UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
 WASHINGTON,
D.C.  20549
  FORM
10-Q
  (Mark
One)
 x  QUARTERLY REPORT PURSUANT TO SECTION 13
OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For
the quarterly period ended March 31, 2008
 
 OR
 
 o   TRANSITION REPORT PURSUANT TO SECTION
13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For
the transition period from _______________ to _______________
 
 Commission file
      number:      01-32665BOARDWALK
      PIPELINE PARTNERS, LP(Exact
      name of registrant as specified in its charter)DELAWARE(State
      or other jurisdiction of incorporation or organization)20-3265614(I.R.S.
      Employer Identification No.)9
      Greenway Plaza, Suite 2800
                Houston,
      Texas  77046
                (866)
      913-2122(Address
      and Telephone Number of Registrant’s Principal Executive
      Office)Securities
      registered pursuant to Section 12(b) of the Act:Title
      of each class
              
              Name
      of each exchange on which registeredCommon
      Units Representing Limited Partner Interests
              
              New
      York Stock ExchangeSecurities registered pursuant
      to Section 12(g) of the Act:  NONE
 
 
 Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90
days.        Yes  x    Noo
 
 Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer or a smaller reporting
company.  See the definitions of “large accelerated filer,”
“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act. (Check one)
 Large
accelerated filer  x                                               Accelerated
filer  o                                           Non-accelerated
filer  o                                           Smaller
reporting company  o
 
 Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act).  Yes  ̈  No x
 
 As
of April 23, 2008, the registrant had 90,656,122 common units outstanding and
33,093,878 subordinated units outstanding.
 
 
 
 
 
 
 1
 
 
 
 
 
 TABLE
OF CONTENTS
 
 FORM
10-Q
 
 March
31, 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...........................20
  Item
3.  Quantitative and Qualitative Disclosures About Market
Risk...............................................................28
  Item 4.  Controls
and Procedures...........................................................................................................30
  PART II - OTHER
INFORMATION
   Item 1.  Legal
Proceedings...................................................................................................................31
  Item 2.  Unregistered
Sales of Equity Securities and Use of Proceeds...............................................................31
  Item
6.  Exhibits..................................................................................................................................32
  Signatures.....................................................................................................................................33
 
  2
 
 PART
I – FINANCIAL INFORMATION
 
 Item
1.  Financial Statements
 
 BOARDWALK
PIPELINE PARTNERS, LP
 
 CONDENSED CONSOLIDATED BALANCE SHEETS
 (Millions)
 (Unaudited)
 
 March
      31,
              
              
              December
      31,ASSETS
              
              2008
              
              
              2007Current
      Assets:Cash
      and cash equivalents
              
              $
              36.4
              
              
              $
              317.3Receivables:Trade,
      net
              
              
              60.4
              
              
              
              60.7Other
              
              
              11.9
              
              
              
              12.7Gas
      Receivables:Transportation
      and exchange
              
              
              23.6
              
              
              
              12.5Storage
              
              
              -
              
              
              
              1.3Inventories
              
              
              18.9
              
              
              
              16.6Costs
      recoverable from customers
              
              
              7.2
              
              
              
              6.3Gas
      stored underground
              
              
              22.9
              
              
              
              16.3Prepaid
      expenses and other current assets
              
              
              11.8
              
              
              
              11.9Total
      current assets
              
              
              193.1
              
              
              
              455.6Property,
      Plant and Equipment:Natural
      gas transmission plant
              
              
              2,780.6
              
              
              
              2,392.5Other
      natural gas plant
              
              
              227.3
              
              
              
              224.03,007.9
              
              
              
              2,616.5Less—accumulated
      depreciation and amortization
              
              
              288.8
              
              
              
              262.52,719.1
              
              
              
              2,354.0Construction
      work in progress
              
              
              1,079.6
              
              
              
              951.4Property,
      plant and equipment, net
              
              
              3,798.7
              
              
              
              3,305.4Other
      Assets:Goodwill
              
              
              163.5
              
              
              
              163.5Gas
      stored underground
              
              
              152.3
              
              
              
              172.4Costs
      recoverable from customers
              
              
              15.8
              
              
              
              15.9Other
              
              
              46.3
              
              
              
              44.5Total
      other assets
              
              
              377.9
              
              
              
              396.3Total
      Assets
              
              $
              4,369.7
              
              
              $
              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)
 
 March
      31,
              
              
              December
      31,LIABILITIES
      AND PARTNERS’ CAPITAL
              
              2008
              
              
              2007Current
      Liabilities:Payables:Trade
              
              $
              149.8
              
              
              $
              190.6Affiliates
              
              
              1.2
              
              
              
              1.3Other
              
              
              4.6
              
              
              
              5.1Gas
      Payables:Transportation
      and exchange
              
              
              9.8
              
              
              
              17.8Storage
              
              
              19.3
              
              
              
              35.3Accrued
      taxes, other
              
              
              44.9
              
              
              
              20.2Accrued
      interest
              
              
              23.1
              
              
              
              30.8Accrued
      payroll and employee benefits
              
              
              14.3
              
              
              
              22.3Construction
      retainage
              
              
              18.1
              
              
              
              32.2Deferred
      income
              
              
              3.6
              
              
              
              7.2Other
      current liabilities
              
              
              35.6
              
              
              
              26.5Total
      current liabilities
              
              
              324.3
              
              
              
              389.3Long
      –Term Debt
              
              
              2,095.8
              
              
              
              1,847.9Other
      Liabilities and Deferred Credits:Pension
      and postretirement benefits
              
              
              18.0
              
              
              
              17.2Asset
      retirement obligation
              
              
              16.3
              
              
              
              16.1Provision
      for other asset retirement
              
              
              42.9
              
              
              
              42.4Other
              
              
              66.9
              
              
              
              41.4Total
      other liabilities and deferred credits
              
              
              144.1
              
              
              
