UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
 WASHINGTON,
D.C.  20549
  FORM
10-Q
  (Mark
One)
 xQUARTERLY REPORT PURSUANT
TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For
the quarterly period ended September 30, 2008
 
 OR
 
 oTRANSITION REPORT PURSUANT
TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For
the transition period from _______________ to _______________
 
 Commission file
      number:      01-32665BOARDWALK
      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
October 17, 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
 
 September
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 .......................................................................................................................................................................................................................................................31
  
 PART
I I - OTHER INFORMATION
  
  Item
1.  Legal
Proceedings .................................................................................................................................................................................................................................................................32
  Item
6.  Exhibits ....................................................................................................................................................................................................................................................................................33
  Signatures ............................................................................................................................................................................................................................................................................................34
  
   2
  PART
I – FINANCIAL INFORMATION
 
 Item
1.  Financial Statements
 
 BOARDWALK
PIPELINE PARTNERS, LP
 
 CONDENSED CONSOLIDATED BALANCE SHEETS
 (Millions)
 (Unaudited)
 
 September
      30,
              
              
              December
      31,ASSETS
              
              2008
              
              
              2007Current
      Assets:Cash
      and cash equivalents
              
              $
              22.1
              
              
              $
              317.3Receivables:Trade,
      net
              
              
              56.9
              
              
              
              60.7Other
              
              
              9.4
              
              
              
              12.7Gas
      Receivables:Transportation
      and exchange
              
              
              25.6
              
              
              
              12.5Storage
              
              
              -
              
              
              
              1.3Inventories
              
              
              17.9
              
              
              
              16.6Costs
      recoverable from customers
              
              
              5.8
              
              
              
              6.3Gas
      stored underground
              
              
              3.6
              
              
              
              16.3Prepaid
      expenses and other current assets
              
              
              22.3
              
              
              
              11.9Total
      current assets
              
              
              163.6
              
              
              
              455.6Property,
      Plant and Equipment:Natural
      gas transmission plant
              
              
              3,484.6
              
              
              
              2,392.5Other
      natural gas plant
              
              
              221.2
              
              
              
              224.03,705.8
              
              
              
              2,616.5Less—accumulated
      depreciation and amortization
              
              
              349.8
              
              
              
              262.53,356.0
              
              
              
              2,354.0Construction
      work in progress
              
              
              1,941.0
              
              
              
              951.4Property,
      plant and equipment, net
              
              
              5,297.0
              
              
              
              3,305.4Other
      Assets:Goodwill
              
              
              163.5
              
              
              
              163.5Gas
      stored underground
              
              
              174.6
              
              
              
              172.4Costs
      recoverable from customers
              
              
              15.6
              
              
              
              15.9Other
              
              
              57.3
              
              
              
              44.5Total
      other assets
              
              
              411.0
              
              
              
              396.3Total
      Assets
              
              $
              5,871.6
              
              
              $
              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)
 
 September
      30,
              
              
              December
      31,LIABILITIES
      AND PARTNERS’ CAPITAL
              
              2008
              
              
              2007Current
      Liabilities:Payables:Trade
              
              $
              306.8
              
              
              $
              190.6Affiliates
              
              
              2.0
              
              
              
              1.3Other
              
              
              7.0
              
              
              
              5.1Gas
      Payables:Transportation
      and exchange
              
              
              13.0
              
              
              
              17.8Storage
              
              
              54.7
              
              
              
              35.3Accrued
      taxes, other
              
              
              69.8
              
              
              
              20.2Accrued
      interest
              
              
              30.5
              
              
              
              30.8Accrued
      payroll and employee benefits
              
              
              18.9
              
              
              
              22.3Construction
      retainage
              
              
              55.7
              
              
              
              32.2Deferred
      income
              
              
              2.2
              
              
              
              7.2Other
      current liabilities
              
              
              34.0
              
              
              
              26.5Total
      current liabilities
              
              
              594.6
              
              
              
              389.3Long
      –Term Debt
              
              
              2,352.8
              
              
              
              1,847.9Other
      Liabilities and Deferred Credits:Pension
      and postretirement benefits
              
              
              15.3
              
              
              
              17.2Asset
      retirement obligation
              
              
              16.7
              
              
              
              16.1Provision
      for other asset retirement
              
              
              44.2
              
              
              
              42.4Other
              
              
              63.5
              
              
              
              41.4Total
      other liabilities and deferred credits
              
              
              139.7
              
              
              
              117.1Commitments
      and ContingenciesPartners’
      Capital:Common
      units – 100.7 million units and 90.7 million units issued and outstanding
      as of  September 30, 2008 and December 31, 2007
              
              
              1,741.6
              
              
              
              1,473.9Class
      B units – 22.9 million units issued and outstanding as of September 30,
      2008
              
              
              692.9
              
              
              
              -Subordinated
      units – 33.1 million units issued and outstanding as of September 30, 2008
      and December 31, 2007
              
              
              300.1
              
              
              
              291.7General
      partner
              
              
              53.1
              
              
              
              33.2Accumulated
      other comprehensive (loss) income
              
              
              (3.2
              )
              
              
              4.2Total
      partners’ capital
              
              
              2,784.5
              
              
              
              1,803.0Total
      Liabilities and Partners’ Capital
              
              $
              5,871.6
              
              
              $
              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
              
              
              Nine
      Months EndedSeptember
      30,
              
              
              September
      30,2008
              
              
              2007
              
              
              2008
              
              
              2007Operating
      Revenues:Gas
      transportation
              
              $
              172.8
              
              
              $
              111.6
              
              
              $
              509.5
              
              
              $
              379.5Parking
      and lending
              
              
              3.0
              
              
              
              6.8
              
              
              
              12.7
              
              
              
              38.0Gas
      storage
              
              
              13.7
              
              
              
              10.3
              
              
              
              38.0
              
              
              
              28.5Other
              
              
              2.1
              
              
              
              6.1
              
              
              
              19.0
              
              
              
              27.4Total
      operating revenues
              
              
              191.6
              
              
              
              134.8
              
              
              
              579.2
              
              
              
              473.4Operating
      Costs and Expenses:Operation
      and maintenance
              
              
              68.4
              
              
              
              45.9
              
              
              
              164.1
              
              
              
              128.4Administrative
      and general
              
              
              25.8
              
              
              
