANT TO SECTION
13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For
the transition period from _______________ to _______________
 
 Commission file
      number:      01-32665BOARDWALK
      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.)9
      Greenway Plaza, Suite 2800
                Houston,
      Texas  77046
                (866)
      913-2122(Address
      and Telephone Number of Registrant’s Principal Executive
      Office)Securities
      registered pursuant to Section 12(b) of the Act:Title
      of each class
              
              Name
      of each exchange on which registeredCommon
      Units Representing Limited Partner Interests
              
              New
      York Stock ExchangeSecurities registered pursuant
      to Section 12(g) of the Act:  NONE
 
 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, a non-accelerated filer or a smaller reporting
company.  See the definitions of “large accelerated filer,”
“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act. (Check one)
 Large
accelerated filer  x                                               Accelerated
filer  o                                           Non-accelerated
filer  o                                           Smaller
reporting company  o
 
 Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act).  Yes  ̈  No x
 
 As of
July 24, 2008, the registrant had 100,656,122 common units, 22,866,667 class B
units and 33,093,878 subordinated units outstanding.
 
 
 
 
 
 1
 
 
 
 
 
 
 TABLE
OF CONTENTS
 
 FORM
10-Q
 
 June
30, 2008
 
 BOARDWALK
PIPELINE PARTNERS, LP
 
 PART
I - FINANCIAL INFORMATION
 
 Item
      1.  Financial Statements
  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 ...............................................................................................................................22
  Item
3.  Quantitative and Qualitative Disclosures About Market
Risk ...................................................................................................................................................................................30
  Item
4.  Controls and
Procedures ...................................................................................................................................................................................................................................................32
  
  PART
II - OTHER INFORMATION
  
  Item
1.  Legal
Proceedings ..............................................................................................................................................................................................................................................................33
  Item
6.  Exhibits .................................................................................................................................................................................................................................................................................34
  Signatures ..........................................................................................................................................................................................................................................................................................35
  
   2
  PART
I – FINANCIAL INFORMATION
 
 Item
1.  Financial Statements
 
 BOARDWALK
PIPELINE PARTNERS, LP
 
 CONDENSED CONSOLIDATED BALANCE SHEETS
 (Millions)
 (Unaudited)
 
 June
      30,
              
              
              December
      31,ASSETS
              
              2008
              
              
              2007Current
      Assets:Cash
      and cash equivalents
              
              $
              482.6
              
              
              $
              317.3Receivables:Trade,
      net
              
              
              63.3
              
              
              
              60.7Other
              
              
              23.0
              
              
              
              12.7Gas
      Receivables:Transportation
      and exchange
              
              
              32.0
              
              
              
              12.5Storage
              
              
              0.3
              
              
              
              1.3Inventories
              
              
              18.1
              
              
              
              16.6Costs
      recoverable from customers
              
              
              6.6
              
              
              
              6.3Gas
      stored underground
              
              
              15.0
              
              
              
              16.3Prepaid
      expenses and other current assets
              
              
              33.0
              
              
              
              11.9Total
      current assets
              
              
              673.9
              
              
              
              455.6Property,
      Plant and Equipment:Natural
      gas transmission plant
              
              
              3,305.5
              
              
              
              2,392.5Other
      natural gas plant
              
              
              220.6
              
              
              
              224.03,526.1
              
              
              
              2,616.5Less—accumulated
      depreciation and amortization
              
              
              317.6
              
              
              
              262.53,208.5
              
              
              
              2,354.0Construction
      work in progress
              
              
              1,194.4
              
              
              
              951.4Property,
      plant and equipment, net
              
              
              4,402.9
              
              
              
              3,305.4Other
      Assets:Goodwill
              
              
              163.5
              
              
              
              163.5Gas
      stored underground
              
              
              171.8
              
              
              
              172.4Costs
      recoverable from customers
              
              
              15.7
              
              
              
              15.9Other
              
              
              52.8
              
              
              
              44.5Total
      other assets
              
              
              403.8
              
              
              
              396.3Total
      Assets
              
              $
              5,480.6
              
              
              $
              4,157.3
 
 
 The
accompanying notes are an integral part of these condensed consolidated
financial statements.
  3
  BOARDWALK
PIPELINE PARTNERS, LP
 
 CONDENSED
CONSOLIDATED BALANCE SHEETS
 (Millions)
 (Unaudited)
 
 June
      30,
              
              December
      31,LIABILITIES
      AND PARTNERS’ CAPITAL
              
              2008
              
              2007Current
      Liabilities:Payables:Trade
              
              $
              223.8
              
              
              $
              190.6Affiliates
              
              
              2.5
              
              
              
              1.3Other
              
              
              6.7
              
              
              
              5.1Gas
      Payables:Transportation
      and exchange
              
              
              12.8
              
              
              
              17.8Storage
              
              
              50.7
              
              
              
              35.3Accrued
      taxes, other
              
              
              52.9
              
              
              
              20.2Accrued
      interest
              
              
              34.6
              
              
              
              30.8Accrued
      payroll and employee benefits
              
              
              17.4
              
              
              
              22.3Construction
      retainage
              
              
              28.2
              
              
              
              32.2Deferred
      income
              
              
              2.0
              
              
              
              7.2Other
      current liabilities
              
              
              49.6
              
              
              
              26.5Total
      current liabilities
              
              
              481.2
              
              
              
              389.3Long
      –Term Debt
              
              
              2,096.4
              
              
              
              1,847.9Other
      Liabilities and Deferred Credits:Pension
      and postretirement benefits
              
              
              18.8
              
              
              
              17.2Asset
      retirement obligation
              
              
              16.5
              
              
              
              16.1Provision
      for other asset retirement
              
              
              43.6
              
              
              
              42.4Other
              
              
              74.1
              
              
              
              41.4Total
      other liabilities and deferred credits
              
              
              153.0
              
              
              
              117.1Commitments
      and ContingenciesPartners’
      Capital:Common
      units – 100.7 million units and 90.7 million units issued and outstanding
      as of  June 30, 2008 and December 31, 2007
              
              
              1,741.0
              
              
              
              1,473.9Class
      B units – 22.9 million units issued and outstanding as of June 30,
      2008
              
              
              686.0
              
              
              
              -Subordinated
      units – 33.1 million units issued and outstanding as of June 30, 2008 and
      December 31, 2007
              
              
              300.0
              
              
              
              291.7General
      partner
              
              
              53.0
              
              
              
              33.2Accumulated
      other comprehensive (loss) income
              
              
              (30.0
              )
              
              
              4.2Total
      partners’ capital
              
              
              2,750.0
              
              
              
              1,803.0Total
      Liabilities and Partners’ Capital
              
              $
              5,480.6
              
              
              $
              4,157.3
 
 
 The
accompanying notes are an integral part of these condensed consolidated
financial statements.
  4
  BOARDWALK
PIPELINE PARTNERS, LP
 
 CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 (Millions,
except per unit amounts)
 (Unaudited)
 For
      the
              
              
              For
      theThree
      Months Ended
              
              
              Six
      Months EndedJune
      30,
              
              
              June
      30,2008
              
              
              2007
              
              
              2008
              
              
              2007Operating
      Revenues:Gas
      transportation
              
              $
              160.2
              
              
              $
              115.0
              
              
              $
              336.7
              
              
              $
              267.9Parking
      and lending
              
              
              4.6
              
              
              
              12.8
              
              
              
              9.7
              
              
              
              31.2Gas
      storage
              
              
              13.6
              
              
              
              10.5
              
              
              
              24.3
              
              
              
              18.2Other
              
              
              11.9
              
              
              
              12.2
              
              
              
              16.9
              
              
              
              21.4Total
      operating revenues
              
              
              190.3
              
              
              
              150.5
              
              
              
              387.6
              
              
              
              338.7Operating
      Costs and Expenses:Operation
      and maintenance
              
              
              54.9
              
              
              
              43.0
              
              
              
              95.7
              
              
              
              82.5Administrative
      and general
              
              
              27.3
              
              
              
              22.1
              
              
              
              52.5
              
              
              
              47.9Depreciation
      and amortization
              
              
              30.4
              
              
              
              20.2
              
              
              
              57.8
              
              
              
              40.1Contract
      settlement gain
              
              
              -
              
              
              
              -
              
              
              
              (11.2
              )
              
              
              -Asset
      impairment
              
              
              -
              
              
              
              14.7
              
              
              
              1.4
              
              
              
              14.7Net
      (gain) loss on disposal of operating assets and related
      contracts
              
              
              (14.2
              )
              
              
              (1.0
              )
              
              
              (14.0
              )
              
              
              1.6Taxes
      other than income taxes
              
              
              10.9
              
              
              
              7.2
              
              
              
              22.9
              
              
              
              15.2Total
      operating costs and expenses
              
              
              109.3
              
              
              
              106.2
              
              
              
              205.1
              
              
              
              202.0Operating
      income
              
              
              81.0
              
              
              
              44.3
              
              
              
              182.5
              
              
              
              136.7Other
      Deductions (Income):Interest
      expense
              
              
              17.7
              
              
              
              14.5
              
              
              
              36.7
              
              
              
              31.3Interest
      income
              
              
              (0.4
              )
              
              
              (5.9
              )
              
              
              (1.4
              )
              
              
              (10.5
              )Miscellaneous
      other (income) deductions, net
              
              
              (1.2
              )
              
              
              0.1
              
              
              
              (6.1
              )
              
              
              (0.2
              )Total
      other deductions
              
              
              16.1
              
              
              
              8.7
              
              
              
              29.2
              
              
              
              20.6Income
      before income taxes
              
              
              64.9
              
              
              
              35.6
              
              
              
              153.3
              
              
              
              116.1Income
      taxes
              
              
              0.2
              
              
              
              0.2
              
              
              
              0.5
              
              
              
              0.4Net
      income
              
              $
              64.7
              
              
              $
              35.4
              
              
              $
              152.8
              
              
              $
              115.7
 
 Net
      income
              
              $
              64.7
              
              
              $
              35.4
              
              
              $
              152.8
              
              
              $
              115.7Less
      general partner’s interest in Net income
              
              
              2.9
              
              
              
              1.2
              
              
              
              6.2
              
              
              
              3.0Limited
      partners’ interest in Net income
              
              $
              61.8
              
              
              $
              34.2
              
              
              $
              146.6
              
              
              $
              112.7Basic
      and diluted net income per limited partner unit:Common
      units
              
              $
              0.49
              
              
              $
              0.35
              
              
              $
              1.09
              
              
              $
              0.97Subordinated
      units
              
              $
              0.49
              
              
              $
              0.17
              
              
              $
              1.09
              
              
              $
              0.97Cash
      distribution per unit to common and subordinated units
              
              $
              0.465
              
              
              $
              0.43
              
              
              $
              0.925
              
              
              $
              0.845Weighted-average
      number of limited partner units outstanding:Common
      units
              
              
              92.3
              
              
              