              117.1Commitments
      and ContingenciesPartners’
      Capital:Common
      units – 90.7 million units issued and outstanding as of March
      31, 2008 and December 31, 2007
              
              
              1,494.3
              
              
              
              1,473.9Subordinated
      units – 33.1 million units issued and outstanding as of March 31, 2008 and
      December 31, 2007
              
              
              299.2
              
              
              
              291.7General
      partner
              
              
              33.8
              
              
              
              33.2Accumulated
      other comprehensive (loss) income
              
              
              (21.8
              )
              
              
              4.2Total
      partners’ capital
              
              
              1,805.5
              
              
              
              1,803.0Total
      Liabilities and Partners’ Capital
              
              $
              4,369.7
              
              
              $
              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 earnings per unit)
 (Unaudited)
 
 For
      the Three Months Ended
                March
      31,2008
              
              
              2007Operating
      Revenues:Gas
      transportation
              
              $
              176.5
              
              
              $
              152.9Parking
      and lending
              
              
              5.1
              
              
              
              18.4Gas
      storage
              
              
              10.7
              
              
              
              7.7Other
              
              
              5.0
              
              
              
              9.1Total
      operating revenues
              
              
              197.3
              
              
              
              188.1Operating
      Costs and Expenses:Operation
      and maintenance
              
              
              40.8
              
              
              
              39.5Administrative
      and general
              
              
              25.2
              
              
              
              25.8Depreciation
      and amortization
              
              
              27.4
              
              
              
              19.9Contract
      settlement gain
              
              
              (11.2
              )
              
              
              -Asset
      impairment
              
              
              1.4
              
              
              
              -Net
      loss on disposal of operating assets and related contracts
              
              
              0.2
              
              
              
              2.6Taxes
      other than income taxes
              
              
              12.0
              
              
              
              8.0Total
      operating costs and expenses
              
              
              95.8
              
              
              
              95.8Operating
      income
              
              
              101.5
              
              
              
              92.3Other
      Deductions (Income):Interest
      expense
              
              
              19.0
              
              
              
              16.8Interest
      income
              
              
              (0.9
              )
              
              
              (4.6
              )Interest
      income from affiliates, net
              
              
              (0.1
              )
              
              
              -Miscellaneous
      other income, net
              
              
              (4.9
              )
              
              
              (0.3
              )Total
      other deductions
              
              
              13.1
              
              
              
              11.9Income
      before income taxes
              
              
              88.4
              
              
              
              80.4Income
      taxes
              
              
              0.3
              
              
              
              0.2Net
      income
              
              $
              88.1
              
              
              $
              80.2
 
 Calculation
      of limited partners’ interest in Net income:Net
      income
              
              $
              88.1
              
              
              $
              80.2Less
      general partner’s interest in Net income
              
              
              3.3
              
              
              
              1.8Limited
      partners’ interest in Net income
              
              $
              84.8
              
              
              $
              78.4Basic
      and diluted net income per limited partner unit:Common
      and subordinated units
              
              $
              0.60
              
              
              $
              0.61Cash
      distribution to common and subordinated units
              
              $
              0.46
              
              
              $
              0.415Weighted-average
      number of limited partner units outstanding:Common
      units
              
              
              90.7
              
              
              
              76.0Subordinated
      units
              
              
              33.1
              
              
              
              33.1
 
 
 The
accompanying notes are an integral part of these condensed consolidated
financial statements.
  5
  BOARDWALK
PIPELINE PARTNERS, LP
 
 CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 (Millions)
 (Unaudited)
 
 For
      the Three Months Ended
                March
      31,2008
              
              
              2007OPERATING
      ACTIVITIES:Net
      income
              
              $
              88.1
              
              
              $
              80.2Adjustments
      to reconcile to cash provided by operations:Depreciation
      and amortization
              
              
              27.4
              
              
              
              19.9Amortization
      of deferred costs
              
              
              2.4
              
              
              
              1.8Amortization
      of acquired executory contracts
              
              
              (0.1
              )
              
              
              (0.8
              )Asset
      impairment
              
              
              1.4
              
              
              
              -Loss
      on disposal of operating assets and related contracts
              
              
              0.2
              
              
              
              2.6Changes
      in operating assets and liabilities:Trade
      and other receivables
              
              
              1.1
              
              
              
              3.5Gas
      receivables and storage assets
              
              
              3.6
              
              
              
              19.2Costs
      recoverable from customers
              
              
              (0.8
              )
              
              
              3.6Other
      assets
              
              
              (10.6
              )
              
              
              0.6Trade
      and other payables
              
              
              (9.2
              )
              
              
              (14.5
              )Gas
      payables
              
              
              0.4
              
              
              
              (24.2
              )Accrued
      liabilities
              
              
              (12.5
              )
              
              
              (4.1
              )Other
      liabilities
              
              
              (2.1
              )
              
              
              (10.5
              )Net
      cash provided by operating activities
              
              
              89.3
              
              
              
              77.3INVESTING
      ACTIVITIES:Capital
      expenditures
              
              
              (542.5
              )
              
              
              (162.1
              )Proceeds
      from sale of operating assets
              
              
              -
              
              
              
              0.4Advances
      to affiliates, net
              
              
              (0.3
              )
              
              
              0.7Net
      cash used in investing activities
              
              
              (542.8
              )
              
              
              (161.0
              )FINANCING
      ACTIVITIES:Proceeds
      from long-term debt, net of issuance costs
              
              
              247.2
              
              
              
              -Proceeds
      from borrowings on revolving credit agreement
              
              
              153.0
              
              
              
              -Repayment
      of borrowings on revolving credit agreement
              
              
              (153.0
              )
              
              
              -Treasury
      rate lock settlement
              
              
              (15.0
              )
              
              
              -Distributions
              
              
              (59.6
              )
              
              
              (46.1
              )Proceeds
      from sale of common units, net of related
                transaction
      costs
              
              
              -
              
              
              
              287.9Capital
      contribution from parent and general partner
              
              
              -
              
              
              