              22.1
              
              
              
              78.3
              
              
              
              70.0Depreciation
      and amortization
              
              
              33.6
              
              
              
              20.5
              
              
              
              91.4
              
              
              
              60.6Contract
      settlement gain
              
              
              -
              
              
              
              -
              
              
              
              (11.2
              )
              
              
              -Asset
      impairment
              
              
              -
              
              
              
              -
              
              
              
              1.4
              
              
              
              14.7Net
      gain on disposal of operating assets and relatedcontracts
              
              
              (36.1
              )
              
              
              (8.8
              )
              
              
              (50.1
              )
              
              
              (7.2
              )Taxes
      other than income taxes
              
              
              11.1
              
              
              
              6.5
              
              
              
              34.0
              
              
              
              21.7Total
      operating costs and expenses
              
              
              102.8
              
              
              
              86.2
              
              
              
              307.9
              
              
              
              288.2Operating
      income
              
              
              88.8
              
              
              
              48.6
              
              
              
              271.3
              
              
              
              185.2Other
      Deductions (Income):Interest
      expense
              
              
              9.3
              
              
              
              14.8
              
              
              
              46.0
              
              
              
              46.1Interest
      income
              
              
              (0.7
              )
              
              
              (5.8
              )
              
              
              (2.1
              )
              
              
              (16.3
              )Miscellaneous
      other deductions (income), net
              
              
              6.3
              
              
              
              (0.5
              )
              
              
              0.2
              
              
              
              (0.7
              )Total
      other deductions
              
              
              14.9
              
              
              
              8.5
              
              
              
              44.1
              
              
              
              29.1Income
      before income taxes
              
              
              73.9
              
              
              
              40.1
              
              
              
              227.2
              
              
              
              156.1Income
      taxes
              
              
              0.3
              
              
              
              0.1
              
              
              
              0.8
              
              
              
              0.5Net
      income
              
              $
              73.6
              
              
              $
              40.0
              
              
              $
              226.4
              
              
              $
              155.6
 
 Net
      income
              
              $
              73.6
              
              
              $
              40.0
              
              
              $
              226.4
              
              
              $
              155.6Less
      general partner’s interest in Net income
              
              
              3.5
              
              
              
              1.5
              
              
              
              9.7
              
              
              
              4.5Limited
      partners’ interest in Net income
              
              $
              70.1
              
              
              $
              38.5
              
              
              $
              216.7
              
              
              $
              151.1Basic
      and diluted net income per limited partner unit:Common
      units
              
              $
              0.47
              
              
              $
              0.35
              
              
              $
              1.58
              
              
              $
              1.32Class
      B units
              
              $
              0.30
              
              
              $
              -
              
              
              $
              0.30
              
              
              $
              -Subordinated
      units
              
              $
              0.47
              
              
              $
              0.30
              
              
              $
              1.58
              
              
              $
              1.32Cash
      distribution per unit to common and subordinated units (a)
              
              $
              0.47
              
              
              $
              0.44
              
              
              $
              1.395
              
              
              $
              1.285Weighted-average
      number of limited partner units outstanding:Common
      units
              
              
              100.7
              
              
              
              83.2
              
              
              
              94.6
              
              
              
              80.8Class
      B units (a)
              
              
              22.9
              
              
              
              -
              
              
              
              22.9
              
              
              
              -Subordinated
      units
              
              
              33.1
              
              
              
              33.1
              
              
              
              33.1
              
              
              
              33.1(a) Number of Class B units shown is
      weighted from July 1, 2008, which is the date they became eligible to
      participate in earnings.
 
 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
      theNine
      Months EndedSeptember
      30,2008
              
              
              2007OPERATING
      ACTIVITIES:Net
      income
              
              $
              226.4
              
              
              $
              155.6Adjustments
      to reconcile to cash provided by operations:Depreciation
      and amortization
              
              
              91.4
              
              
              
              60.6Amortization
      of deferred costs
              
              
              6.9
              
              
              
              1.2Amortization
      of acquired executory contracts
              
              
              (0.2
              )
              
              
              (0.9
              )Asset
      impairment
              
              
              1.4
              
              
              
              14.7Gain
      on disposal of operating assets and related contracts
              
              
              (50.1
              )
              
              
              (7.2
              )Changes
      in operating assets and liabilities:Trade
      and other receivables
              
              
              2.4
              
              
              
              16.4Gas
      receivables and storage assets
              
              
              (4.2
              )
              
              
              (2.2
              )Costs
      recoverable from customers
              
              
              0.6
              
              
              
              4.4Other
      assets
              
              
              (40.7
              )
              
              
              (14.1
              )Trade
      and other payables
              
              
              6.7
              
              
              
              (15.3
              )Other
      payables, affiliates
              
              
              0.7
              
              
              
              -Gas
      payables
              
              
              22.9
              
              
              
              (11.1
              )Accrued
      liabilities
              
              
              14.9
              
              
              
              11.3Other
      liabilities
              
              
              (3.0
              )
              
              
              15.3Net
      cash provided by operating activities
              
              
              276.1
              
              
              
              228.7INVESTING
      ACTIVITIES:Capital
      expenditures
              
              
              (1,905.6
              )
              
              
              (688.2
              )Proceeds
      from sale of operating assets, net
              
              
              63.0
              
              
              
              5.0Proceeds
      from insurance reimbursements and other recoveries
              
              
              4.7
              
              
              
              1.7Advances
      to affiliates, net
              
              
              0.9
              
              
              
              0.2Purchase
      of short-term investments
              
              
              -
              
              
              
              (540.0
              )Net
      cash used in investing activities
              
              
              (1,837.0
              )
              
              
              (1,221.3
              )FINANCING
      ACTIVITIES:Proceeds
      from long-term debt, net of issuance costs
              
              
              247.2
              
              
              
              495.3Proceeds
      from borrowings on revolving credit agreement
              
              
              778.0
              
              
              
              -Repayment
      of borrowings on revolving credit agreement
              
              
              (522.0
              )
              
              
              -Distributions
              
              
              (186.3
              )
              
              
              (150.5
              )Proceeds
      from sale of common units, net of related transaction
costs
              
              
              243.6
              
              
              
              287.9Proceeds
      from sale of class B units
              
              
              686.0
              
              
              