              83.2
              
              
              
              91.5
              
              
              
              79.6Subordinated
      units
              
              
              33.1
              
              
              
              33.1
              
              
              
              33.1
              
              
              
              33.1
 
 The
accompanying notes are an integral part of these condensed consolidated
financial statements.
  5
  BOARDWALK
PIPELINE PARTNERS, LP
 
 CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 (Millions)
 (Unaudited)
 
 For
      theSix
      Months EndedJune
      30,2008
              
              
              2007OPERATING
      ACTIVITIES:Net
      income
              
              $
              152.8
              
              
              $
              115.7Adjustments
      to reconcile to cash provided by operations:Depreciation
      and amortization
              
              
              57.8
              
              
              
              40.1Amortization
      of deferred costs
              
              
              4.4
              
              
              
              3.8Amortization
      of acquired executory contracts
              
              
              (0.2
              )
              
              
              (0.9
              )Asset
      impairment
              
              
              1.4
              
              
              
              14.7(Gain)
      loss on disposal of operating assets and related contracts
              
              
              (14.0
              )
              
              
              1.6Changes
      in operating assets and liabilities:Trade
      and other receivables
              
              
              (26.5
              )
              
              
              17.1Gas
      receivables and storage assets
              
              
              (16.5
              )
              
              
              (1.9
              )Costs
      recoverable from customers
              
              
              (0.2
              )
              
              
              4.3Other
      assets
              
              
              (12.3
              )
              
              
              (6.1
              )Trade
      and other payables
              
              
              1.2
              
              
              
              (11.6
              )Other
      payables, affiliates
              
              
              0.4
              
              
              
              -Gas
      payables
              
              
              38.3
              
              
              
              (5.3
              )Accrued
      liabilities
              
              
              8.1
              
              
              
              10.1Other
      liabilities
              
              
              (23.1
              )
              
              
              (9.9
              )Net
      cash provided by operating activities
              
              
              171.6
              
              
              
              171.7INVESTING
      ACTIVITIES:Capital
      expenditures
              
              
              (1,089.5
              )
              
              
              (380.0
              )Proceeds
      from sale of operating assets
              
              
              4.9
              
              
              
              0.3Proceeds
      from insurance reimbursements and other recoveries
              
              
              3.8
              
              
              
              1.7Advances
      to affiliates, net
              
              
              (1.1
              )
              
              
              (1.2
              )Net
      cash used in investing activities
              
              
              (1,081.9
              )
              
              
              (379.2
              )FINANCING
      ACTIVITIES:Proceeds
      from long-term debt, net of issuance costs
              
              
              247.2
              
              
              
              -Proceeds
      from borrowings on revolving credit agreement
              
              
              518.0
              
              
              
              -Repayment
      of borrowings on revolving credit agreement
              
              
              (518.0
              )
              
              
              -Distributions
              
              
              (120.1
              )
              
              
              (97.7
              )Proceeds
      from sale of common units, net of related transaction
costs
              
              
              243.3
              
              
              
              287.9Proceeds
      from sale of class B units
              
              
              686.0
              
              
              
              -Capital
      contribution from general partner
              
              
              19.2
              
              
              
              6.0Net
      cash provided by financing activities
              
              
              1,075.6
              
              
              
              196.2Increase
      (Decrease) in cash and cash equivalents
              
              
              165.3
              
              
              
              (11.3
              )Cash
      and cash equivalents at beginning of period
              
              
              317.3
              
              
              
              399.1Cash
      and cash equivalents at end of period
              
              $
              482.6
              
              
              $
              387.8
 
 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
 (Millions)
 (Unaudited)
 
 
 Common
                Units
              
              
              Class
      B
                Units
              
              
              Subordinated
                Units
              
              
              General
      Partner
              
              
              Accumulated
      Other Comp Income (Loss)
              
              
              Total
                Partners’
      CapitalBalance
      January 1, 2007
              
              $
              941.8
              
              
              
              -
              
              
              $
              285.5
              
              
              $
              22.1
              
              
              $
              23.1
              
              
              $
              1,272.5Add
      (deduct):Net
      income
              
              
              79.1
              
              
              
              -
              
              
              
              33.6
              
              
              
              3.0
              
              
              
              -
              
              
              
              115.7Distributions
      paid
              
              
              (67.0
              )
              
              
              -
              
              
              
              (28.0
              )
              
              
              (2.7
              )
              
              
              -
              
              
              
              (97.7
              )Sale
      of common units, net of
                related
      transaction costs
                (8.0
      million common units)
              
              
              287.9
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              287.9Capital
      contribution from
                general
      partner
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              6.0
              
              
              
              -
              
              
              
              6.0Other
      comprehensive loss
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (3.7
              )
              
              
              (3.7
              )Balance
      June 30, 2007
              
              $
              1,241.8
              
              
              
              -
              
              
              $
              291.1
              
              
              $
              28.4
              
              
              $
              19.4
              
              
              $
              1,580.7Balance
      January 1, 2008
              
              $
              1,473.9
              
              
              
              -
              
              
              $
              291.7
              
              
              $
              33.2
              
              
              $
              4.2
              
              
              $
              1,803.0Add
      (deduct):Net
      income
              
              
              107.6
              
              
              
              -
              
              
              
              39.0
              
              
              
              6.2
              
              
              
              -
              
              
              
              152.8Distributions
      paid
              
              
              (83.8
              )
              
              
              -
              
              
              
              (30.7
              )
              
              
              (5.6
              )
              
              
              -
              
              
              
              (120.1
              )Sale
      of common units, net of
                related
      transaction costs
                (10.0
      million common
                units)
              
              
              243.3
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              243.3Sale
      of class B units
                (22.9
      million class B units)
              
              
              -
              
              
              $
              686.0
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              686.0Capital
      contribution from
                general
      partner
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              19.2
              
              
              
              -
              
              
              
              19.2Other
      comprehensive loss
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (34.2
              )
              
              
              (34.2
              )Balance
      June 30, 2008
              
              $
              1,741.0
              
              
              $
              686.0
              
              
              $
              300.0
              
              
              $
              53.0
              
              
              $
              (30.0
              )
              
              $
              2,750.0
 
 
 The
accompanying notes are an integral part of these condensed consolidated
financial statements.
 
 
  7
  BOARDWALK
PIPELINE PARTNERS, LP
 
 CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE
INCOME
 (Millions)
 (Unaudited)
 
 For
      the
                Three
      Months Ended
                June
      30,
              
              
              For
      the
                Six
      Months Ended
                June
      30,2008
              
              
              2007
              
              
              2008
              
              
              2007Net
      income
              
              $
              64.7
              
              
              $
              35.4
              
              
              $
              152.8
              
              
              $
              115.7Other
      comprehensive (loss) income:(Loss)
      gain on cash flow hedges
              
              
              (23.0
              )
              
              
              8.4
              
              
              
              (47.4
              )
              
              
              0.9Reclassification
      adjustment transferred
                to
      Net income from cash flow hedges
              
              
              17.0
              
              
              
              (1.5
              )
              
              
              17.6
              
              
              
              (4.5
              )Pension
      and other postretirement benefits costs
              
              
              (2.2
              )
              
              
              (1.5
              )
              
              
              (4.4
              )
              
              
              (0.1
              )Total
      comprehensive income
              
              $
              56.5
              
              
              $
              40.8
              
              
              $
              118.6
              
              
              $
              112.0
 
 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 in 2005. Its business is
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), and Gulf Crossing Pipeline
Company, LLC (Gulf Crossing) which will operate a new interstate pipeline
expected to be placed in service in 2009. Boardwalk Pipelines Holding Corp.
(BPHC), a wholly-owned subsidiary of Loews Corporation (Loews), owns 53.3
million common units, 22.9 million class B units and 33.1 million subordinated
units. Boardwalk GP, LP (Boardwalk GP), an indirect wholly-owned subsidiary
of BPHC, is the Partnership’s general partner and holds a 2% general partner
interest in and all of the incentive distribution rights of the Partnership,
further described in Note 8. The Partnership’s common units are traded
under the symbol “BWP” on the New York Stock Exchange.
 
 The accompanying unaudited condensed
consolidated financial statements of the Partnership were prepared pursuant to
the rules and regulations of the Securities and Exchange Commission. Certain
information and footnote disclosures normally included in financial statements
prepared in accordance with accounting principles generally accepted in the
United States of America have been condensed or omitted pursuant to such rules
and regulations. In the opinion of management, the accompanying condensed
consolidated financial statements reflect all adjustments (consisting of only
normal recurring accruals) necessary to present fairly the financial position as
of June 30, 2008 and December 31, 2007, and the results of operations and
comprehensive income for the three and six months ended June 30, 2008 and 2007,
and changes in cash flow and changes in partners’ capital for the six months
ended June 30, 2008 and 2007. Reference is made to the Notes to Consolidated
Financial Statements in the 2007 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
full year. All intercompany items have been eliminated in
consolidation.
 
 
 Note
2:  Gas in Storage and Gas Receivables/Payables
 
 Gulf
South and Texas Gas store gas on behalf of others. 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, 2008 and December 31, 2007, Gulf South held 35.2
trillion British thermal units (TBtu) and 52.0 TBtu of gas owned by shippers.
Gulf South loaned 1.0 and 0.2 TBtu of gas to shippers as of June 30, 2008 and
December 31, 2007. Consistent with the method of storage accounting elected
by Texas Gas and the risk-of-loss provisions included in its tariff, Texas Gas
reflects gas held on behalf of others in Gas stored underground and records an
equal offsetting payable. The amount reflected in Gas Payables on the Condensed
Consolidated Balance Sheets is valued at a historical cost of gas of $50.7
million and $35.3 million at June 30, 2008 and December 31, 2007.
 
 9
 
 Note
3:Derivative
Financial Instruments
 
 Subsidiaries
of the Partnership use futures, swaps, and option contracts (collectively,
derivatives) to hedge exposure to various risks, including natural gas commodity
price risk and interest rate risk. These derivatives are reported at fair value
in accordance with Statement of Financial Accounting Standards (SFAS) No.
133, Accounting for Derivative
Instruments and Hedging Activities,as
amended.
 
 Certain
volumes of gas stored underground are available for sale and subject to
commodity price risk. At June 30, 2008 and December 31, 2007, approximately
$15.0 million and $16.3 million of gas stored underground, which the Partnership
owns and carries as current Gas stored underground, was exposed to commodity
price risk. The Partnership utilizes derivatives to hedge certain exposures to
market price fluctuations on the anticipated operational sales of
gas.
 