              6.0Net
      cash provided by financing activities
              
              
              172.6
              
              
              
              247.8(Decrease)
      increase in cash and cash equivalents
              
              
              (280.9
              )
              
              
              164.1Cash
      and cash equivalents at beginning of period
              
              
              317.3
              
              
              
              399.1Cash
      and cash equivalents at end of period
              
              $
              36.4
              
              
              $
              563.2
 
 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
              
              
              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
              
              
              54.6
              
              
              
              23.8
              
              
              
              1.8
              
              
              
              -
              
              
              
              80.2Distributions
      paid
              
              
              (31.2
              )
              
              
              (13.7
              )
              
              
              (1.2
              )
              
              
              -
              
              
              
              (46.1
              )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
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (9.1
              )
              
              
              (9.1
              )Balance
      March 31, 2007
              
              $
              1,253.1
              
              
              $
              295.6
              
              
              $
              28.7
              
              
              $
              14.0
              
              
              $
              1,591.4Balance
      January 1, 2008
              
              $
              1,473.9
              
              
              $
              291.7
              
              
              $
              33.2
              
              
              $
              4.2
              
              
              $
              1,803.0Add
      (deduct):Net
      income
              
              
              62.1
              
              
              
              22.7
              
              
              
              3.3
              
              
              
              -
              
              
              
              88.1Distributions
      paid
              
              
              (41.7
              )
              
              
              (15.2
              )
              
              
              (2.7
              )
              
              
              -
              
              
              
              (59.6
              )Other
      comprehensive loss
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (26.0
              )
              
              
              (26.0
              )Balance
      March 31, 2008
              
              $
              1,494.3
              
              
              $
              299.2
              
              
              $
              33.8
              
              
              $
              (21.8
              )
              
              $
              1,805.5
 
 
 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 EndedMarch
      31,2008
              
              
              2007Net
      income
              
              $
              88.1
              
              
              $
              80.2Other
      comprehensive (loss) income:Loss
      on cash flow hedges
              
              
              (24.4
              )
              
              
              (7.4
              )Reclassification
      adjustment transferred to Net income from cash flow
                hedges
              
              
              0.6
              
              
              
              (3.1
              )Pension
      and other postretirement benefits costs
              
              
              (2.2
              )
              
              
              1.4Total
      comprehensive income
              
              $
              62.1
              
              
              $
              71.1
 
 The
accompanying notes are an integral part of these condensed consolidated
financial statements.
 
  8
  
 BOARDWALK
PIPELINE PARTNERS, LP
 
 NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
 (Unaudited)
 
 
 Note
1:  Basis of Presentation
 
 Boardwalk
Pipeline Partners, LP (the Partnership) is a Delaware limited partnership formed
to own and operate the business conducted by Boardwalk Pipelines, LP (Boardwalk
Pipelines) and its subsidiaries, Gulf South Pipeline Company, LP (Gulf South)
and Texas Gas Transmission, LLC (Texas Gas) (together, the operating
subsidiaries). Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned
subsidiary of Loews Corporation (Loews), owns 53.3 million common units and 33.1
million subordinated units constituting approximately 68% of the Partnership’s
capital. 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 and all of the incentive distribution rights, further described
in Note 7. 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 March 31, 2008 and December 31,
2007, and the results of operations, changes in cash flow, changes in partners’
equity and comprehensive income for the three months ended March 31, 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 March 31, 2008 and December 31, 2007, Gulf South held 32.2
trillion British thermal units (TBtu) and 52.0 TBtu of gas owned by shippers.
Gulf South loaned 0.3 and 0.2 TBtu of gas to shippers as of March 31, 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
$19.3 million and $35.3 million at March 31, 2008 and December 31,
2007.
 
 
 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 hedge contracts are reported at fair
value in accordance with Statement of Financial Accounting Standards (SFAS) No.
133, Accounting for Derivative
Instruments and Hedging Activities,as amended.
 
 9
   Certain
volumes of gas stored underground are available for sale and subject to
commodity price risk. At March 31, 2008 and December 31, 2007, approximately
$22.9 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 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.
 
 In the
second quarter 2007, the Partnership entered into natural gas price swaps to
hedge exposure to prices associated with the purchase of 2.1 Bcf of natural gas
to be used for line pack for the Gulf Crossing and Southeast Expansion projects,
approximately 1.3 Bcf of which remained outstanding at March 31, 2008. The
derivatives were not designated as hedges and were marked to fair value
resulting in a gain of $3.1 million in Miscellaneous other income, net on the
Condensed Consolidated Statements of Income for the three months ended March 31,
2008.
 
 The
Partnership recognized a loss of $2.1 million in the first quarter 2007 on
derivatives and related contracts not designated as hedges related to gas stored
underground that became available for sale as a result of Phase II of the
Western Kentucky project.
 
 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. On February 1, 2008, the Partnership settled the rate lock and
paid the counterparty approximately $15.0 million.  The loss will be
amortized to interest expense over 10 years. As of December 31, 2007, the
Partnership recorded a payable of $8.4 million and a corresponding amount in
Accumulated other comprehensive income for the fair value of the rate
lock.
 
 With the
exception of the derivatives related to certain storage gas volumes related to
Phase II of the Western Kentucky storage expansion project and line pack gas
purchases referred to above, the derivatives related to the sale or purchase of
natural gas, cash for fuel reimbursement and debt generally qualify for cash
flow hedge accounting under SFAS No. 133 and are designated as such. The
effective component of related unrealized gains and losses resulting from
changes in fair values of the derivatives contracts designated as cash flow
hedges are deferred as a component of Accumulated other comprehensive
income. The deferred gains and losses are recognized in the Condensed
Consolidated Statements of Income when the 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. For the sale of gas related to Phase II of the Western Kentucky
storage expansion project, any gains and losses on the related derivatives were
recognized in Net gain on disposal of operating assets and related
contracts. Any gains and losses on the derivatives related to the line pack
gas purchases would be recognized in Miscellaneous other income,
net.
 