              -Capital
      contribution from general partner
              
              
              19.2
              
              
              
              6.0Net
      cash provided by financing activities
              
              
              1,265.7
              
              
              
              638.7Decrease
      in cash and cash equivalents
              
              
              (295.2
              )
              
              
              (353.9
              )Cash
      and cash equivalents at beginning of period
              
              
              317.3
              
              
              
              399.1Cash
      and cash equivalents at end of period
              
              $
              22.1
              
              
              $
              45.2
 
 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
              
              
              106.6
              
              
              
              -
              
              
              
              44.5
              
              
              
              4.5
              
              
              
              -
              
              
              
              155.6Distributions
      paid
              
              
              (103.6
              )
              
              
              -
              
              
              
              (42.5
              )
              
              
              (4.4
              )
              
              
              -
              
              
              
              (150.5
              )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
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (12.4
              )
              
              
              (12.4
              )Balance
      September 30, 2007
              
              $
              1,232.7
              
              
              
              -
              
              
              $
              287.5
              
              
              $
              28.2
              
              
              $
              10.7
              
              
              $
              1,559.1Balance
      January 1, 2008
              
              $
              1,473.9
              
              
              
              -
              
              
              $
              291.7
              
              
              $
              33.2
              
              
              $
              4.2
              
              
              $
              1,803.0Add
      (deduct):Net
      income
              
              
              155.2
              
              
              $
              6.9
              
              
              
              54.6
              
              
              
              9.7
              
              
              
              -
              
              
              
              226.4Distributions
      paid
              
              
              (131.1
              )
              
              
              -
              
              
              
              (46.2
              )
              
              
              (9.0
              )
              
              
              -
              
              
              
              (186.3
              )Sale
      of common units, net of
                related
      transaction costs
                (10.0
      million commonunits)
              
              
              243.6
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              243.6Sale
      of class B units
                (22.9
      million class B units)
              
              
              -
              
              
              
              686.0
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              686.0Capital
      contribution from
                general
      partner
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              19.2
              
              
              
              -
              
              
              
              19.2Other
      comprehensive loss
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (7.4
              )
              
              
              (7.4
              )Balance
      September 30, 2008
              
              $
              1,741.6
              
              
              $
              692.9
              
              
              $
              300.1
              
              
              $
              53.1
              
              
              $
              (3.2
              )
              
              $
              2,784.5
 
 
 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
                September
      30,
              
              
              For
      the
                Nine
      Months Ended
                September
      30,2008
              
              
              2007
              
              
              2008
              
              
              2007Net
      income
              
              $
              73.6
              
              
              $
              40.0
              
              
              $
              226.4
              
              
              $
              155.6Other
      comprehensive (loss) income:Gain
      (loss) on cash flow hedges
              
              
              21.5
              
              
              
              (5.8
              )
              
              
              (25.9
              )
              
              
              (4.9
              )Reclassification
      adjustment transferredto
      Net income from cash flow hedges
              
              
              7.4
              
              
              
              (1.1
              )
              
              
              25.1
              
              
              
              (5.5
              )Pension
      and other postretirement benefits costs
              
              
              (2.2
              )
              
              
              (1.8
              )
              
              
              (6.6
              )
              
              
              (2.0
              )Total
      comprehensive income
              
              $
              100.3
              
              
              $
              31.3
              
              
              $
              219.0
              
              
              $
              143.2
 
 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), 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 September 30, 2008 and December 31, 2007, and the results of operations and
comprehensive income for the three and nine months ended September 30, 2008 and
2007, and changes in cash flow and changes in partners’ capital for the nine
months ended September 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
September 30, 2008 and December 31, 2007, Gulf South held 37.1 trillion British
thermal units (TBtu) and 52.0 TBtu of gas owned by shippers. Gulf South loaned
2.8 and 0.2 TBtu of gas to shippers as of September 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 $54.7
million and $35.3 million at September 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 September 30, 2008 and December 31, 2007, approximately
$3.6 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. All of the gas was sold in
the second and third quarters of 2008, and the related derivatives were settled,
resulting in gains of $19.7 million and $34.4 million for the three and nine
months ended September 30, 2008, which were reported in Net gain on disposal of
operating assets and related contracts on the Condensed Consolidated Statements
of Income. In the third quarter 2007, approximately 0.9 Bcf of gas related to
Phase II of the Western Kentucky Storage Expansion project was sold and the
related derivatives were settled, resulting in a gain of $4.4
million.
 
 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. The derivatives were
not designated as hedges and were marked to fair value through earnings
resulting in a loss of $6.3 million and a gain of $0.9 million in Miscellaneous
other income, net on the Condensed Consolidated Statements of Income for the
three and nine months ended September 30, 2008, and resulting in a loss of $0.4
million and $1.1 million for the corresponding periods in 2007. All of the line
pack derivatives were settled as of September 30, 2008.
 
 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.
 
 The
derivatives related to the sale of natural gas and cash for fuel reimbursement
generally qualify for cash flow hedge accounting under SFAS No. 133 and are
designated as such. The 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 had no losses for the three months
ended September 30, 2008, and reclassified losses of $1.7 million for the nine
months ended September 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 were 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 were 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 nine months ended September 30, 2008. Ineffectiveness
increased Net income by $0.5 million and $0.9 million for the three and nine
months ended September 30, 2007. The Partnership did not discontinue any cash
flow hedges during the three and nine month periods ended September 30, 2008 and
2007.
 
 
 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 for the nine months ending September 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.
 
 The fair
values of derivatives existing as of September 30, 2008, were included in the
following captions in the Condensed Consolidated Balance Sheets (in
millions):
 
 Total
      at
                September
      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
              
              $
              4.2
              
              
              
              -
              
              
              $
              4.2
              
              
              
              -Other
      assets
              
              
              1.7
              
              
              
              -
              
              
              
              1.7
              
              
              
              -Total
      assets
              
              $
              5.9
              
              
              
              -
              
              
              $
              5.9
              
              
              
              -Liabilities:Other
      current liabilities
              
              $
              0.2
              
              
              
              -
              
              
              $
              0.2
              
              
              
              -Other
      non-current liabilities
              
              
              0.1
              
              
              
              -
              
              
              
              0.1
              
              
              
              -Total
      liabilities
              
              $
              0.3
              
              
              
              -
              
              
              $
              0.3
              
              
              
              -
 
 11
 
 SFAS
No. 159, The Fair Value Option for Financial Assets and Financial
Liabilities
 
 Beginning in 2008, the Partnership has
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 nine month period
ended September 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 reporting 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.
 