 As a
result of the approval by the Federal Energy Regulatory Commission (FERC) of
Phase III of the Western Kentucky Storage Expansion project in the first quarter
2008, approximately 5.1 billion cubic feet (Bcf) of gas stored underground with
a book value of $11.8 million became available for sale. The Partnership entered
into derivatives, which were designated as cash flow hedges, to hedge the price
exposure related to the expected sale of this gas. Approximately 2.2 Bcf of this
gas was sold in the second quarter 2008, and the related derivatives were
settled, resulting in a gain of $14.7 million which was reported in Net gain on
disposal of operating assets and related contracts on the Condensed Consolidated
Statements of Income. The Partnership recognized a gain of $1.4 million and a
loss of $0.7 million for the three and six months ended June 30, 2007, on
derivatives and related contracts not designated as hedges related to gas stored
underground that became available for sale as a result of Phase II of the
Western Kentucky Storage Expansion project.
 
 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 pipeline expansion projects, of which approximately
1.3 Bcf remained outstanding at June 30, 2008. The derivatives were not
designated as hedges and were marked to fair value through earnings resulting in
a gain of $4.1 million and $7.2 million in Miscellaneous other income, net on
the Condensed Consolidated Statements of Income for the three and six months
ended June 30, 2008, and resulting in a loss of $0.7 million for the
corresponding periods in 2007.
 
 In August
2007, the Partnership entered into a Treasury rate lock for a notional amount of
$150.0 million of principal to hedge the risk attributable to changes in the
risk-free component of forward 10-year interest rates through February 1, 2008.
The Treasury rate lock was designated as a cash flow hedge in accordance with
SFAS No. 133. As of December 31, 2007, the Partnership recorded a payable of
$8.4 million and a corresponding amount in Accumulated other comprehensive loss
for the fair value of the rate lock. On February 1, 2008, the Partnership
settled the rate lock and paid the counterparty approximately $15.0 million
which was deferred as a component of Accumulated other comprehensive loss. The
loss will be amortized to interest expense over 10 years.
 
 With the
exception of the derivatives related to certain storage gas volumes related to
Phase II of the Western Kentucky Storage Expansion project and line pack gas
purchases referred to above, the derivatives related to the sale or purchase of
natural gas, cash for fuel reimbursement and debt generally qualify for cash
flow hedge accounting under SFAS No. 133 and are designated as such. The
effective component of related 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 loss. The deferred gains
and losses are recognized in the Condensed Consolidated Statements of Income
when the anticipated transactions affect earnings. In situations where continued
reporting of a loss in Accumulated other comprehensive loss would result in
recognition of a future loss on the combination of the derivative and the hedged
transaction, SFAS No. 133 requires that the loss be immediately recognized in
earnings for the amount that is not expected to be recovered. The Partnership
reclassified losses of $1.7 million for the three and six months ended June 30,
2008, from Accumulated other comprehensive loss to earnings related to amounts
that are not expected to be recovered in future periods from the combination of
sales of gas stored underground and the deferred losses associated with related
derivatives.
 
 10
  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 projects, any gains and
losses on the related derivatives would be recognized in Net (gain) 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.
 
 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 no longer
deemed probable to occur, hedge accounting would be terminated and changes in
the fair values of the associated derivative financial instruments would be
recognized currently in earnings. Less than $0.1 million of ineffectiveness was
recorded for the three and six months ended June 30, 2008. Ineffectiveness
increased Net income by $0.1 million and $0.4 million for the three and six
months ended June 30, 2007. The Partnership did not discontinue any cash flow
hedges during the three and six month periods ended June 30, 2008 and
2007.
 
 Note 4
contains information regarding the fair values of the Partnership’s derivative
instruments. Included as a component of Other current assets was $9.3 million of
cash which was deposited as collateral as a result of net loss positions on
derivatives at June 30, 2008.
 
 
 Note
4:  Fair Value
 
 SFAS
No. 157, Fair Value Measurements
 
 In 2008, the Partnership implemented
the provisions of SFAS No. 157, except for the provisions related to
non-financial assets and liabilities measured at fair value on a non-recurring
basis, which provisions will be applied beginning in 2009. Fair value refers to
the price that would be received to sell an asset or paid to transfer a
liability in an orderly transaction in the principal market in which the
reporting entity transacts based on the assumptions market participants would
use when pricing the asset or liability. SFAS No. 157 establishes a fair value
hierarchy that prioritizes the information used to develop those assumptions
giving priority, from highest to lowest, to quoted prices in active markets for
identical assets and liabilities (Level 1); observable inputs not included in
Level 1, for example, quoted prices for similar assets and liabilities (Level
2); and unobservable data (Level 3), for example, a reporting entity’s own
internal data based on the best information available in the
circumstances.
 
 The
Partnership identified its derivatives as items governed by the provisions of
SFAS No. 157. The derivatives in existence at June 30, 2008, were natural gas
price swaps and options, which were recorded at fair value based on New York
Mercantile Exchange (NYMEX) quotes for natural gas futures and options. The
NYMEX quotes were deemed to be observable inputs for similar assets and
liabilities and rendered Level 2 inputs for purposes of disclosure. The
application of SFAS No. 157 had no effect on the Partnership’s financial
statements.
 
 11
  The fair
values of derivatives existing as of June 30, 2008, were included in the
following captions in the Condensed Consolidated Balance Sheets (in
millions):
 
 Total
      at
                June
      30, 2008
              
              
              Quoted
      Prices in Active Markets for Identical Assets
                Level
      1
              
              
              Significant
      Other Observable Inputs
                Level
      2
              
              
              Significant
      Unobservable Inputs
                Level
      3Assets:Prepaid
      expenses and other current assets
              
              $
              7.9
              
              
              
              -
              
              
              $
              7.9
              
              
              
              -Total
      assets
              
              $
              7.9
              
              
              
              -
              
              
              $
              7.9
              
              
              
              -Liabilities:Other
      current liabilities
              
              $
              15.9
              
              
              
              -
              
              
              $
              15.9
              
              
              
              -Other
      non-current liabilities
              
              
              1.6
              
              
              
              -
              
              
              
              1.6
              
              
              
              -Total
      liabilities
              
              $
              17.5
              
              
              
              -
              
              
              $
              17.5
              
              
              
              -
 
 
 SFAS
No. 159, The Fair Value Option for Financial Assets and Financial
Liabilities
 
 In 2008, the Partnership had the option
to apply the provisions of SFAS No. 159, which allows companies to elect to
measure and record certain financial assets and liabilities at fair value that
would not otherwise be recorded at fair value, such as long-term debt or notes
receivable. Unrealized gains and losses on items for which the fair value option
was chosen would be reported in earnings. The Partnership reviewed its financial
assets and liabilities in existence at January 1, 2008, as well as any financial
assets and liabilities entered into during the six month period ended June 30,
2008, and did not elect the fair value option for any applicable items.
Consequently, the application of SFAS No. 159 had no effect on the Partnership’s
financial statements.
 
 
 Note 5:  Income Taxes
 
 The Partnership is not a taxable entity
for federal income tax purposes. As such, it does not directly pay federal
income tax. The Partnership’s taxable income or loss, which may vary
substantially from the net income or loss reported in the Condensed Consolidated
Statements of Income, is includable in the federal income tax returns of each
partner. The aggregate difference in the basis of the Partnership’s net assets
for financial and income tax purposes cannot be readily determined as the
Partnership does not have access to the information about each partner’s tax
attributes. The subsidiaries of the Partnership directly incur some income-based
state taxeswhich are
presented in Income taxes on the Condensed Consolidated Statements of
Income.
 
 
 Note
6:  Commitments and Contingencies
 
 A.  Calpine
Energy Services (Calpine) Settlement
 
 In
December 2007, Gulf South and Calpine filed a stipulation and agreement in
Calpine’s Chapter 11 Bankruptcy proceedings to settle, for approximately $16.5
million, Gulf South’s claim against Calpine related to Calpine’s non-payment
under a transportation agreement. The claim, which was approved in January 2008,
was to be paid in the form of Calpine stock, along with other general creditors
having claims in the Bankruptcy proceeding. In the fourth quarter 2007, the
Partnership recognized $4.1 million of revenues related to previously reserved
amounts invoiced to Calpine for transportation services previously rendered. In
January 2008, the Partnership sold the entire claim to a third party and
received a cash payment of approximately $15.3 million. The transfer of the
claim was deemed a sale and any recourse related to the sale expired in January
2008. As a result, in the first quarter 2008, the Partnership recorded a net
gain of $11.2 million related to the realization of the unrecognized portion of
the claim which was reported as Contract settlement gain on the Condensed
Consolidated Statements of Income. The matter is considered settled and the
Partnership does not expect to receive additional amounts related to the
claim.
 
 12
  B.  Jackson
Storage Loss
 
 The Partnership’s Jackson, Mississippi
aquifer storage facility has a working gas capacity of approximately 5.0 Bcf and
is primarily used for operational purposes. In the fourth quarter 2007, it was
estimated that a gas loss of approximately 1.3 Bcf had occurred. As a result of
the estimated gas loss, the Partnership recognized a charge to earnings of $0.7
million in the fourth quarter 2007. In the second quarter 2008, a more
comprehensive test of the field was completed resulting in no adjustment to
the amount previously charged to earnings.
 
 C.  Hurricane
Rita Settlement
 
 In
September 2005, Hurricane Rita caused physical damage to a portion of the
Partnership’s assets. The related remediation work was completed in 2007. In the
second quarter 2008, the Partnership received insurance proceeds of $4.7 million
which were applied against a receivable for probable recoveries that was
established in the third quarter 2007. The Partnership received an additional
$1.0 million in the third quarter 2008 as final settlement.
 
 D.  Legal
Proceedings
 
 Napoleonville
Salt Dome Matter
 
 In
December 2003, natural gas leaks were observed near two natural gas storage
caverns that were leased and operated by Gulf South for natural gas storage in
Napoleonville, Louisiana. Gulf South commenced remediation efforts immediately
and ceased using those storage caverns. Two class action lawsuits were filed
relating to this incident and were converted to individual actions. Several
additional individual actions have been filed against Gulf South and other
defendants by local residents and businesses. In addition, the lessor of the
property has filed a claim against Gulf South in an action filed against the
lessor by one of Gulf South's insurers. Most of the claims have been settled and
Gulf South continues to vigorously defend each of the remaining 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 many 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.For the six month period
ended June 30, 2008, the Partnership received $3.9 million in insurance proceeds
related to previously incurred litigation and remediation costs, which were
recorded as a reduction to Operation and maintenance expense.
 
  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.
 
 E.  Regulatory
and Rate Matters
 
 Expansion
Capital Projects
 
 The
Partnership has been engaged in several pipeline expansion projects as described
below:
 
 East Texas to Mississippi
Expansion.The Partnership completed the East Texas to
Mississippi expansion project during the second quarter 2008 at a total cost of
approximately $960.1 million. This project consists of approximately 242 miles
of 42-inch pipeline from DeSoto Parish in western Louisiana to near Harrisville,
Mississippi. Customers have contracted at fixed rates for 1.4 Bcf per day of
firm transportation capacity on a long-term basis which represents substantially
all of the normal operating capacity.
 