 The fair
values of derivatives existing as of March 31, 2008 and December 31, 2007, were
included in the following captions in the Condensed Consolidated Balance Sheets
(in millions):
 
 March
      31, 2008
              
              
              December
      31, 2007Prepaid
      expenses and other current assets
              
              $
              2.8
              
              
              $
              2.2Other
      current liabilities
              
              
              16.5
              
              
              
              9.4Other
      non-current liabilities
              
              
              0.2
              
              
              
              -Accumulated
      other comprehensive loss
              
              
              (32.7
              )
              
              
              (8.9
              )
 
 10
   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 if the
transactions are deemed probable of not occurring changes in the fair values of
the associated derivative financial instruments would be recognized currently in
earnings. Ineffectiveness decreased Net income by less than $0.1 million for the
three months ended March 31, 2008 and increased Net income by $0.4 million for
the three months ended March 31, 2007. The Partnership did not discontinue any
cash flow hedges during the three month periods ended March 31, 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 are expected to be applied beginning in 2009. Under SFAS
No. 157, 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. The standard
establishes a fair value hierarchy that prioritizes the information used to
develop those assumptions giving the priority, from highest to lowest, to quoted
prices in active markets for identical assets and liabilities (Level 1);
observable inputs not included in Level 1, for example, quoted prices for
similar assets and liabilities (Level 2); and unobservable data (Level 3), for
example, a reporting entity’s own internal data based on the best information
available in the circumstances.
 
 The Partnership identified its
derivatives as items governed by the provisions of SFAS No. 157. The derivatives
in existence at March 31, 2008 were natural gas price swaps and options, which
were recorded at fair value at March 31, 2008 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
following table shows information regarding the Partnership’s derivatives at
March 31, 2008 (in millions):
 
 Total
      at
                March
      31, 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
              
              $
              2.8
              
              
              
              -
              
              
              $
              2.8
              
              
              
              -Total
      assets
              
              $
              2.8
              
              
              
              -
              
              
              $
              2.8
              
              
              
              -Liabilities:Other
      current liabilities
              
              $
              16.5
              
              
              
              -
              
              
              $
              16.5
              
              
              
              -Other
      non-current liabilities
              
              
              0.2
              
              
              
              -
              
              
              
              0.2
              
              
              
              -Total
      liabilities
              
              $
              16.7
              
              
              
              -
              
              
              $
              16.7
              
              
              
              -
 
 
  11
  SFAS
No. 159, The Fair Value Option for Financial Assets and Financial
Liabilities
 
 In 2008, the Partnership had the option
to apply the provisions of SFAS No. 159, which allows companies to elect to
measure and record certain financial assets and liabilities at fair value that
would not otherwise be recorded at fair value, such as long term debt or notes
receivable. Unrealized gains and losses on items for which the fair value option
was chosen would be reported in earnings. The Partnership reviewed its financial
assets and liabilities in existence at January 1, 2008 as well as any financial
assets and liabilities entered into during the three month period ended March
31, 2008, and did not elect the fair value option for any applicable items.
Consequently, the application of SFAS No. 159 had no effect on the Partnership’s
financial statements.
 
 
 Note 5:  Income Taxes
 
 The Partnership is not a taxable entity
for federal income tax purposes.  As such, it does not directly pay
federal income tax. The Partnership’s taxable income or loss, which may vary
substantially from the net income or loss reported in the Condensed Consolidated
Statements of Income, is includable in the federal income tax returns of each
partner. The aggregate difference in the basis of the Partnership’s net assets
for financial and income tax purposes cannot be readily determined as the
Partnership does not have access to the information about each partner’s tax
attributes. The subsidiaries of the Partnership directly incur some income-based
state taxeswhich are
presented in Income taxes on the Condensed Consolidated Statements of
Income.
 
 
 Note
6:  Commitments and Contingencies
 
 A.  Calpine
Energy Services (Calpine) Settlement
 
 In
December 2007, Gulf South and Calpine filed a stipulation and agreement in
Calpine’s Chapter 11 Bankruptcy proceedings to settle, for approximately $16.5
million, Gulf South’s claim against Calpine related to Calpine’s non-payment
under a transportation agreement. The claim, which was approved in January 2008,
was to be paid in the form of Calpine stock, along with other general creditors
having claims in the Bankruptcy proceeding. In the fourth quarter 2007, the
Partnership recognized $4.1 million of revenues related to previously reserved
amounts invoiced to Calpine for transportation services in 2007 and 2006. 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.  Legal
Proceedings
 
 Napoleonville
Salt Dome Matter
 
 In
December 2003, natural gas leaks were observed near two natural gas storage
caverns that were being leased and operated by Gulf South for natural gas
storage in Napoleonville, Louisiana. Gulf South commenced remediation efforts
immediately and ceased using those storage caverns. 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. Gulf South continues to vigorously
defend each of these actions, however it is not possible to predict the outcome
of this litigation as the cases remain in discovery. Litigation is subject to
many uncertainties, and it is possible these actions could be decided
unfavorably. Gulf South has settled many of the cases filed against it and may
enter into discussions in an attempt to settle other cases if Gulf South
believes it is appropriate to do so.
 
 
 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.
 
 
 C.  Regulatory
and Rate Matters
 
 Expansion
Capital Projects
 
 The
Partnership is engaged in several pipeline expansion projects as described
below:
 
 East Texas to Mississippi
Expansion.  The pipeline and two of the three compression
facilities are now in service for the East Texas to Mississippi expansion, which
project consists of approximately 242 miles of 42-inch pipeline from DeSoto
Parish in western Louisiana to near Harrisville, Mississippi and approximately
110,000 horsepower of new compression having approximately 1.7 Bcf of new
peak-day transmission capacity. The Partnership is serving the full contract
demand which consists of customers that have contracted at fixed rates for 1.4
Bcf per day of firm transportation capacity on a long-term basis (with a
weighted average term of approximately 6.8 years), which represents
substantially all of the normal operating capacity. The Partnership is in the
process of commissioning the remaining compression facility associated with this
project, which is expected to be completed during the second quarter 2008.
Through March 31, 2008, the Partnership has spent $916.1 million related to this
project.
 