 B.  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.
 
 C.  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 the remaining cases if Gulf South believes
it is appropriate to do so.For the nine-month period ended September 30, 2008, the Partnership
received $4.1 million in insurance proceeds related to previously incurred
litigation and remediation costs, which were recorded as a reduction to
Operation and maintenance expense.
 
 12
  Other
Legal Matters
 
 The
Partnership's subsidiaries are parties to various other legal actions arising in
the normal course of business. Management believes the disposition of all known
outstanding legal actions will not have a material adverse impact on the
Partnership's financial condition, results of operations or cash
flows.
 
 D.  Regulatory
and Rate Matters
 
 Expansion
Capital Projects
 
 The
Partnership has been engaged in several pipeline expansion projects as described
below:
 
 Southeast
Expansion.  The pipeline and two compressor stations related to
this project were placed in service during 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 will expand the project through
the addition of compression facilities to meet commitments of 1.8 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 all of the operational capacity (with a weighted-average term of 9.2
years, including a capacity lease agreement with Gulf Crossing discussed below).
Through September 30, 2008, the Partnership spent $635.5 million related to this
project.
 
 Gulf Crossing Project.The
Partnership is constructing a new interstate pipeline that begins near Sherman,
Texas and will 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 incremental compression
facilities.  Additionally, Gulf Crossing has entered into: (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 Partnership’s recently completed 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, both of
which have been approved by the FERC. Customers have contracted at fixed rates
for all of the operational 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 compression to be fully in service in
2010. Through September 30, 2008, the Partnership spent $1.0 billion 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
consist of approximately 165 miles of 36-inch pipeline. The Greenville Lateral
will originate at the Texas Gas mainline near Greenville, Mississippi and
proceed east to the Kosciusko, Mississippi area and consist 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 66 miles of the Fayetteville Lateral to be in service during the
fourth quarter 2008 and the remainder of the pipeline related to the
Fayetteville and Greenville Laterals to be in service during the first quarter
2009. In September 2008, the Partnership made additional filings with FERC
regarding the new compression required to increase the peak-day transmission
capacity, which is expected to be in service during 2010. Through September 30,
2008, the Partnership spent $449.6 million related to the Fayetteville and
Greenville Laterals.
 
 13
 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 September 30, 2008, the Partnership spent $41.0
million related to this project.
 
 E.  Environmental
and Safety Matters
 
 The
operating subsidiaries are subject to federal, state, and local environmental
laws and regulations in connection with the operation and remediation of various
operating sites. The Partnership accrues for environmental expenses resulting
from existing conditions that relate to past operations when the 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.
 
 As
of September 30, 2008 and December 31, 2007, the Partnership had accrued
approximately $15.4 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 September 30, 2008 and December 31, 2007, approximately
$2.7 million was recorded in Other current liabilities and approximately $12.7
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.
Compliance for this standard is anticipated to occur between 2013 and 2016. The
Partnership is currently evaluating its affected facilities to determine the
cost necessary to become compliant with this standard.
 
 The Partnership considers
environmental assessment, remediation costs and costs associated with compliance
with environmental standards to be recoverable through base rates, as they are
prudent costs incurred in the ordinary course of business and, therefore, no
regulatory asset has been recorded to defer these costs. The actual costs
incurred will depend on the actual amount and extent of contamination
discovered, the final cleanup standards mandated by the EPA or other
governmental authorities and other factors.
 
 14
 F.  Commitments
 
 The Partnership’s future capital
commitments as of September 30, 2008, for contracts already authorized are
expected to approximate the following amounts (in millions):
 
 Less
      than 1 year
              
              $
              271.91-3
      years
              
              
              22.64-5
      years
              
              
              -More
      than 5 years
              
              
              -Total
              
              $
              294.5
  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
 
 For the
nine months ended September 30, 2008 and 2007, the Partnership entered into the
following debt issuances (in millions, except interest rate
percentage):
 
 Date
      of Issuance
              
              Issuing
      Subsidiary
              
              Amount
                of
                Issuance
              
              
              Purchaser
      Discounts
                and
                Expenses
              
              
              Net
                Proceeds
              
              
              Interest
      Rate
              
              Maturity
      Date
              
              Interest
      PayableMarch
      2008
              
              Texas
      Gas
              
              $
              250.0
              
              
              $
              2.8
              
              
              $
              247.2
              
              
              
              5.50
              %
              April
      1, 2013
              
              April
      1 and  October 1August
      2007
              
              Gulf
      South
              
              
              225.0
              
              
              
              2.0
              
              
              
              223.0
              
              
              
              5.75
              %
              August
      15, 2012
              
              February
      15 and August 15August
      2007
              
              Gulf
      South
              
              
              275.0
              
              
              
              2.7
              
              
              
              272.3
              
              
              
              6.30
              %
              August
      15, 2017
              
              February
      15 and August 15
 
 The
notes are redeemable, in whole or in part, at the Partnership’s option at
any time, at a redemption price equal to the greater of 100% of the principal
amount of the notes to be redeemed or a “make whole” redemption price based on
the remaining scheduled payments of principal and interest discounted to the
date of redemption at a Treasury rate plus 50 basis points in the case of the
Texas Gas notes, 20 basis points in the case of the Gulf South 2012 notes, or 25
basis points in the case of the Gulf South 2017 notes, plus accrued and unpaid
interest, if any. Other customary covenants apply, including those
concerning events of default.
  As of September 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
 
 The
Partnership maintains a revolving credit facility which has aggregate lending
commitments of $1.0 billion. A financial institution which has a $50.0 million
commitment under the revolving credit facility filed for bankruptcy protection
in the third quarter 2008 and has not funded its portion of the Partnership’s
borrowing requests since that time. Borrowings outstanding under the credit
facility as of September 30, 2008, were $256.0 million with a weighted-average
borrowing rate of 3.00%. As of September 30, 2008, the Partnership and its
subsidiaries were in compliance with all covenant requirements under the credit
agreement. No funds were drawn under the Partnership’s revolving credit facility
at December 31, 2007. Subsequent to September 30, 2008, the Partnership borrowed
all of the remaining unfunded commitments under the credit facility (excluding
the unfunded commitment of the bankrupt lender noted above), which increased
borrowings to $958.0 million.
 