 Southeast
Expansion.  The pipeline and one compressor station related to
this project were placed in service during the second quarter 2008. This project
consists of approximately 111 miles of 42-inch pipeline originating near
Harrisville, Mississippi and extending to an interconnect with Transcontinental
Pipe Line Company (Transco) in Choctaw County, Alabama (Transco 85), having 1.2
Bcf of peak-day transmission capacity. The Partnership expects to expand the
project through the addition of compression facilities to 2.2 Bcf of peak-day
transmission capacity. The Partnership expects this additional capacity to be in
service during the first quarter 2009 to coincide with the commencement of
service on its Gulf Crossing project. Customers have contracted at fixed rates
for 660 million cubic feet (MMcf) per day of firm transportation capacity on a
long-term basis (with a weighted-average term of 9.2 years), in addition to the
capacity lease agreement with Gulf Crossing discussed below. Through June 30,
2008, the Partnership spent $553.6 million related to this project.
 
 13
  Gulf Crossing Project.The
Partnership is constructing a new interstate pipeline that will begin near
Sherman, Texas and proceed to the Perryville, Louisiana area and will consist of
approximately 357 miles of 42-inch pipeline having approximately 1.7 Bcf of
peak-day transmission capacity with the addition of compression
facilities.  Additionally, Gulf Crossing has entered into, subject to
regulatory approval: (i) a capacity lease agreement for 1.1 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 Transco 85;
and (ii) a capacity lease agreement with Enogex, a third-party intrastate
pipeline, which will bring gas supplies to the Partnership’s system. Customers
have contracted at fixed rates for 1.7 Bcf per day of long-term firm
transportation capacity (with a weighted average term of approximately 9.5
years). The Partnership expects the pipeline to be in service during the first
quarter 2009 and the additional compression to be in service by 2010. Through
June 30, 2008, the Partnership spent $504.7 million related to this
project.
 
 Fayetteville and Greenville
Laterals.  The Partnership is constructing two laterals on its
Texas Gas pipeline system to transport gas from the Fayetteville Shale area in
Arkansas to markets directly and indirectly served by the Partnership’s existing
interstate pipelines. The Fayetteville Lateral will originate in Conway County,
Arkansas and proceed southeast through the Bald Knob, Arkansas area to an
interconnect with the Texas Gas mainline in Coahoma County, Mississippi and
consists of approximately 165 miles of 36-inch pipeline. The Greenville Lateral
will originate at the Texas Gas mainline near Greenville, Mississippi and
proceeds east to the Kosciusko, Mississippi area consisting of approximately 95
miles of 36-inch pipeline. The Greenville Lateral will allow customers to access
additional markets, primarily in the Midwest, Northeast and Southeast. The
Partnership recently executed contracts for additional capacity that will
require it to add compression to increase the peak-day transmission capacity to
approximately 1.3 Bcf for the Fayetteville Lateral and to approximately 1.0 Bcf
for the Greenville Lateral. The contracts associated with this project are at
fixed rates with a weighted average term of 9.9 years. The Partnership expects
the first 60 miles of the Fayetteville Lateral to be in service during the third
quarter 2008 and the remainder of the pipeline related to the Fayetteville and
Greenville Laterals to be in service during the first quarter 2009. The
Partnership expects to make additional filings with FERC during the third
quarter 2008 regarding the additional compression required to increase the
peak-day transmission capacity and expects the additional capacity to be in
service during 2010. Through June 30, 2008, the Partnership spent $260.9 million
related to the Fayetteville and Greenville Laterals.
 
 The
Partnership is also engaged in the following storage expansion
project:
 
 Western Kentucky Storage Expansion
Phase III.  The Partnership is developing up to 8.3 Bcf of new
working gas capacity at its Midland storage facility and FERC has granted the
Partnership market-based rate authority for this new capacity. This expansion is
supported by 10-year precedent agreements for 5.1 Bcf of storage capacity. The
cost of this project will be dependent on the ultimate size of the expansion.
The Partnership expects 5.4 Bcf of storage capacity to be in service during the
fourth quarter 2008. Through June 30, 2008, the Partnership spent
$15.8 million related to this project.
 
 F.  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 remediation
efforts are probable and the costs can be reasonably estimated. In addition to
federal and state mandated remediation requirements, the Partnership often
enters into voluntary remediation programs with the agencies. The Partnership
believes its accruals for environmental liabilities are adequate to accomplish
remediation related to federal and state regulations. Depending on the results
of on-going assessments and federal and state agency review of the data,
revisions to the Partnership’s estimates may be necessary based on actual costs
or new circumstances.
 
 14
  As
of June 30, 2008 and December 31, 2007, the Partnership had an accrued liability
of approximately $15.9 million and $17.0 million related to assessment and/or
remediation costs associated with the historical use of polychlorinated
biphenyls, petroleum hydrocarbons and mercury, enhancement of groundwater
protection measures and other costs. The expenditures are expected to occur over
approximately the next ten years. The accrual represents management’s estimate
of the undiscounted future obligations based on evaluations and discussions with
counsel and operating personnel and the current facts and circumstances related
to these matters. As of June 30, 2008 and December 31, 2007, approximately $2.7
million was recorded in Other current liabilities and approximately $13.2
million and $14.3 million were recorded in Other Liabilities and Deferred
Credits.
 
 In March
2008, the Environmental Protection Agency (EPA) adopted regulations lowering the
8-hour ozone standard relevant to non-attainment areas.  Under the
regulation new non-attainment areas will be identified which may require
additional emission controls for compliance at as many as 14 facilities operated
by the Partnership. The anticipated effective date for compliance with the
proposed standard in its current state is between 2013 and 2016.
 
 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.
 
 G.  Commitments
 
 The Partnership’s future capital
commitments as of June 30, 2008, for contracts already authorized are expected
to approximate the following amounts (in millions):
 Less
      than 1 year
              
              $
              429.41-3
      years
              
              
              21.84-5
      years
              
              
              -More
      than 5 years
              
              
              -Total
              
              $
              451.2
  There were no substantial changes to
the Partnership’s operating lease commitments as disclosed in Note 3 to the
Partnership’s Annual Report on Form 10-K.
 
 
 Note
7:  Financing
 
 Senior
Unsecured Debt
 
 In March 2008, the Partnership received
net proceeds of approximately $247.2 million after deducting initial purchaser
discounts and offering expenses of $2.8 million from the sale of $250.0 million
of 5.50% senior unsecured notes of Texas Gas due April 1, 2013. Interest on the
notes will be payable on April 1 and October 1 of each year, beginning on
October 1, 2008. The notes are redeemable, in whole or in part, at the
option of Texas Gas at any time, at a redemption price equal to the greater of
100% of the principal amount of the notes to be redeemed or a “make whole”
redemption price based on the remaining scheduled payments of principal and
interest discounted to the date of redemption at a Treasury rate plus 50 basis
points, plus accrued and unpaid interest, if any. Other customary covenants
apply, including those concerning events of default.
 
 As
of June 30, 2008 and December 31, 2007, the weighted-average interest rate of
the Partnership’s long-term debt was 5.89% and 5.82%.
 
 15
  Revolving
Credit Facility
 
 As of
June 30, 2008 and December 31, 2007, no funds were drawn under the Partnership’s
$1.0 billion revolving credit facility. However, at June 30, 2008, the
Partnership had outstanding letters of credit under the facility of $57.6
million to support certain obligations associated with the pipeline expansion
projects which reduced the available capacity under the facility by such amount.
During the six-month period ended June 30, 2008, the Partnership borrowed and
repaid $518.0 million under the facility, with a weighted-average borrowing rate
of 2.87%. As of June 30, 2008, the Partnership and its subsidiaries were in
compliance with all covenant requirements under the credit
agreement.
 
 Capitalized
Interest and Allowance for Funds Used During Construction
 
 During
the three and six months ended June 30, 2008, the Partnership capitalized
interest of $14.9 million and $23.5 million. During the three and six months
ended June 30, 2007, the Partnership capitalized interest of $4.2 million and
$6.3 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 for certain of its operations. The Partnership
capitalized AFUDC of $0.1 million for the three and six months ended June 30,
2008, and $0.7 million and $1.2 million for the three and six months ended June
30, 2007. In the second quarter 2008, the Partnership determined that SFAS No.
71 would not be applicable for the Fayetteville and Greenville Laterals. As a
result, the Partnership recorded $2.6 million of capitalized interest and
reversed $3.6 million of AFUDC.
 
 Offering
of Common Units
 
 In June
2008, the Partnership completed a public offering of 10.0 million of its common
units at a price of $25.30 per unit.  The Partnership received
proceeds of approximately $248.5 million, net of underwriting discounts and
offering expenses of $9.7 million, which includes approximately $5.2 million
contributed by its general partner to maintain its 2% interest. The proceeds of
the offering were used to repay amounts borrowed under the revolving credit
facility and to fund a portion of the costs of its ongoing expansion
projects.
 
 In March
2007, the Partnership completed an equity offering of 8.0 million of its common
units at a price of $36.50 per unit.  The Partnership received
proceeds of approximately $293.9 million, net of underwriting discounts and
offering expenses of $4.2 million, which includes approximately $6.0 million
contributed by its general partner to maintain its 2% interest. The proceeds of
the offering have been used to finance the Partnership’s expansion
projects.
 
 Class
B Units
 
 In June
2008, the Partnership issued and sold, pursuant to the Class B Unit Purchase
Agreement (the Purchase Agreement), approximately 22.9 million of class B units
representing limited partner interests (class B units) to BPHC for $30.00 per
class B unit, or an aggregate purchase price of $686.0 million. The
Partnership’s general partner also contributed $14.0 million to the Partnership
to maintain its 2% interest. The Partnership used the proceeds of $700.0 million
to repay amounts borrowed under the revolving credit facility and to fund a
portion of the costs of its ongoing expansion projects.
 
 The class
B units will share in quarterly distributions of available cash from operating
surplus on a pari passu basis with the Partnership’s common units, until each
common unit and class B unit has received a quarterly distribution of $0.30. The
class B units will not participate in quarterly distributions above $0.30 per
unit.
 
 The class
B units will share in income allocations beginning on July 1, 2008, and any
distribution that may be made beginning with the fourth quarter 2008. As a
result, no earnings were allocated to the class B capital account for the three
and six months ended June 30, 2008.
 
 The class
B units have the same voting rights as if they were outstanding common units and
are entitled to vote as a separate class on any matters that materially
adversely affect the rights or preferences of the class B units in relation to
other classes of partnership interests or as required by law. Pursuant to the
Purchase Agreement, the Partnership entered into a Registration Rights Agreement
with BPHC covering the common units into which the class B units will be
convertible.  The class B units will be convertible into common units
by the holder on a one-for-one basis at any time after June 30,
2013.
 