 Southeast
Expansion.  In September 2007, the Federal Energy Regulatory
Commission (FERC) granted the Partnership the authority to construct, own and
operate a pipeline expansion originating near Harrisville, Mississippi and
extending to an interconnect with Transcontinental Pipe Line Company (Transco)
in Choctaw County, Alabama (Transco 85). This expansion will initially consist
of approximately 112 miles of 42-inch pipeline having approximately 1.2 Bcf of
peak-day transmission capacity. To accommodate volumes expected to come from the
Gulf Crossing leased capacity discussed below, this project will be expanded to
up to 2.2 Bcf of peak-day transmission capacity. In addition, the FERC approved
the Partnership’s 260 million cubic feet (MMcf) per day operating lease with
Destin Pipeline Company which will provide the Partnership enhanced access to
markets in Florida. Customers have contracted at fixed rates for 660 MMcf per
day of firm transportation capacity on a long-term basis (with a
weighted-average term of 9.2 years), in addition to the capacity leased to Gulf
Crossing discussed below. Construction has commenced and the Partnership expects
the initial 1.2 Bcf of capacity to be in service during the second quarter 2008.
The Partnership expects the remaining capacity to be in service during the first
quarter 2009. Through March 31, 2008, the Partnership has spent $394.8 million
related to this project.
 
 Gulf Crossing Project.The
Partnership is pursuing the construction of a new interstate pipeline that will
begin near Sherman, Texas and proceed to the Perryville, Louisiana area. The
project will be owned by Gulf Crossing Pipeline Company LLC, the Partnership’s
newly formed interstate pipeline subsidiary, and will consist of approximately
357 miles of 42-inch pipeline having up to approximately 1.7 Bcf of peak-day
transmission capacity. Additionally, Gulf Crossing has entered into, subject to
regulatory approval: (i) an operating lease for up to 1.4 Bcf per day of
capacity on the Partnership’s Gulf South pipeline system (including capacity on
the Southeast Expansion and capacity on a portion of the East Texas to
Mississippi Expansion) to make deliveries to an interconnect with Transco 85;
and (ii) an operating lease with Enogex, a third-party intrastate pipeline,
which will bring certain gas supplies to the Partnership’s system. Customers
have contracted at fixed rates for 1.1 Bcf per day of long-term firm
transportation capacity (with a weighted average term of approximately 9.5
years). The Final Environmental Impact Statement was received in the first
quarter 2008, and the Partnership is awaiting the certificate to commence
construction of the project. The Partnership expects this project to be in
service during the first quarter 2009. Through March 31, 2008, the Partnership
has spent $256.2 million related to this project.
 
 13
  Fayetteville and Greenville
Laterals.  The Partnership is pursuing the construction of two
laterals connected to 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 consisting of
approximately 95 miles of 36-inch pipeline. The Greenville Lateral will allow
customers to access additional markets, primarily in the Midwest, Northeast and
Southeast. This project had an initial design capacity of 0.8 Bcf of peak-day
transmission capacity which did not include compression facilities. The
Partnership recently executed contracts for additional capacity that would
require it to add compression to the project to increase the peak-day
transmission capacity from 0.8 Bcf to approximately 1.2 Bcf for the Fayetteville
Lateral and from approximately 0.8 to approximately 1.0 Bcf for the Greenville
Lateral.
 
 Including
the new capacity, the contracts on the Fayetteville Lateral provide, after
phase-in periods through 2012, for 975 MMcf per day of initial capacity, with
options for additional capacity that, if exercised, could add 225 MMcf per day
of capacity. On the Greenville Lateral, contracts for 818 MMcf per day of
initial capacity are phased in through 2012 with options for additional capacity
that, if exercised, could add 172 MMcf per day of capacity.  The
contracts associated with this project are at fixed rates with a weighted
average term of 9.9 years. The Final Environmental Impact Statement was received
in the first quarter 2008, and the Partnership is awaiting the certificate to
commence construction of the project. The Partnership expects the first 60 miles
of the Fayetteville Lateral to be in service during the third quarter 2008 and
the remainder of the pipeline related to the Fayetteville and Greenville
Laterals to be in service during the first quarter 2009. The Partnership expects
to make additional filings with FERC regarding the additional compression
required to increase the peak-day transmission capacity and expects the
additional capacity to be in service during 2010. Through March 31, 2008, the
Partnership has spent $167.8 million related to this project.
 
 In
addition to the pipeline expansion projects described above, the Partnership is
currently engaged in the following storage expansion project:
 
 Western Kentucky Storage Expansion
Phase III.  In February 2008, the FERC granted the Partnership
authority to develop up to 8.3 Bcf of new working gas capacity and granted
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 2008.
Through March 31, 2008, the Partnership has spent $3.7 million related to this
project.
 
 
 D.  Environmental
and Safety Matters
 
 The operating subsidiaries are subject
to federal, state, and local environmental laws and regulations in connection
with the operation and remediation of various operating sites. The Partnership
accrues for environmental expenses resulting from existing conditions that
relate to past operations when the costs are probable and can be reasonably
estimated. In addition to federal and state mandated remediation requirements,
the Partnership often enters into voluntary remediation programs with the
agencies.
 
 As
of March 31, 2008 and December 31, 2007, the Partnership had an accrued
liability of approximately $16.7 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 March 31, 2008 and December 31, 2007, approximately $2.7
million was recorded in Other current liabilities and approximately $14.0
million and $14.3 million were recorded in Other Liabilities and Deferred
Credits.
 