 Capitalized
Interest and Allowance for Funds Used During Construction
  During the three and nine months
ended September 30, 2008, the Partnership capitalized interest of $21.9 million
and $45.3 million. During the three and nine months ended September 30, 2007,
the Partnership capitalized interest of $8.2 million and $14.5 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 and $0.2 million
for the three and nine months ended September 30, 2008, and $1.3 million and
$2.4 million for the three and nine months ended September 30,
2007.
 
 Offering
of Common Units
 
 For the
nine months ended September 30, 2008 and 2007, the Partnership completed the
following equity offerings which funds were used to finance a portion of the
Partnership’s expansion projects or to repay amounts borrowed under the
revolving credit facility (in millions, except the offering price):
 
 Month
      of Offering
              
              Number
                of
      Common Units
              
              
              Offering
      Price
              
              
              Underwriting
      Discounts and Expenses
              
              
              Net
      Proceeds
                (including
      General Partner Contribution)
              
              
              Common
      Units Outstanding
                After
      Offering
              
              
              Common
      Units Held by the Public
                After
      OfferingJune
      2008
              
              
              10.0
              
              
              $
              25.30
              
              
              $
              9.4
              
              
              $
              248.8
              
              
              
              100.7
              
              
              
              47.4March
      2007
              
              
              8.0
              
              
              
              36.50
              
              
              
              4.2
              
              
              
              293.9
              
              
              
              83.2
              
              
              
              29.9
 
 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 are
convertible into common units by the holder on a one-for-one basis at any time
after June 30, 2013.
 
 The class
B units 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 do not participate in quarterly distributions above $0.30 per
unit.
 
 The class
B units began sharing in income allocations beginning on July 1, 2008, and will
begin participating in distributions that will be made beginning with the fourth
quarter 2008. Income of $6.9 million was allocated to the class B capital
account for the three and nine months ended September 30, 2008.
 
 16
 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.
 
 
 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 the distribution that will be made in the fourth quarter 2008. The
      class B units do 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 nine month periods
ended September 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
                September
      30,
              
              
              For
      the
                Nine
      Months Ended
                September
      30,2008
              
              
              2007
              
              
              2008
              
              
              2007Limited
      partners' interest in net income
              
              $
              70.1
              
              
              $
              38.5
              
              
              $
              216.7
              
              
              $
              151.1Less
      assumed allocation to IDRs
              
              
              0.1
              
              
              
              (0.7
              )
              
              
              7.9
              
              
              
              0.7Net
      income available to limited partners
              
              
              70.0
              
              
              
              39.2
              
              
              
              208.8
              
              
              
              150.4Less
      assumed allocation to class B units
              
              
              6.9
              
              
              
              -
              
              
              
              6.9
              
              
              
              -Less
      assumed allocation to subordinated units
              
              
              15.6
              
              
              
              10.1
              
              
              
              52.3
              
              
              
              43.7Net
      income available to common units
              
              $
              47.5
              
              
              $
              29.1
              
              
              $
              149.6
              
              
              $
              106.7Weighted-average
      common units
              
              
              100.7
              
              
              
              83.2
              
              
              
              94.6
              
              
              
              80.8Weighted-average
      class B units (a)
              
              
              22.9
              
              
              
              -
              
              
              
              22.9
              
              
              
              -Weighted-average
      subordinated units
              
              
              33.1
              
              
              
              33.1
              
              
              
              33.1
              
              
              
              33.1Net
      income per limited partner unit –common
      units
              
              $
              0.47
              
              
              $
              0.35
              
              
              $
              1.58
              
              
              $
              1.32Net
      income per limited partner unit –class
      B units
              
              $
              0.30
              
              
              $
              -
              
              
              $
              0.30
              
              
              $
              -Net
      income per limited partner unit –subordinated
      units
              
              $
              0.47
              
              
              $
              0.30
              
              
              $
              1.58
              
              
              $
              1.32
  (a)
              Number
      of class B units shown is weighted from July 1,
  2008.
 
 As discussed in Note 7, the class B
units were not eligible to 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 prior to
July 1, 2008.
 
 In the nine month periods ended
September 30, 2008 and 2007, the Partnership declared quarterly distributions
per unit to eligible 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)August
      11, 2008
              
              $
              0.470
              
              
              $
              62.8
              
              
              $
              3.4May
      12, 2008
              
              
              0.465
              
              
              
              57.6
              
              
              
              2.9February
      25, 2008
              
              
              0.460
              
              
              
              56.9
              
              
              
              2.7August
      13, 2007
              
              
              0.440
              
              
              
              51.1
              
              
              
              1.7May
      14, 2007
              
              
              0.430
              
              
              
              50.0
              
              
              
              1.5February
      27, 2007
              
              
              0.415
              
              
              
              45.0
              
              
              
              1.2
 
 In
October 2008, the Partnership declared a quarterly cash distribution to
unitholders of record of $0.475 per unit. The subordinated units are convertible
to common units on a one-to-one basis when certain distribution requirements, as
defined in the partnership agreement, have been met. These requirements will
have been met coincident with payment of the quarterly distribution declared in
October 2008, to be paid in the fourth quarter 2008. The subordinated units will
convert following this quarterly distribution to unitholders.
 
 18
 
 Note
9:  Disposition of Coal Reserves
 
 In August
2008, the Partnership completed the sale of its investment in land and coal
reserves along the Ohio River in northern Kentucky and southern Indiana for
$16.5 million. These assets had no book value at the time of the sale. As a
result, the Partnership recorded a gain of $16.5 million related to the sale
which was reported in Net gain on disposal of operating assets and related
contracts in the Condensed Consolidated Statements of Income.
 
 
 Note
10: 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 two compressor stations related to the
Southeast Expansion project. As a result, approximately $1.1 billion was
transferred from Construction work in progress to Property, plant and equipment
during 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
assets.
 