 16
 
 Note
8:  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 (EITF) Issue 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 (IDRs) in accordance with the partnership agreement as
follows:
 
 Total
      Quarterly Distribution
              
              Marginal Percentage
                Interest in
                DistributionsTarget
      Amount
              Limited
      Partner
                Unitholders
                (1),(2)
              
              General
                Partner
      UnitholdersMinimum
      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%
 
 
 (1)
              The
      class B unitholders participate in distributions on a pari passu basis
      with the Partnership’s common units up to $0.30 per quarter, beginning
      with any distribution that may be made in the fourth quarter 2008.
      The class B units will not participate in quarterly distributions above
      $0.30 per unit.
  (2)
              The
      partnership agreement provides that during the subordination period, the
      subordinated units will not receive distributions until the general
      partner, common and class B unitholders have received their respective
      minimum quarterly distribution plus any arrearages. The subordinated units
      are not entitled to arrearages.
 
 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, 2008 and 2007, were adjusted to take into account an assumed
allocation to the general partner's IDRs. Payments made on account of the IDRs
are determined in relation to actual declared distributions. 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
millions, except per unit data):
  17
  
 For
      the
                Three
      Months Ended
                June
      30,
              
              
              For
      the
                Six
      Months Ended
                June
      30,2008
              
              
              2007
              
              
              2008
              
              
              2007Limited
      partners' interest in net income
              
              $
              61.8
              
              
              $
              34.2
              
              
              $
              146.6
              
              
              $
              112.7Less
      assumed allocation to IDRs
              
              
              0.8
              
              
              
              (0.5
              )
              
              
              10.1
              
              
              
              3.7Net
      income available to limited partners
              
              
              61.0
              
              
              
              34.7
              
              
              
              136.5
              
              
              
              109.0Less
      assumed allocation to subordinated units
              
              
              16.1
              
              
              
              5.6
              
              
              
              36.2
              
              
              
              32.0Net
      income available to common units
              
              $
              44.9
              
              
              $
              29.1
              
              
              $
              100.3
              
              
              $
              77.0Weighted
      average common units
              
              
              92.3
              
              
              
              83.2
              
              
              
              91.5
              
              
              
              79.6Weighted
      average subordinated units
              
              
              33.1
              
              
              
              33.1
              
              
              
              33.1
              
              
              
              33.1Net
      income per limited partner unit –
                common
      units
              
              $
              0.49
              
              
              $
              0.35
              
              
              $
              1.09
              
              
              $
              0.97Net
      income per limited partner unit –
                subordinated
      units
              
              $
              0.49
              
              
              $
              0.17
              
              
              $
              1.09
              
              
              $
              0.97
 
 As discussed in Note 7, the class B
units do not participate in income allocations until the third quarter 2008. As
a result, no income allocations were made to the class B unit equity accounts
and no assumed allocations to the class B units were made pursuant to EITF No.
03-6 for purpose of computing earnings per unit for the three and six month
periods ended June 30, 2008.
 
 In the six month periods ended June 30,
2008 and 2007, the Partnership declared quarterly distributions per unit to
unitholders of record, including common and subordinated units and the 2%
general partner interest and IDRs held by its general partner as follows (in
millions, except distribution per unit):
 
 Payable
      Date
              
              Distribution
      per Unit
              
              
              Amount
      Paid to Limited Partner Unitholders
              
              
              Amount
      Paid to General Partner
                Unitholders
      (Including IDRs)May
      12, 2008
              
              $
              0.465
              
              
              $
              57.6
              
              
              $
              2.9February
      25, 2008
              
              
              0.460
              
              
              
              56.9
              
              
              
              2.7May
      14, 2007
              
              
              0.430
              
              
              
              50.0
              
              
              
              1.5February
      27, 2007
              
              
              0.415
              
              
              
              45.0
              
              
              
              1.2
 
 In July
2008, the Partnership declared a quarterly cash distribution to unitholders of
record of $0.47 per unit.
 
 
 Note 9: Property, Plant and
Equipment
 
 In 2008,
the Partnership placed in service the remaining pipeline assets and related
compression associated with the East Texas to Mississippi Expansion project from
Delhi, Louisiana to Harrisville, Mississippi. Additionally, the Partnership
placed in service the pipeline assets and one compressor station related to the
Southeast Expansion project.  As a result, approximately $912.9
million was transferred from Construction work in progress to Property, plant
and equipment during the six months ended June 30, 2008. The assets will
generally be depreciated over a term of 35 years.
 
 In the
first quarter 2008, the Partnership completed a review of the non-contiguous
offshore assets of its Gulf South subsidiary and provided notice to the other
interest holders of its intent to discontinue any use of its portion of the
available capacity of these assets. As a result, the Partnership reviewed the
assets for recoverability in accordance with SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, and recorded an impairment charge of
approximately $1.4 million representing the net book value of the related
assets.
 
 18
   The
Partnership was developing a salt dome storage cavern near Napoleonville,
Louisiana. Operational tests, which were completed in July 2007, indicated
that due to geological and other anomalies that could not be corrected, the
Partnership would be unable to place the cavern in service as expected. As
a result, the Partnership elected to abandon that cavern and is exploring the
possibility of securing a new site on which a new cavern could be
developed. In accordance with the requirements of  SFAS No.
144, the carrying value of the cavern and related facilities 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.
 
 
 Note
10: Credit Concentration
 
 Natural
gas price volatility has increased dramatically in recent years, which has
materially increased credit risk related to gas loaned to customers. Gas loaned
to customers refers to receivables for services provided, as well as volumes
owed by customers for imbalances or gas lent by the Partnership to them,
generally under parking and lending and no-notice services. As of June 30, 2008,
the amount of gas loaned out by the Partnership’s subsidiaries was approximately
20.1 TBtu and the amount considered an imbalance was approximately 4.2 TBtu.
Assuming an average market price during June 2008 of $12.54 per million British
thermal units, the market value of gas loaned out and considered an imbalance at
June 30, 2008, would have been approximately $304.8 million. If any significant
customer of the Partnership should have credit or financial problems resulting
in a delay or failure to repay the gas they owe to it, this could have a
material adverse effect on the Partnership’s financial condition, results of
operations and cash flows.
 
 
 Note
11:  Employee Benefits
 
 Defined
Benefit Plans
 
 Texas Gas employees hired prior to
November 1, 2006, are covered under a non-contributory, defined benefit pension
plan. The Texas Gas Supplemental Retirement Plan provides pension benefits for
the portion of an eligible employee’s pension benefit that becomes subject to
compensation limitations under the Internal Revenue Code. Texas Gas provides
postretirement medical benefits and life insurance to retired employees who were
employed full time, hired prior to January 1, 1996, and have met certain other
requirements. The Partnership uses a measurement date of December 31 for its
benefits plans.
 
 19
  Components of net periodic benefit cost for both the retirement plans and
postretirement benefits other than pensions (PBOP) for the three and six months
ended June 30, 2008 and 2007, were the following (in millions):
 
 Retirement
      Plans
              
              
              PBOPFor
      the
                Three
      Months Ended
                June
      30,
              
              
              For
      the
                Three
      Months Ended
                June
      30,2008
              
              
              2007
              
              
              2008
              
              
              2007Service
      cost
              
              $
              0.9
              
              
              $
              0.9
              
              
              $
              0.1
              
              
              $
              0.1Interest
      cost
              
              
              1.6
              
              
              
              1.6
              
              
              
              0.8
              
              
              
              0.7Expected
      return on plan assets
              
              
              (1.7
              )
              
              
              (1.7
              )
              
              
              (1.2
              )
              
              
              (1.2
              )Amortization
      of prior service credit
              
              
              -
              
              
              
              -
              
              
              
              (1.9
              )
              
              
              (1.9
              )Amortization
      of unrecognized net loss
              
              
              -
              
              
              
              0.1
              
              
              
              -
              
              
              
              -Settlement
      charge
              
              
              -
              
              
              
              0.7
              
              
              
              -
              
              
              
              -Regulatory
      asset decrease
              
              
              -
              
              
              
              -
              
              
              
              1.3
              
              
              
              1.4Net
      periodic pension expense
              
              $
              0.8
              
              
              $
              1.6
              
              
              $
              (0.9
              )
              
              $
              (0.9
              )
 
 
 Retirement
      Plans
              
              
              PBOPFor
      the
                Six
      Months Ended
                June
      30,
              
              
              For
      the
                Six
      Months Ended
                June
      30,2008
              
              
              2007
              
              
              2008
              
              
              2007Service
      cost
              
              $
              1.8
              
              
              $
              1.9
              
              
              $
              0.3
              
              
              $
              0.3Interest
      cost
              
              
              3.2
              
              
              
              3.2
              
              
              
              1.6
              
              
              
              1.6Expected
      return on plan assets
              
              
              (3.3
              )
              
              
              (3.6
              )
              
              
              (2.5
              )
              
              
              (2.3
              )Amortization
      of prior service credit
              
              
              -
              
              
              
              -
              
              
              
              (3.9
              )
              
              
              (3.9
              )Amortization
      of unrecognized net loss
              
              
              -
              
              
              
              0.2
              
              
              
              0.1
              
              
              
              0.3Settlement
      charge
              
              
              -
              
              
              
              3.8
              
              
              
              -
              
              
              
              -Regulatory
      asset decrease
              
              
              -
              
              
              
              -
              
              
              
              2.7
              
              
              
              2.7Net
      periodic pension expense
              
              $
              1.7
              
              
              $
              5.5
              
              
              $
              (1.7
              )
              
              $
              (1.3
              )
 
 Defined
Contribution Plans
 
 Gulf
South employees and Texas Gas employees hired on or after November 1, 2006, are
provided retirement benefits under a defined contribution money purchase
plan. The operating subsidiaries also provide 401(k) plan benefits to their
employees. Costs related to the Partnership’s defined contribution plans were
$1.5 million and $3.1 million for the three and six months ended June 30, 2008,
and $1.3 million and $2.6 million for the three and six months ended June 30,
2007.
 
 
 Note
12:  Related Parties
 
 Loews provides a variety of corporate
services to the Partnership and its subsidiaries under service agreements.
Services provided by Loews include, among others, information technology, tax,
risk management, internal audit and corporate development services. Loews
charged $3.4 million and $7.5 million for the three and six months ended June
30, 2008, and $2.4 million and $6.6 million for the three and six months ended
June 30, 2007, to the Partnership based on the actual time spent by Loews
personnel performing these services, plus related expenses.
 
 Distributions paid related to common
and subordinated units held by BPHC and the 2% general partner interest and IDRs
held by Boardwalk GP were $85.5 million and $75.6 million during the six months
ended June 30, 2008 and 2007.
 
 The
Partnership pays franchise and certain other taxes on behalf of BPHC and records
a note receivable from BPHC for the amounts paid, which is settled quarterly.
The notes accrue interest at London Interbank Offered Rate plus one percent. For
the three and six months ended June 30, 2008, the Partnership paid $1.2 million
and $1.3 million on behalf of BPHC. For the three and six months ended June 30,
2007, the Partnership paid $0.4 million and $0.9 million on behalf of BPHC. A
note receivable of $2.7 million remained at June 30, 2008.
 