 14
  In March
2008, the Environmental Protection Agency (EPA) adopted regulations lowering the
8-hour ozone standard relevant to non-attainment areas.  Under the
regulation new non-attainment areas will be identified which may require
additional emission controls for compliance at as many as 14 facilities operated
by the Partnership. The anticipated effective date for compliance with the
proposed standard in its current state is between 2013 and 2016.
 
 The
Partnership considers environmental assessment, remediation costs and costs
associated with compliance with environmental standards to be recoverable
through base rates, as they are prudent costs incurred in the ordinary course of
business and, therefore, no regulatory asset has been recorded to defer these
costs. The actual costs incurred will depend on the actual amount and extent of
contamination discovered, the final cleanup standards mandated by the EPA or
other governmental authorities and other factors.
 
 
 E.  Commitments
 
 The Partnership’s future capital
commitments as of March 31, 2008, for contracts already authorized are expected
to approximate the following amounts (in millions):
 
 Less
      than 1 year
              
              $
              573.71-3
      years
              
              
              24.14-5
      years
              
              
              -More
      than 5 years
              
              
              -Total
              
              $
              597.8
  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:  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
              Common
      and
                Subordinated
                Unitholders
              
              General
                PartnerMinimum
      Quarterly Distribution
              
              $0.3500
              
              98%
              2%First
      Target Distribution
              
              up to $0.4025
              
              98%
              2%Second
      Target Distribution
              
              above $0.4025 up to $0.4375
              
              85%
              15%Third
      Target Distribution
              
              above
      $0.4375 up to $0.5250
              
              75%
              25%Thereafter
              
              above
      $0.5250
              
              50%
              50%
 
 The amounts
reported for net income per limited partner unit on the Condensed
Consolidated Statements of Income for the three month periods ended March
31, 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):
  15
  
 For
      the Three Months Ended
                March
      31,2008
              
              
              2007Limited
      partners' interest in net income
              
              $
              84.8
              
              
              $
              78.4Less
      assumed allocation to IDRs
              
              
              11.0
              
              
              
              12.0Net
      income available to limited partners
              
              
              73.8
              
              
              
              66.4Less
      assumed allocation to subordinated units
              
              
              19.7
              
              
              
              20.2Net
      income available to common units
              
              $
              54.1
              
              
              $
              46.2Weighted
      average common units
              
              
              90.7
              
              
              
              76.0Weighted
      average subordinated units
              
              
              33.1
              
              
              
              33.1Net
      income per limited partner unit –
                common
      and subordinated units
              
              $
              0.60
              
              
              $
              0.61
 
 In the three month periods ended March
31, 2008 and 2007, the Partnership declared quarterly distributions per unit to
unitholders of record, including common and subordinated units and the 2%
general partner interest and IDRs held by its general partner as follows (in
millions, except distribution per unit):
 
 Payable
      Date
              
              Distribution
      per Unit
              
              Amount
      Paid to Common and Subordinated Unitholders
              
              Amount
      Paid to General Partner (Including IDRs)February
      25, 2008
              
              $
      0.460
              
              $
      56.9
              
              $
      2.7February
      27, 2007
              
              0.415
              
              44.9
              
              1.2
 
 
 Note
8:  Financing
 
 Senior
Unsecured Debt
 
 On March 27, 2008, the Partnership
received net proceeds of approximately $247.2 million after deducting initial
purchaser discounts and offering expenses of $2.8 million from the sale of
$250.0 million of 5.50% senior unsecured notes of Texas Gas due April 1, 2013.
Interest on the notes will be payable on April 1 and October 1 of each year,
beginning on October 1, 2008. The notes are redeemable, in whole or in
part, at the option of Texas Gas at any time, at a redemption price equal to the
greater of 100% of the principal amount of the notes to be redeemed or a “make
whole” redemption price based on the remaining scheduled payments of principal
and interest discounted to the date of redemption at a Treasury rate plus 50
basis points, plus accrued and unpaid interest, if any. Other customary
covenants apply, including those concerning events of default.
 
 As
of March 31, 2008 and December 31, 2007, the weighted-average interest rate of
the Partnership’s long-term debt was 5.88% and 5.82%.
 
 Revolving
Credit Facility
 
 As of
March 31, 2008 and December 31, 2007, no funds were drawn under the
Partnership’s $1.0 billion revolving credit facility, however, at March 31,
2008, the Partnership had outstanding letters of credit under the facility of
$95.9 million to support certain obligations associated with the pipeline
expansion projects which reduced the available capacity under the facility by
such amount. During the three month period ended March 31, 2008, the Partnership
borrowed and repaid $153.0 million under the facility.  The interest
rates on the borrowings ranged from 2.76% to 3.35%. As of March 31, 2008, the
Partnership and its subsidiaries were in compliance with all covenant
requirements under the credit agreement.
 
  16
  Capitalized
Interest and Allowance for Funds Used During Construction
 
 During
the three months ended March 31, 2008 and 2007, the Partnership capitalized
interest of $8.6 million and $2.1 million. In accordance with SFAS No. 71,Accounting for the Effect of
Certain Types of Regulation, the Partnership’s Texas Gas subsidiary
capitalizes allowance for funds used during construction (AFUDC), comprised of
debt and equity components. The Partnership capitalized $2.2 million and $0.4
million of AFUDC for the three months ended March 31, 2008 and
2007.
 
 Offering
of Common Units
 
 In March
2007, the Partnership completed an equity offering of 8.0 million of its common
units for which it received net proceeds of $293.9 million, after deducting
underwriting discounts and offering expenses of $4.2 million and including
approximately $6.0 million contributed by its general partner to maintain its 2%
interest. The proceeds of the offering have been used to finance the
Partnership’s expansion activities discussed in Note 6.
 
 
 Note
9: Property, Plant and Equipment
 
 In first
quarter 2008, the Partnership placed in service the remaining pipeline assets
associated with the East Texas to Mississippi Expansion project from Delhi,
Louisiana to Harrisville, Mississippi and related compression at two facilities.
As a result, approximately $382.2 million was transferred from construction work
in progress to property, plant and equipment. The assets will generally be
depreciated over a term of 35 years.
 