 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
11: 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 September 30,
2008, the amount of gas loaned out by the Partnership’s subsidiaries was
approximately 7.6 TBtu and the amount considered an imbalance was approximately
4.2 TBtu. Assuming an average market price during September 2008 of $7.54 per
million British thermal units, the market value of gas loaned out and considered
an imbalance at September 30, 2008, would have been approximately $88.6 million.
If any significant customer should have credit or financial problems resulting
in a delay or failure to repay the gas they owe the Partnership, it could have a
material adverse effect on the Partnership’s financial condition, results of
operations and cash flows.
 
 
 Note
12:  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 nine months ended September 30, 2008 and 2007, were the
following (in millions):
 
 Retirement
      Plans
              
              
              PBOPFor
      the
                Three
      Months Ended
                September
      30,
              
              
              For
      the
                Three
      Months Ended
                September
      30,2008
              
              
              2007
              
              
              2008
              
              
              2007Service
      cost
              
              $
              0.9
              
              
              $
              0.9
              
              
              $
              0.1
              
              
              $
              0.1Interest
      cost
              
              
              1.6
              
              
              
              1.5
              
              
              
              0.8
              
              
              
              0.8Expected
      return on plan assets
              
              
              (1.7
              )
              
              
              (1.7
              )
              
              
              (1.3
              )
              
              
              (1.2
              )Amortization
      of prior service credit
              
              
              -
              
              
              
              -
              
              
              
              (1.9
              )
              
              
              (1.9
              )Amortization
      of unrecognized net loss
              
              
              -
              
              
              
              0.1
              
              
              
              -
              
              
              
              0.2Settlement
      charge
              
              
              0.1
              
              
              
              0.4
              
              
              
              -
              
              
              
              -Regulatory
      asset (increase) decrease
              
              
              -
              
              
              
              (0.4
              )
              
              
              1.4
              
              
              
              1.4Net
      periodic expense
              
              $
              0.9
              
              
              $
              0.8
              
              
              $
              (0.9
              )
              
              $
              (0.6
              )
 
 
 Retirement
      Plans
              
              
              PBOPFor
      the
                Nine
      Months Ended
                September
      30,
              
              
              For
      the
                Nine
      Months Ended
                September
      30,2008
              
              
              2007
              
              
              2008
              
              
              2007Service
      cost
              
              $
              2.7
              
              
              $
              2.8
              
              
              $
              0.4
              
              
              $
              0.4Interest
      cost
              
              
              4.8
              
              
              
              4.8
              
              
              
              2.4
              
              
              
              2.5Expected
      return on plan assets
              
              
              (5.0
              )
              
              
              (5.3
              )
              
              
              (3.7
              )
              
              
              (3.6
              )Amortization
      of prior service credit
              
              
              -
              
              
              
              -
              
              
              
              (5.8
              )
              
              
              (5.8
              )Amortization
      of unrecognized net loss
              
              
              -
              
              
              
              0.2
              
              
              
              -
              
              
              
              0.5Settlement
      charge
              
              
              0.1
              
              
              
              4.2
              
              
              
              -
              
              
              
              -Regulatory
      asset (increase) decrease
              
              
              -
              
              
              
              (0.4
              )
              
              
              4.1
              
              
              
              4.1Net
      periodic expense
              
              $
              2.6
              
              
              $
              6.3
              
              
              $
              (2.6
              )
              
              $
              (1.9
              )
 
 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
$1.6 million and $4.7 million for the three and nine months ended September 30,
2008, and $1.2 million and $3.9 million for the three and nine months ended
September 30, 2007.
 
 
 Note
13:  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 $3.1 million and $10.6 million for the three and nine months ended
September 30, 2008, and $2.7 million and $9.3 million for the three and nine
months ended September 30, 2007, to the Partnership based on the actual time
spent by Loews personnel performing these services, plus related
expenses.
 
 20
 Distributions paid related to common
and subordinated units held by BPHC and the 2% general partner interest and IDRs
held by Boardwalk GP were $129.5 million and $115.4 million during the nine
months ended September 30, 2008 and 2007.
 
 
 Note
14:  Accumulated Other Comprehensive (Loss) Income
 
 The following table shows the
components of Accumulated other comprehensive (loss) income, net of tax which is
included in Partners’ Capital on the Condensed Consolidated Balance Sheets (in
millions):
 
 As
      of
                September
      30,
              
              As
      of
                December
      31,2008
              
              2007Loss
      on cash flow hedges
              
              $
              (9.8
              )
              
              $
              (8.9
              )Deferred
      components of net periodic benefit cost
              
              
              6.6
              
              
              
              13.1Total
      Accumulated other comprehensive (loss) income
              
              $
              (3.2
              )
              
              $
              4.2
 
 
 Note
15:  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 September 30, 2008.
 
 
 Note
16:  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 Emerging Issues Task Force (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), 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 transportation and storage services. 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 affect our
transportation revenues, and spreads in natural gas prices across time (for
example summer to winter), which primarily affect 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 for
the majority of 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 September 30, 2008 and
2007
 
 Ournet
income for the third quarter 2008 increased $33.6 million, or 84%, 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 the disposition of coal reserves and gas sales associated
with our storage expansion projects. The favorable drivers were partly offset by
lower PAL revenues due to unfavorable natural gas price spreads, higher fuel
costs and higher depreciation and property tax expense due to an increase in our
asset base from expansion.
 
 Operating
revenues increased $56.8 million, or 42%, to $191.6 million for the third
quarter 2008, compared to $134.8 million for the 2007 period. Gas transportation
revenues increased $37.7 million, excluding fuel, due mainly to our expansion
projects. Our fuel revenues increased $19.5 million due to expansion-related
throughput and an increase in the price of natural gas. Gas storage revenues
increased $3.4 million related to an increase in storage capacity associated
with our Western Kentucky Storage Expansion project. These increases were
partially offset by a $3.8 million decrease in PAL revenues due to unfavorable
natural gas price spreads.
 
 Operating
costs and expenses increased $16.6 million, or 19%, to $102.8 million for the
third quarter 2008, compared to $86.2 million for the 2007 period, primarily
resulting from a $20.5 million increase in fuel costs from providing service on
our expansion projects and higher natural gas prices. Depreciation and other
taxes, primarily comprised of property taxes, increased $17.7 million due to an
increase in our asset base from expansion and administrative and general
expenses increased $3.7 million primarily due to employee related expenses,
various corporate services and a bad debt recovery that favorably impacted the
2007 period. The increased expenses were partly offset by a $16.5 million gain
on the disposition of coal reserves and a $15.3 million gain from the sale of
gas related to our Western Kentucky Storage Expansion project. The 2007 period
was also favorably impacted by $4.6 million from insurance recoveries related to
the 2005 hurricanes.
 