 20
 
 Note
13:  Accumulated Other Comprehensive (Loss) Income
 
 The following table shows the
components of Accumulated other comprehensive loss, net of tax which is included
in Partners’ Capital on the Condensed Consolidated Balance Sheets (in
millions):
 
 As
      of
                June
      30,
              
              As
      of
                December
      31,2008
              
              2007Loss
      on cash flow hedges
              
              $
              (38.7
              )
              
              $
              (8.9
              )Deferred
      components of net periodic benefit cost
              
              
              8.7
              
              
              
              13.1Total
      Accumulated other comprehensive (loss) income
              
              $
              (30.0
              )
              
              $
              4.2
 
 
 Note
14:  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 make loans to
the Partnership and had no restricted assets at June 30, 2008.
 
 
 Note
15:  Recently Issued Accounting Pronouncements
 
  In March
2008, the Financial Accounting Standards Board (FASB) issued SFAS No. 161, Disclosures about Derivative
Instruments and Hedging Activities,which requires entities to provide
enhanced disclosures about (a) how and why the entity uses derivative
instruments, (b) how derivative instruments and related hedged items are
accounted for under SFAS No. 133 and its related interpretations, and (c) how
derivative instruments and related hedged items affect the entity’s financial
position, financial performance, and cash flows. SFAS No. 161 is effective for
fiscal years and interim periods beginning after November 15, 2008. The
Partnership is evaluating the effect that SFAS No. 161 will have on its
financial statements.
   In March 2008, the FASB
approved EITF Issue No. 07-4,  Application of the Two-Class Method
under FASB Statement No. 128, Earnings per Share, to Master Limited
Partnerships, which requires that master limited partnerships use the
two-class method of allocating earnings to calculate earnings per
unit. EITF Issue No. 07-4 is effective for fiscal years and interim periods
beginning after December 15, 2008. The Partnership is evaluating the effect
that EITF Issue No. 07-4 will have on its earnings per unit and financial
statements.
   
   21
  Item 2.   Management's Discussion and Analysis of
Financial Condition and Results of Operations
 
 The following discussion and analysis
of financial condition and results of operations should be read in conjunction
with our accompanying interim condensed consolidated financial statements and
related notes, included elsewhere in this report and prepared in accordance with
accounting principles generally accepted in the United States of America and our
consolidated financial statements, related notes, Management's Discussion and
Analysis of Financial Condition and Results of Operations and Risk Factors
included in our Annual Report on Form 10-K for the year ended December 31,
2007.
 
 We are a
Delaware limited partnership formed in 2005. Our business is 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, operating subsidiaries) and Gulf Crossing Pipeline Company, LLC (Gulf
Crossing), which will operate a new interstate pipeline expected to be placed in
service in 2009. Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned
subsidiary of Loews Corporation (Loews), owns 53.3 million of our common units,
22.9 million of our class B units and 33.1 million of our subordinated units.
Boardwalk GP, LP (Boardwalk GP), an indirect, wholly-owned subsidiary of BPHC,
is our general partner and holds a 2% general partner interest in and all of our
incentive distribution rights. Our common units are traded under the symbol
“BWP” on the New York Stock Exchange.
 
 
 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 discounts from the maximum allowable cost-based rates are often
granted to customers due to competition in the marketplace.Our Gulf
South subsidiary is authorized to charge market-based rates for its firm and
interruptible storage services. In first quarter 2008, our Texas Gas subsidiary
was provided authority from FERC to charge market-based rates for the storage
services associated with Phase III of our Western Kentucky Storage Expansion
project.
 
 Our transportation services consist of
firm transportation, where the customer pays a capacity reservation charge to
reserve pipeline capacity at certain receipt and delivery points along our
pipeline systems, plus a commodity and fuel charge on the volume actually
transported, and interruptible transportation, where the customer pays to
transport gas only when capacity is available and used. We offer firm storage
services in which the customer reserves and pays for a specific amount of
storage capacity, including injection and withdrawal rights, and interruptible
storage and parking and lending (PAL) services where the customer receives and
pays for capacity only when it is available and used. Some PAL agreements are
paid for at inception of the service and revenues for these agreements are
recognized as service is provided over the term of the agreement.
 
 Our
operating costs and expenses typically do not vary significantly based upon the
amount of gas transported, with the exception of fuel consumed at Gulf South’s
compressor stations, which is part of Operation and maintenance expenses. We
charge shippers for fuel in accordance with each pipeline’s individual tariff
guidelines and Gulf South’s fuel recoveries are included as part of Gas
transportation revenues.
 
 We are not in the business of buying
and selling natural gas other than for system management purposes, but changes
in the price of natural gas can affect the overall supply and demand of natural
gas, which in turn does affect our results of operations. We deliver to a broad
mix of customers including local distribution companies, 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, midwestern and southeastern United States through interconnections
with unaffiliated pipelines.
 
 22
  Our business is affected by trends involving natural gas price levels and
natural gas price spreads, including spreads between physical locations on our
pipeline system, which affects our transportation revenues, and spreads in
natural gas prices across time (for example summer to winter), which primarily
affects our PAL and storage revenues. High natural gas prices in recent years
have helped to drive increased production levels in producing locations such as
the Bossier Sands and Barnett Shale gas producing regions in East Texas, which
has resulted in additional supply being available on the west side of our
system. This has resulted in widened west-to-east basis differentials which have
benefited our transportation revenues. The high natural gas prices have also
driven increased production in regions such as the Fayetteville Shale in
Arkansas and the Caney Woodford Shale in Oklahoma, which, together with the
higher production levels in East Texas, have formed the basis for several
pipeline expansion projects including those being undertaken by us. Wide spreads
in natural gas prices between time periods during the past two to three years,
for example fall 2006 to spring 2007, were favorable for our PAL and
interruptible storage services during that period. These spreads decreased
substantially in 2007 and have continued to decrease into 2008, which resulted
in reduced PAL and interruptible storage revenues. We cannot predict future time
period spreads or basis differentials.
 
 
 Results
of Operations for the Three Months Ended June 30, 2008 and 2007
 
 Ournet
income for the second quarter 2008 increased $29.3 million, or 83%, from the
comparable period in 2007. The primary drivers for the increase were higher
revenues from firm transportation services associated with our expansion
projects and gains on gas sales and mark-to-market derivative activity
associated with our expansion projects. The favorable drivers were partly offset
by lower PAL revenues due to unfavorable natural gas price spreads, and higher
depreciation and property taxes due to an increase in our asset base from
expansion. The 2007 period was unfavorably impacted by an impairment
charge.
 
 Operating
revenues increased $39.8 million, or 26%, to $190.3 million for the second
quarter 2008, compared to $150.5 million for the 2007 period. The primary
increase related to a $28.0 million increase in gas transportation revenues,
excluding fuel, of which the majority was generated by our expansion projects.
Our fuel revenues increased $16.9 million due to expansion-related throughput
and an increase in the price of natural gas. Gas storage revenues increased $3.1
million related to an increase in storage capacity associated with our Western
Kentucky Storage Expansion project. These increases were partially offset by an
$8.2 million decrease in PAL due to unfavorable natural gas price
spreads.
 
 Operating
costs and expenses increased $3.1 million, or 3%, to $109.3 million for the
second quarter 2008, compared to $106.2 million for the 2007 period, primarily
resulting from a $17.0 million increase in fuel costs from expansion projects
and higher natural gas prices. Depreciation and other taxes increased $13.9
million due to an increase in our asset base from expansion. The increased
expenses were offset by a $13.3 million gain on the sale of gas related to our
Western Kentucky Storage Expansion project. The 2007 period was unfavorably
impacted by a $14.7 million impairment charge related to our Magnolia storage
facility.
 
 Total
other deductions increased by $7.4 million, or 85%, to $16.1 million for the
second quarter 2008, compared to $8.7 million for the 2007 period as a result of
increased interest expense due to issuances of debt in March 2008 and August
2007 and increased borrowings under our revolving credit
facility.  These amounts were partly offset by a $4.8 million gain
from the mark-to-market effect of derivatives associated with the purchase of
line pack for our pipeline expansion projects.
 
 
 Results
of Operations for the Six Months Ended June 30, 2008 and 2007
 
 Ournet
income for the first six months of 2008 increased $37.1 million, or 32%, from
the comparable period in 2007. The primary drivers for the increase were higher
revenues from firm transportation services associated with our expansion
projects, gains on gas sales and mark-to-market derivative activity associated
with our expansion projects, and a gain from the settlement of a contract claim.
The favorable drivers were partly offset by lower PAL revenues due to
unfavorable natural gas price spreads and higher depreciation and property taxes
due to an increase in our asset base from expansion. The 2007 period was
unfavorably impacted by an impairment charge.
 
 23
 Operating
revenues for the six months ended June 30, 2008, increased $48.9 million, or
14%, to $387.6 million, compared to $338.7 million for the six months ended June
30, 2007. Gas transportation revenues, excluding fuel, increased $45.2 million
related to our expansion projects and higher rates on our existing systems. Fuel
revenues increased $19.1 million due to expansion-related throughput and higher
natural gas prices. Gas storage revenues increased $6.1 million related to an
increase in storage capacity associated with our Western Kentucky Storage
Expansion project. These increases were partially offset by lower PAL revenues
of $21.5 million due to unfavorable natural gas price spreads.
 
 Operating
costs and expenses for the six months ended June 30, 2008, increased $3.1
million, or 2%, to $205.1 million, compared to $202.0 million for the six months
ended June 30, 2007. The primary drivers were increased depreciation and other
taxes of $25.4 million associated with an increase in our asset base due to
expansion and increased fuel costs of $21.0 million from expansion projects and
higher natural gas prices.  These increases were offset by a $15.4
million gain on the sale of gas related to our Western Kentucky Storage
Expansion project and an $11.2 million gain from the settlement of a contract
claim. The 2007 period was unfavorably impacted by a $14.7 million impairment
charge related to our Magnolia storage facility.
 
 Total
other deductions increased by $8.6 million, or 42%, to $29.2 million for the six
months ended June 30, 2008, compared to $20.6 million for the 2007 period as a
result of increased interest expense due to issuances of new debt in March 2008
and August 2007 and increased borrowings under our revolving credit
facility.  These amounts were partially offset by a $7.9 million
mark-to-market gain from derivatives associated with the purchase of line pack
for our pipeline expansion projects.
 
 
 Liquidity
and Capital Resources
 
 We are a
partnership holding company and derive all of our operating cash flow from our
operating subsidiaries. Our operating subsidiaries use funds from their
respective operations to fund their operating activities and maintenance capital
requirements, service their indebtedness and make advances or distributions to
Boardwalk Pipelines. Boardwalk Pipelines uses cash provided from the operating
subsidiaries and, as needed, borrowings under its revolving credit facility
discussed below, to service its outstanding indebtedness and, when available,
make distributions or advances to us to fund our distributions to
unitholders.
 