 In the
first quarter 2008, the Partnership completed a review of the non-contiguous
offshore assets of its Gulf South subsidiary and provided notice to the other
interest holders of its intent to discontinue any use of its portion of the
available capacity of these assets. As a result, the Partnership reviewed the
assets for recoverability in accordance with SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, and recorded an impairment charge of
approximately $1.4 million representing the net book value of the related
assets.
 
 
 Note
10: Credit Concentration
 
 Natural
gas price volatility has increased dramatically in recent years, which has
materially increased credit risk related to gas loaned to customers. Gas loaned
to customers refers to receivables for services provided, as well as volumes
owed by customers for imbalances or gas lent by the Partnership to them,
generally under parking and lending and no-notice service. As of March 31, 2008,
the amount of gas loaned out by the Partnership’s subsidiaries was approximately
37.8 TBtu and the amount considered an imbalance was approximately 3.6 TBtu.
Assuming an average market price during March 2008 of $9.32 per million British
thermal units (MMBtu), the market value of gas loaned out and considered an
imbalance at March 31, 2008, would have been approximately $385.2 million. If
any significant customer of the Partnership should have credit or financial
problems resulting in a delay or failure to repay the gas they owe to it, this
could have a material adverse effect on the Partnership’s financial condition,
results of operations and cash flows.
 
 
 Note
11:  Employee Benefits
 
 Defined
Benefit Plans
 
 Texas Gas employees hired prior to
November 1, 2006 are covered under a non-contributory, defined benefit pension
plan. The Texas Gas Supplemental Retirement Plan provides pension benefits for
the portion of an eligible employee’s pension benefit that becomes subject to
compensation limitations under the Internal Revenue Code. Texas Gas provides
postretirement medical benefits and life insurance to retired employees who were
employed full time, hired prior to January 1, 1996, and have met certain other
requirements. The Partnership uses a measurement date of December 31 for its
benefits plans.
 
 17
   Components of net periodic
benefit cost for both the retirement plans and postretirement benefits other
than pensions (PBOP) for the three months ended March 31, 2008 and 2007 were the
following (in millions):
 
 Retirement
      Plans
              
              
              PBOPFor
      the Three Months Ended
              
              
              For
      the Three Months EndedMarch
      31,
              
              
              March
      31,2008
              
              
              2007
              
              
              2008
              
              
              2007Service
      cost
              
              $
              0.9
              
              
              $
              0.9
              
              
              $
              0.2
              
              
              $
              0.2Interest
      cost
              
              
              1.6
              
              
              
              1.7
              
              
              
              0.8
              
              
              
              0.9Expected
      return on plan assets
              
              
              (1.7
              )
              
              
              (1.8
              )
              
              
              (1.3
              )
              
              
              (1.2
              )Amortization
      of prior service credit
              
              
              -
              
              
              
              -
              
              
              
              (1.9
              )
              
              
              (1.9
              )Amortization
      of unrecognized net loss
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              0.2Settlement
      charge
              
              
              -
              
              
              
              3.1
              
              
              
              -
              
              
              
              -Regulatory
      asset decrease
              
              
              -
              
              
              
              -
              
              
              
              1.4
              
              
              
              1.4Net
      periodic pension expense
              
              $
              0.8
              
              
              $
              3.9
              
              
              $
              (0.8
              )
              
              $
              (0.4
              )
 
 
 Defined
Contribution Plans
 
 Gulf
South employees and Texas Gas employees hired on or after November 1, 2006 are
provided retirement benefits under a defined contribution money purchase
plan. The operating subsidiaries also provide 401(k) plan benefits to their
employees. Costs related to the Partnership’s defined contribution plans were
$1.5 million and $1.2 million for the three months ended March 31, 2008 and
2007.
 
 
 Note
12:  Related Parties
 
 Loews provides a variety of corporate
services to the Partnership and its subsidiaries under services agreements.
Services provided by Loews include, among others, information technology, tax,
risk management, internal audit and corporate development services. Loews
charged $4.0 million and $4.2 million for the three months ended March 31, 2008
and 2007 to the Partnership based on the actual time spent by Loews personnel
performing these services, plus related expenses.
 
 Distributions paid related to common
and subordinated units held by BPHC, 2% general partner interest and IDRs held
by Boardwalk GP were $42.4 million and $37.0 million during the first quarter
2008 and 2007.
 
 The
Partnership pays franchise and certain other taxes on behalf of BPHC and records
a note receivable from BPHC for the amounts paid, which is settled quarterly.
The notes accrue interest at London Interbank Offered Rate plus one
percent.  For the three months ended March 31, 2008 and 2007, the
Partnership paid $0.1 million and less than $0.1 million on behalf of BPHC. A
note receivable of $1.9 million remained at March 31, 2008.
 
 
 Note
13:  Accumulated Other Comprehensive Income (Loss)
 
 The following table shows the
components of Accumulated other comprehensive income, net of tax which is
included in Partners’ Capital on the Condensed Consolidated Balance Sheets (in
millions):
 
 As
      of
              
              
              As
      ofMarch
      31, 2008
              
              
              December
      31, 2007Loss
      on cash flow hedges
              
              $
              (32.7
              )
              
              $
              (8.9
              )Deferred
      components of net periodic benefit cost
              
              
              10.9
              
              
              
              13.1Total
      Accumulated other comprehensive (loss) income
              
              $
              (21.8
              )
              
              $
              4.2
 
 18
 
 Note
14:  Guarantee of Securities of Subsidiaries
 
 The
Partnership has no independent assets or operations other than its investment in
its subsidiaries. The Partnership’s operating subsidiaries have issued
securities which have all been fully and unconditionally guaranteed by the
Partnership. The Partnership does have separate partners’ capital including
publicly traded limited partner common units.
 