 Total
other deductions increased by $6.4 million, or 75%, to $14.9 million for the
third quarter 2008, compared to $8.5 million for the 2007 period. The increase
was due to $5.9 million of losses from the mark-to-market effect of derivatives
associated with the purchase of line pack for our expansion projects and
decreased interest income of $5.1 million due to lower average cash balances
available for investment. These amounts were partly offset by a $5.5 million
decrease in interest expense related to higher capitalized interest associated
with our expansion projects.
 
 
 Results
of Operations for the Nine Months Ended September 30, 2008 and 2007
 
 Ournet
income for the first nine months of 2008 increased $70.8 million, or 46%, 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 associated with our expansion projects,
disposition of coal reserves and 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 tax expense due
to an increase in our asset base from expansion. The 2007 period was unfavorably
impacted by a $14.7 million impairment charge.
 
 23
 Operating
revenues for the nine months ended September 30, 2008, increased $105.8 million,
or 22%, to $579.2 million, compared to $473.4 million for the nine months ended
September 30, 2007. Gas transportation revenues, excluding fuel, increased $83.0
million, $76.0 million of which was related to our expansion projects and the
remainder to higher interruptible services. Fuel revenues increased $38.6
million due to expansion-related throughput and higher natural gas prices. Gas
storage revenues increased $9.5 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 $25.3 million due to
unfavorable natural gas price spreads.
 
 Operating
costs and expenses for the nine months ended September 30, 2008, increased $19.7
million, or 7%, to $307.9 million, compared to $288.2 million for the nine
months ended September 30, 2007. The primary drivers were increased depreciation
and other taxes, comprised primarily of property taxes, of $43.1 million
associated with an increase in our asset base due to expansion and increased
fuel costs of $41.5 million from providing service on our expansion projects and
higher natural gas prices. Administrative and general expenses increased $8.3
million due to increased outside services mainly due to legal and regulatory
matters and various corporate services, higher property insurance from an
increase in rates and asset base, an increase in information technology-related
expenses from infrastructure improvements and growth and a bad debt recovery
that favorably impacted 2007. These increases were offset by a $30.8 million
gain on the sale of gas related to our Western Kentucky Storage Expansion
project, a $16.5 million gain on the disposition of coal reserves, 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 $15.0 million, or 52%, to $44.1 million for the
nine months ended September 30, 2008, compared to $29.1 million for the 2007
period primarily as a result of decreased interest income due to lower average
cash balances available for investment.
 
 
 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 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
      Total Cost
              
              
              Cash
      Invested through
                September
      30, 2008Southeast
      Expansion
              
              $
              775
              
              
              $
              635.5Gulf
      Crossing Project
              
              
              1,800
              
              
              
              1,002.0Fayetteville
      and Greenville Laterals
              
              
              1,290
              
              
              
              449.6Total
              
              $
              3,865
              
              
              $
              2,087.1
 
 Based
upon our current cost estimates, we expect to incur expansion project capital
expenditures of approximately $0.9 billion for the remainder of 2008 and $0.9
billion in 2009 and 2010 to complete our pipeline expansion projects. The
majority of those expenditures will occur during the remainder of 2008 and the
first half of 2009. Our cost and timing estimates for these projects are subject
to a variety of other risks and uncertainties, including obtaining regulatory
approvals, 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.
 
 24
 We have
financed our expansion capital costs through equity financings, the incurrence
of debt, including sales of debt by us and our subsidiaries, borrowings under
our revolving credit facility and available operating cash flow in excess of our
operating needs. To complete our announced projects, we anticipate we will need
to issue as much as $1.0 billion in equity by issuing limited partnership units,
a portion of which is expected to be issued in the fourth quarter 2008 and the
remainder in the first half of 2009. Our largest shareholder, Loews, has advised
us that it is willing to purchase the entire equity investment we need to the
extent the public markets remain unavailable on acceptable terms. We have not
committed to any transaction at this time, however, any additional investment by
Loews would be subject to review and approval, as to fairness, by our
independent Conflicts Committee.
 
 The
following paragraphs describe each of our pipeline expansion projects in more
detail:
 
 Southeast
Expansion.  The pipeline and two compressor stations related to
this project were placed in service during 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 billion
cubic feet (Bcf) of peak-day transmission capacity. We are expanding the project
through the addition of compression facilities to meet commitments of 1.8 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 all of the operational capacity (with a weighted-average term of 9.2 years,
including a capacity lease agreement with Gulf Crossing discussed
below).
 
 Gulf Crossing Project.We are
constructing a new interstate pipeline that begins near Sherman, Texas and will
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 incremental compression facilities. Additionally,
Gulf Crossing has entered into: (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 our recently completed 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, both of which
have been approved by the FERC. Customers have contracted at fixed rates for all
of the operational 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 compression to be fully in service in 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 consist of approximately 165
miles of 36-inch pipeline. The Greenville Lateral will originate at the Texas
Gas mainline near Greenville, Mississippi and proceed east to the Kosciusko,
Mississippi area and consist 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 66 miles of the Fayetteville Lateral to be in
service during the fourth quarter 2008 and the remainder of the pipeline related
to the Fayetteville and Greenville Laterals to be in service during the first
quarter 2009. In September 2008, we made additional filings with FERC regarding
the new compression required to increase the peak-day transmission capacity,
which is expected to be in service during 2010.
 
 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
September 30, 2008, we spent $41.0 million related to this project.
 
 25
 Maintenance
Capital Expenditures
 
 Maintenance capital expenditures for
the nine months ended September 30, 2008 and 2007, were $23.9 million and $32.3
million. We expect to fund the remaining 2008 maintenance capital expenditures
of approximately $34.7 million from our operating cash flows.
 
 Distributions
 
 For the nine months ended September 30,
2008 and 2007, we paid distributions of $186.3 million and $150.5 million.
Please see Note 8 in Part 1, 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.  Please see Note 7 in Part 1, 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
$248.8 million, net of underwriting discounts and offering expenses of $9.4
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 revolving credit facility which has aggregate lending commitments of
$1.0 billion, under which Boardwalk Pipelines, Gulf South and Texas Gas each may
borrow funds, up to applicable sub-limits. A financial institution which has a
$50.0 million commitment under the revolving credit facility filed for
bankruptcy protection in the third quarter 2008 and has not funded its portion
of our borrowing requests since that time. 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.
 