 Expansion
Capital Expenditures
 
 We
completed our East Texas to Mississippi expansion project during the second
quarter of 2008 at a total cost of approximately $960.1 million. This project
consists of approximately 242 miles of 42-inch pipeline from DeSoto Parish in
western Louisiana to near Harrisville, Mississippi. Customers have contracted at
fixed rates for 1.4 billion cubic feet (Bcf) per day of firm transportation
capacity on a long-term basis which represents substantially all of the normal
operating capacity.
 
 We are
currently engaged in several pipeline expansion projects, described below, and
expect the estimated total cost of these projects to be as follows (in
millions):
 Estimated
                Cost
      at
                March
      31, 2008
              
              
              Subsequent
      Costs
              
              
              Estimated
      Total Cost
              
              
              Cash
      Invested through
                June
      30, 2008Southeast
      Expansion
              
              $
              775
              
              
              
              -
              
              
              $
              775
              
              
              $
              553.6Gulf
      Crossing Project
              
              
              1,690
              
              
              $
              110
              
              
              
              1,800
              
              
              
              504.7Fayetteville
      and Greenville Laterals
              
              
              1,250
              
              
              
              40
              
              
              
              1,290
              
              
              
              260.9Total
              
              $
              3,715
              
              
              $
              150
              (a)
              
              $
              3,865
              
              
              $
              1,319.2
 
 (a)  These
      costs are related to the addition of compression to increase the
      transmission capacity to approximately 1.7 Bcf per day on the Gulf
      Crossing project and 1.3 Bcf per day on the Fayetteville Lateral. The
      additional capacity is required to accommodate commitments made under new
      transportation agreements. We expect the additional compression to be
      in service in 2010.
 
 24
 Based
upon our current cost estimates, we expect to incur expansion project capital
expenditures of approximately $1.8 billion for the remainder of 2008 and $0.7
billion in 2009 and 2010 to complete our pipeline expansion projects. We expect
to finance our pipeline expansion capital costs through equity financings and
the incurrence of debt, including sales of debt by us and our subsidiaries and
borrowings under our revolving credit facility, as well as available operating
cash flow in excess of our operating needs.
 
 Our total
estimated cost assumes that we will receive the regulatory approvals necessary
to operate the pipelines on certain of our projects at higher pressures, which
will allow us to utilize a higher percentage of the pipeline capacity. Delays in
receipt of these approvals will result in higher costs and additional delays in
our expected in-service dates, which would also result in delays of revenues we
would have received had these delays not occurred, and in certain instances will
result in the payment of penalties to certain customers. Our cost and timing
estimates for these projects are subject to a variety of other risks and
uncertainties, including adverse weather conditions, delays in obtaining key
materials, shortages of qualified labor and escalating costs of labor and
materials. Please refer to Item 1A, Risk Factors, in our 2007
Form 10-K regarding risks associated with our expansion projects and the related
financing.
 
 The
following paragraphs describe each of our pipeline expansion projects in more
detail:
 
 Southeast
Expansion.  The pipeline and one compressor station related to
this project were placed in service during the second quarter 2008. The project
consists of approximately 111 miles of 42-inch pipeline originating near
Harrisville, Mississippi and extending to an interconnect with Transcontinental
Pipe Line Company (Transco) in Choctaw County, Alabama (Transco 85), having 1.2
Bcf of peak-day transmission capacity. We expect to expand the project through
the addition of compression facilities to 2.2 Bcf of peak-day transmission
capacity. We expect this additional capacity to be in service during the first
quarter 2009 to coincide with the commencement of service on our Gulf Crossing
project. Customers have contracted at fixed rates for 660 million cubic feet
(MMcf) per day of firm transportation capacity on a long-term basis (with a
weighted-average term of 9.2 years), in addition to a capacity lease agreement
with Gulf Crossing discussed below.
 
 Gulf Crossing Project.We are
constructing a new interstate pipeline that will begin near Sherman, Texas and
proceed to the Perryville, Louisiana area and will consist of approximately 357
miles of 42-inch pipeline having approximately 1.7 Bcf of peak-day transmission
capacity with the addition of compression facilities. Additionally, Gulf
Crossing has entered into, subject to regulatory approval: (i) a capacity lease
agreement for 1.1 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
Transco 85; and (ii) a capacity lease agreement with Enogex, a third-party
intrastate pipeline, which will bring gas supplies to our system. Customers have
contracted at fixed rates for 1.7 Bcf per day of long-term firm transportation
capacity (with a weighted average term of approximately 9.5 years). We expect
the pipeline to be in service during the first quarter 2009 and the additional
compression to be in service by 2010.
 
 Fayetteville and Greenville
Laterals.  We are constructing two laterals on our Texas Gas
pipeline system to transport gas from the Fayetteville Shale area in Arkansas to
markets directly and indirectly served by our existing interstate pipelines. The
Fayetteville Lateral will originate in Conway County, Arkansas and proceed
southeast through the Bald Knob, Arkansas area to an interconnect with the Texas
Gas mainline in Coahoma County, Mississippi and consists of approximately 165
miles of 36-inch pipeline. The Greenville Lateral will originate at the Texas
Gas mainline near Greenville, Mississippi and proceeds east to the Kosciusko,
Mississippi area consisting of approximately 95 miles of 36-inch pipeline. The
Greenville Lateral will allow customers to access additional markets, primarily
in the Midwest, Northeast and Southeast. We recently executed contracts for
additional capacity that will require us to add compression to increase the
peak-day transmission capacity to approximately 1.3 Bcf for the Fayetteville
Lateral and to approximately 1.0 Bcf for the Greenville Lateral. The contracts
associated with this project are at fixed rates with a weighted average term of
9.9 years. We expect the first 60 miles of the Fayetteville Lateral to be in
service during the third quarter 2008 and the remainder of the pipeline related
to the Fayetteville and Greenville Laterals to be in service during the first
quarter 2009. We expect to make additional filings with FERC during the third
quarter 2008 regarding the additional compression required to increase the
peak-day transmission capacity and expect the additional capacity to be in
service during 2010.
 
 25
 We
are also engaged in the following storage expansion project:
 
 Western Kentucky Storage Expansion
Phase III.  We are developing up to 8.3 Bcf of new working gas
capacity at our Midland storage facility and FERC has granted us market-based
rate authority for this new capacity. This expansion is supported by 10-year
precedent agreements for 5.1 Bcf of storage capacity. The cost of this project
will be dependent on the ultimate size of the expansion. We expect 5.4 Bcf of
storage capacity to be in service during the fourth quarter 2008. Through June
30, 2008, we spent $15.8 million related to this project.
 
 Maintenance
Capital Expenditures
 
 Maintenance capital expenditures for
the six months ended June 30, 2008 and 2007, were $13.2 million and $18.0
million. We expect to fund the remaining 2008 maintenance capital expenditures
of approximately $45.0 million from our operating cash flows.
 
 Distributions
 
 For the six months ended June 30, 2008
and 2007, we paid distributions of $120.1 million and $97.7 million. Please see
Note 8 in Part 1 in Item 1 of this report for further discussion.
 
 Equity
and Debt Financing
 
 In June
2008, we issued and sold approximately 22.9 million of class B units
representing limited partner interests (class B units) to BPHC for $30.00 per
class B unit, or an aggregate purchase price of $686.0 million pursuant to the
Class B Unit Purchase Agreement (the Purchase Agreement). Our general partner
also contributed $14.0 million to us to maintain its 2% general partner
interest.  We used the proceeds of $700.0 million to repay amounts
borrowed under the revolving credit facility and to fund a portion of the costs
of our ongoing expansion projects.  Please see Note 7 in Part 1 in
Item 1 of this report for further discussion.
 
 In June
2008, we completed a public offering of 10.0 million of our common units at a
price of $25.30 per unit.  We received proceeds of approximately
$248.5 million, net of underwriting discounts and offering expenses of $9.7
million, which includes approximately $5.2 million contributed by our general
partner to maintain its 2% interest.
 
 In March
2008, we received net proceeds of approximately $247.2 million after deducting
initial purchaser discounts and offering expenses of $2.8 million from the sale
of $250.0 million of 5.50% senior unsecured notes of Texas Gas due April 1,
2013.
 
 Revolving
Credit Facility
 
 We
maintain a $1.0 billion revolving credit facility under which Boardwalk
Pipelines, Gulf South and Texas Gas each may borrow funds, up to applicable
sub-limits. Interest on amounts drawn under the credit facility is payable at a
floating rate equal to an applicable spread per annum over the London Interbank
Offered Rate or a base rate defined as the greater of the prime rate or the
Federal funds rate plus 50 basis points. Under the terms of the agreement, each
of the borrowers must maintain a minimum ratio, as of the last day of each
fiscal quarter, of consolidated total debt to consolidated earnings before
income taxes, depreciation and amortization (as defined in the agreement),
measured for the preceding twelve months, of not more than five to one. The
revolving credit facility has a maturity date of June 29, 2012.
 
 During
the six month period ended June 30, 2008, we borrowed and repaid $518.0 million
under the facility of which the weighted average interest rate on the borrowings
was 2.87%. As of June 30, 2008, we were in compliance with all covenant
requirements under our credit agreement and no funds were drawn under this
facility, however, at June 30, 2008, we had outstanding letters of credit under
the facility for $57.6 million to support certain obligations associated with
the pipeline expansion projects which reduced the available capacity under the
facility by such amount.
 
 26
 Changes
in cash flow from operating activities
 
 Net cash
provided by operating activities remained relatively unchanged at $171.6 million
for the six months ended June 30, 2008 compared to the comparable 2007
period. Cash generated from the increase in net income, excluding non cash
items, of $39.0 million was offset by a decrease in cash due to an increase
in receivables of $30.8 million and the settlement of derivatives.
 
 Changes
in cash flow from investing activities
 
 Net cash
used in investing activities increased $702.7 million to $1,081.9 million for
the six months ended June 30, 2008, compared to $379.2 million for the
comparable 2007 period, primarily due to capital expenditures related to our
expansion projects.
 
 Changes
in cash flow from financing activities
 
 Net cash
provided by financing activities increased $879.4 million to $1,075.6 million
for the six months ended June 30, 2008, compared to $196.2 million for the
comparable 2007 period, primarily due to a $901.8 million increase in net
proceeds from the sale of common and class B units and related general partner
capital contributions and net proceeds from the issuance of long-term debt in
March 2008. These increases were offset by a $22.4 million decrease in cash from
an increase in distributions to our unitholders and general
partner.
 
 Contractual
Obligations
 
 The table below is updated for
significant changes in contractual cash payment obligations as of June 30, 2008,
by period (in millions):
 
 Total
              
              
              Less than
                1
      Year
              
              
              1-3 Years
              
              
              4-5 Years
              
              
              More
      than 5 YearsPrincipal
      payments on long-term debt
              
              $
              2,110.0
              
              
              
              -
              
              
              
              -
              
              
              $
              225.0
              
              
              $
              1,885.0Interest
      on long-term debt
              
              
              981.0
              
              
              $
              59.5
              
              
              $
              234.9
              
              
              
              235.0
              
              
              
              451.6Capital
      commitments
              
              
              451.2
              
              
              
              429.4
              
              
              
              21.8
              
              
              
              -
              
              
              
              -Pipeline
      capacity agreements
              
              
              60.6
              
              
              
              3.1
              
              
              
              12.3
              
              
              
              12.3
              
              
              
              32.9Total
              
              $
              3,602.8
              
              
              $
              492.0
              
              
              $
              269.0
              
              
              $
              472.3
              
              
              $
              2,369.5
 
 The commitments related to pipeline
capacity agreements are associated with the initial 10-year term for capacity on
a third-party pipeline for the Southeast Expansion project.  Pursuant
to the settlement of the Texas Gas rate case in 2006, we are required to
annually fund an amount to the Texas Gas pension plan equal to the amount of
actuarially determined net periodic pension cost, including a minimum of $3.0
million. The above table does not reflect commitments we have made after June
30, 2008, relating to our expansion projects. For information on these projects,
please read “Expansion Capital Expenditures” above.
 
 Off-Balance
Sheet Arrangements
 
 At June 30, 2008, 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.
 
 27
 
 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 in 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 periods in which the facts
that give rise to the revisions become known.
 
 During
the six months ended June 30, 2008, 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, 2007.
 
 
 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.”
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 made by our management 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, are also forward-looking statements.
 
 Forward-looking statements are based on
current expectations and projections about future events and are inherently
subject to a variety of risks and uncertainties, many of which are beyond our
control that could cause actual results to differ materially from those
anticipated or projected. These risks and uncertainties include, among
others:
 
 ·
              We
      may not complete projects, including growth or expansion projects, that we
      have commenced or will commence, or we may complete projects on materially
      different terms, cost or timing than anticipated and we may not be able to
      achieve the intended economic or operational 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 or equipment, weather,
      difficulties or delays in obtaining regulatory approvals or denied
      applications, land owner opposition, the lack of adequate materials, labor
      difficulties or shortages, expansion costs that are higher than
      anticipated and numerous other factors beyond our
  control.
 
 ·
              We
      may not complete any future debt or equity financing
      transaction.
 
 ·
              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 our ability to recover our
      income tax allowance, our full cost of operating our pipelines and a
      reasonable return.
 
 ·
              We
      are subject to laws and regulations relating to the environment and
      pipeline operations which may expose us to significant costs, liabilities
      and loss of revenues. Any changes in such regulations or their application
      could negatively affect our business, financial condition and results of
      operations.
 
 ·
              Our
      operations are subject to operational hazards and unforeseen interruptions
      for which we may not be adequately
insured.
 
 ·
              The
      cost of insuring our assets may increase
  dramatically.
 
 28
 Because
of the natural decline in gas production connected to our system, 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.
 
 ·
              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.
 
 
  29
  Item 3.  Quantitative and Qualitative Disclosures About Market
Risk
 
 Our debt has been issued at fixed
rates, therefore interest expense would not be impacted by changes in interest
rates. Total
long-term debt at June 30, 2008, had a carrying value of $2.1 billion and a fair
value of $2.0 billion.A 100 basis point increase in interest rates on
our fixed rate debt would result in a decrease in fair value of approximately
$123.6 million at June 30, 2008. A 100 basis point decrease would result in an
increase in fair value of approximately $133.6 million at June 30, 2008. The weighted-average
interest rate of our long-term debt was 5.89% at June 30,
2008.
 
 Certain
volumes of our gas stored underground are available for sale and subject to
commodity price risk. At June 30, 2008 and December 31, 2007, approximately
$15.0 million and $16.3 million of gas stored underground, which we own and
carry as current Gas stored underground, is exposed to commodity price risk. We
utilize derivatives to hedge certain exposures to market price fluctuations on
the anticipated operational sales of gas.
 
 As a
result of the approval of Phase III of the Western Kentucky storage expansion
project in the first quarter 2008, approximately 5.1 Bcf of gas stored
underground became available for sale, approximately 2.9 Bcf of which remained
unsold at June 30, 2008. We entered into derivatives to hedge the price exposure
related to the expected sale of this gas, which derivatives were designated as
cash flow hedges.
 
 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 pipeline expansion projects, of which approximately 1.3 Bcf
remained outstanding at June 30, 2008. The derivatives were not designated as
hedges and were marked to fair value through earnings resulting in a gain of
$4.1 million and $7.2 million for the three and six months ended June 30, 2008.
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 New
York Mercantile Exchange natural gas futures, would result in the recognition of
a $1.3 million gain in earnings. Conversely, a $1.00 decrease would result in
the recognition of a $1.3 million loss.
 
 With the
exception of the derivatives related to certain storage gas volumes related to
Phase II of the Western Kentucky Storage Expansion project and line pack gas
purchases referred to above, the derivatives related to the sale or purchase of
natural gas, cash for fuel reimbursement and debt issuance generally qualify for
cash flow hedge accounting under Statement of Financial Accounting Standards
(SFAS) No. 133 and are designated as such. The effective component of related
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 loss. The deferred gains and losses are
recognized in the Condensed Consolidated Statements of Income when the
anticipated transactions affect earnings. In situations where continued
reporting of a loss in accumulated other comprehensive income would result in
recognition of a future loss on the combination of the derivative and the hedged
transaction, SFAS No. 133 requires that the loss be immediately recognized in
earnings for the amount that is not expected to be recovered. We reclassified
losses of $1.7 million for the three and six months ended June 30, 2008, from
Accumulated other comprehensive loss to earnings related to amounts that are not
expected to be recovered in future periods from the combination of sales of gas
stored underground and the deferred losses associated with related
derivatives.
 
 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 projects, any gains and
losses on the related derivatives would be recognized in Net gain on disposal of
operating assets and related contracts. Any gains and losses on the derivatives
related to the line pack gas purchases would be recognized in Miscellaneous
other income, net.
 
 30
 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. 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, 2008, the amount of gas loaned out by
our subsidiaries was approximately 20.1 trillion British thermal units (TBtu)
and the amount considered an imbalance was approximately 4.2 TBtu. Assuming an
average market price during June 2008 of $12.54 per million British thermal
units (MMBtu), the market value of gas loaned out and considered an imbalance at
June 30, 2008, would have been approximately $304.8 million. As of December 31,
2007, the amount of gas loaned out by our subsidiaries was approximately 12.7
TBtu and the amount considered an imbalance was approximately 2.5 TBtu. Assuming
an average market price during December 2007 of $7.13 per MMBtu, the market
value of gas loaned out at December 31, 2007, would have been approximately
$108.2 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, 2008, our cash and cash
equivalents were invested primarily in mutual funds or treasury bills. 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 earnings or cash flows to be materially impacted by the effect of a
sudden change in market interest rates on our investment portfolio.
 
 
 
  31
  Item 4.  Controls and Procedures
 
 Disclosure
Controls and Procedures
 
 We
maintain a system of disclosure controls and procedures which is designed to
ensure that information required to be disclosed by us in reports that we file
or submit under the federal securities laws, including this report is recorded,
processed, summarized and reported on a timely basis. These disclosure controls
and procedures include controls and procedures designed to ensure that
information required to be disclosed by us under the federal securities laws is
accumulated and communicated to us on a timely basis to allow decisions
regarding required disclosure.
 
 Our
principal executive officer (CEO) and principal financial officer (CFO)
undertook an evaluation of our disclosure controls and procedures as of the end
of the period covered by this report. The CEO and CFO have concluded that our
controls and procedures were effective as of June 30, 2008.
 
 Changes
in Internal Control over Financial Reporting
 
 There
were no changes in our internal control over financial reporting that occurred
during the quarter ended June 30, 2008, that have materially affected or that
are reasonably likely to materially affect our internal control over financial
reporting.
 
 
  32
  PART
II – OTHER INFORMATION
 
 Item 1.  Legal Proceedings
 
 For a discussion of certain of our
current legal proceedings, please see Note 6 in Part 1 in Item 1 of this
report.
 
 
  33
  Item 6.  Exhibits
 
 
 
 Exhibit
                NumberDescription
 
 3.1
              
              Third
      Amended and Restated Agreement of Limited Partnership of Boardwalk
      Pipeline Partners, LP dated June 17, 2008 (Incorporated by reference to
      Exhibit 3.1 to Boardwalk Pipeline Partners, LP Current Report on Form 8-K
      filed on June 18, 2008).4.1
              
              Registration
      Rights Agreement dated June 17, 2008, by and between Boardwalk Pipeline
      Partners, LP and Boardwalk Pipelines Holding Corp. (Incorporated by
      reference to Exhibit 4.1 to Boardwalk Pipeline Partners, LP Current Report
      on Form 8-K filed on June 18, 2008).10.1
              
              Class
      B Unit Purchase Agreement dated April 24, 2008, by and between Boardwalk
      Pipeline Partners, LP and Boardwalk Pipelines Holding Corp. (Incorporated
      by reference to Exhibit 10.1 to Boardwalk Pipeline Partners, LP Current
      Report on Form 8-K filed on April 24, 2008).*10.2
              
              Separation
      Agreement and General Release between John C. Earley, Jr. and Gulf South
      Pipeline Company, LP, Gulf Crossing Pipeline Company LLC, Texas Gas
      Transmission, LLC, Boardwalk GP, LLC and Boardwalk Operating GP,
      LLC*31.1
              
              Certification
      of Rolf A. Gafvert, Chief Executive Officer, pursuant to Rule 13a-14(a)
      and Rule 15d-14(a).*31.2
              
              Certification
      of Jamie L. Buskill, Chief Financial Officer, pursuant to Rule 13a-14(a)
      and Rule 15d-14(a).*32.1
              
              Certification
      of Rolf A. Gafvert, Chief Executive Officer, pursuant to Section 906 of
      the Sarbanes-Oxley Act of 2002.*32.2
              
              Certification
      of Jamie L. Buskill, Chief Financial Officer, pursuant to Section 906 of
      the Sarbanes-Oxley Act of 2002.*
      Filed herewith
  34
  SIGNATURES
 
 Pursuant to the requirements of the
Securities Exchange Act of 1934, the Registrant has duly caused this report to
be signed on its behalf by the undersigned, thereunto duly
authorized.
 
 Boardwalk
      Pipeline Partners, LPBy:
      Boardwalk GP, LPits
      general partnerBy:
      Boardwalk GP, LLCits
      general partnerDated:
      July 29, 2008
              
              By:
              /s/
      Jamie L. BuskillJamie
      L. BuskillSenior
      Vice President, Chief Financial Officer and
  Treasurer