 As of
September 30, 2008, we had $256.0 million of loans outstanding under the
revolving credit facility of which the weighted-average interest rate on the
borrowings was 3.00%. Any letters of credit previously issued by us under the
facility expired in the third quarter 2008. As of September 30, 2008, we were in
compliance with all covenant requirements under our credit
facility.
 
 Subsequent
to September 30, 2008, we borrowed all of the remaining unfunded commitments
under the credit facility (excluding the unfunded commitment of the bankrupt
lender noted above), which increased borrowings to $958.0 million.
 
 26
 Changes
in cash flow from operating activities
 
 Net cash
provided by operating activities increased $47.4 million to $276.1 million for
the nine months ended September 30, 2008, compared to $228.7 million for the
comparable 2007 period, primarily due to a $59.3 million increase in cash from
the change in net income excluding non-cash items such as depreciation and
amortization and the recognition of income previously deferred. This increase
was offset by an $11.0 million decrease in cash due to the settlement of
derivatives.
 
 Changes
in cash flow from investing activities
 
 Net cash
used in investing activities increased $615.7 million to $1,837.0 million for
the nine months ended September 30, 2008, compared to $1,221.3 million for the
comparable 2007 period, primarily due to a $1,217.4 million increase in capital
expenditures related to our expansion projects. This increase was offset by a
$540.0 million decrease in short term investments which occurred in the 2007
period and $58.0 million in net proceeds from asset sales mainly related to the
sale of gas related to our storage expansion projects and the disposition of
coal reserves.
 
 Changes
in cash flow from financing activities
 
 Net cash
provided by financing activities increased $627.0 million to $1,265.7 million
for the nine months ended September 30, 2008, compared to $638.7 million for the
comparable 2007 period, primarily due to a $654.9 million increase in net
proceeds from the sale of common and class B units and related general partner
capital contributions. The increase was offset by a $35.8 million decrease in
cash from an increase in distributions to our unitholders.
 
 Contractual
Obligations
 
 The table below is updated for
significant changes in contractual cash payment obligations as of September 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 (1)
              
              $
              2,366.0
              
              
              
              -
              
              
              
              -
              
              
              $
              481.0
              
              
              $
              1,885.0Interest
      on long-term debt (2)
              
              
              947.4
              
              
              $
              25.5
              
              
              $
              234.9
              
              
              
              235.0
              
              
              
              452.0Capital
      commitments
              
              
              294.5
              
              
              
              271.9
              
              
              
              22.6
              
              
              
              -
              
              
              
              -Pipeline
      capacity agreements
              
              
              59.1
              
              
              
              1.6
              
              
              
              12.3
              
              
              
              12.3
              
              
              
              32.9Total
              
              $
              3,667.0
              
              
              $
              299.0
              
              
              $
              269.8
              
              
              $
              728.3
              
              
              $
              2,369.9
 
 (1)
              This
      includes our senior unsecured notes, having maturity dates from 2012 to
      2027 and $256.0 million of loans outstanding under our revolving credit
      facility, having a maturity date of June 29,
  2012.
 
 (2)
              Interest
      obligations represent interest due on our senior unsecured notes at fixed
      rates. Future interest obligations under our revolving credit facility are
      uncertain, due to the variable interest rate on fluctuating balances.
      Based on a 3.00% weighted-average interest rate on amounts outstanding
      under our revolving credit facility as of September 30, 2008, $1.9
      million, $15.4 million and $11.4 million would be due under the credit
      facility in less than one year, 1-3 years, and 4-5 years,
      respectively.
 
 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 September 30, 2008,
relating to our expansion projects. For information on these projects, please
read “Expansion Capital Expenditures” above.
 
 27
 Off-Balance
Sheet Arrangements
 
 At September 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.
 
 
 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 nine months ended September 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.
 
 28
 ·
              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.
 
 ·
              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
 
 Total long-term debt at
September 30, 2008, had a carrying value of $2.4 billion and a fair value of
$2.1 billion. With the exception of our revolving credit facility,our
debt has been issued at fixed rates, therefore interest expense would not be
impacted by changes in interest rates. A 100 basis point increase in interest
rates on our fixed rate debt would result in a decrease in fair value of
approximately $120.3 million at September 30, 2008. A 100 basis point decrease
would result in an increase in fair value of approximately $129.8 million at
September 30, 2008. The weighted-average
interest rate of our long-term debt was 5.89% at September 30,
2008.
 
 Certain
volumes of our gas stored underground are available for sale and subject to
commodity price risk. At September 30, 2008 and December 31, 2007, approximately
$3.6 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.
 
 The
derivatives related to the sale of natural gas and cash for fuel reimbursement
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. Generally, for gas sales and cash for
fuel reimbursement, any gains and losses on the related derivatives would be
recognized in Operating Revenues.
  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 September 30, 2008, the amount of gas loaned
out by our subsidiaries was approximately 7.6 trillion British thermal units
(TBtu) and the amount considered an imbalance was approximately 4.2 TBtu.
Assuming an average market price during September 2008 of $7.54 per million
British thermal units (MMBtu), the market value of gas loaned out and considered
an imbalance at September 30, 2008, would have been approximately $88.6 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.
 
 Our cash and cash equivalents,
including funds received after September 30, 2008, as a result of borrowing all
of the remaining commitments under our revolving credit facility, were invested
primarily in treasury funds and 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.
 
 
 
  30
  Item 4.  Controls and Procedures
 
 Disclosure
Controls and Procedures
 
 We
maintain a system of disclosure controls and procedures 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 are 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 September 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 September 30, 2008, that have materially affected or
that are reasonably likely to materially affect our internal control over
financial reporting.
 
 
  31
  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.
 
 
  32
  Item 6.  Exhibits
 
 
 
 Exhibit
                NumberDescription
 
 *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
  33
  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:
      October 28, 2008
              
              By:
              /s/
      Jamie L. BuskillJamie
      L. BuskillSenior
      Vice President, Chief Financial Officer and
  Treasurer
 
 
 
 
 
 
 34