 The Partnership’s subsidiaries have no
significant restrictions on their ability to pay distributions or make loans to
the Partnership and had no restricted assets at March 31,
2008.
 
 
 Note
15:  Recently Issued Accounting Pronouncements
 
  In March
2008, the FASB issued SFAS No. 161, Disclosures about Derivative
Instruments and Hedging Activities,which requires entities to provide
enhanced disclosures about (a) how and why the entity uses derivative
instruments, (b) how derivative instruments and related hedged items are
accounted for under SFAS No. 133 and its related interpretations, and (c) how
derivative instruments and related hedged items affect the entity’s financial
position, financial performance, and cash flows. SFAS No. 161 is effective for
fiscal years and interim periods beginning after November 15, 2008. The
Partnership is evaluating the effect that SFAS No. 161 will have on its
financial statements.
   In March 2008 the FASB
approved EITF Issue No. 07-4,  Application of the Two-Class Method
under FASB Statement No. 128, Earnings per Share, to Master Limited
Partnerships, which requires that master limited partnerships use the
two-class method of allocating earnings to calculate earnings per
unit. EITF Issue No. 07-4 is effective for fiscal years and interim periods
beginning after December 15, 2008. The Partnership is evaluating the effect
that EITF Issue No. 07-4 will have on its earnings per unit and financial
statements.
   
  Note
16:  Subsequent Events
 
 On April
24, 2008, the Partnership entered into a Class B Unit Purchase Agreement (the
Purchase Agreement) to issue and sell approximately 22.9 million of the newly
created class B units representing limited partner interests (class B units) to
BPHC for $30 per class B unit, or an aggregate purchase price of $686 million.
The Partnership’s general partner will also contribute $14 million to the
Partnership to maintain its 2% general partner interest. The Purchase Agreement
has been approved by the Board of Directors and the Conflicts Committee of the
Partnership’s general partner. The Partnership expects to close this transaction
on or about June 17, 2008 and intends to use the proceeds of approximately $700
million to fund a portion of the costs of its ongoing expansion
projects.
 
 Beginning
with the distribution in respect of the quarter ending September 30, 2008, the
class B units will share in quarterly distributions of available cash from
operating surplus on a pari passu basis with the Partnership’s common units,
until each common unit and class B unit has received a quarterly distribution of
$0.30. The class B units will not participate in quarterly distributions above
$0.30 per unit. The class B units will be convertible into common units by the
holder on a one-for-one basis at any time after June 30, 2013.
 
 The class
B units will represent a separate class of the Partnership’s limited partner
interests. The class B units will have the same voting rights as if they were
outstanding common units and will be 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, at the time of closing of the sale of
the class B units, the Partnership will enter into a Registration Rights
Agreement with BPHC covering the common units into which the class B units will
be convertible.
  19
  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 to own and operate the business conducted by Boardwalk Pipelines,
LP (Boardwalk Pipelines) and its subsidiaries, Gulf South Pipeline Company, LP
(Gulf South) and Texas Gas Transmission, LLC (Texas Gas) (together, operating
subsidiaries). Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned
subsidiary of Loews Corporation (Loews), owns 53.3 million of our common units
and 33.1 million of our subordinated units, constituting approximately 68% of
our partners’ equity. Boardwalk GP, LP (Boardwalk GP), an indirect, wholly-owned
subsidiary of BPHC, is our general partner and holds a 2% general partner
interest and all of our incentive distribution rights. Our common units are
traded under the symbol “BWP” on the New York Stock Exchange.
 
 
 Results
of Operations – Business Overview
 
 We derive
our revenues primarily from the interstate transportation and storage of natural
gas for third parties. Transportation and storage services are provided under
firm and interruptible service agreements. Transportation rates are subject to
maximum tariff rates established by the Federal Energy Regulatory Commission
(FERC), although discounts from the maximum allowable cost-based rates are often
granted to customers due to competition in the marketplace.Our Gulf
South subsidiary is authorized to charge market-based rates for its firm and
interruptible storage services. In first quarter 2008, our Texas Gas subsidiary
was provided authority 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, whereby 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, whereby 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 and southeastern United States through interconnections with
unaffiliated pipelines.
 
 20
 Our business is affected by trends
involving natural gas price levels and natural gas price spreads, including
spreads between physical locations on our pipeline system, which affects our
transportation revenues, and spreads in natural gas prices across time (for
example summer to winter), which primarily affects our PAL and storage revenues.
High natural gas prices in recent years have helped to drive increased
production levels in producing locations such as the Bossier Sands and Barnett
Shale gas producing regions in East Texas, which has resulted in additional
supply being available on the west side of our system. This has resulted in
widened west-to-east basis differentials which have benefited our transportation
revenues. The high natural gas prices have also driven increased production in
regions such as the Fayetteville Shale in Arkansas and the Caney Woodford Shale
in Oklahoma, which, together with the higher production levels in East Texas,
have formed the basis for several pipeline expansion projects including those
being undertaken by us. Wide spreads in natural gas prices between time periods
during the past two to three years, for example fall 2006 to spring 2007, were
favorable for our PAL and interruptible storage services during that period.
These spreads decreased substantially in 2007 and have continued to decrease
into the first quarter 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 March 31, 2008 and 2007
 
 Ournet
income for the first quarter 2008, increased $7.9 million, or 10%, from the
comparable period in 2007. The primary drivers for the increase were higher
revenues from firm transportation services associated with our East Texas to
Mississippi Pipeline Expansion project and a gain from the settlement of a
contract claim. The favorable drivers were partly offset by higher depreciation
and property taxes due to an increase in our asset base from expansion and lower
PAL revenues due to lower natural gas price spreads.
 
 Operating
revenues increased $9.2 million, or 5%, to $197.3 million for the first quarter
2008, compared to $188.1 million for the first quarter 2007, primarily due
to:
 
 ·
              $16.8
      million increase in gas transportation revenues, excluding fuel, $10.9
      million of which was generated by the East Texas to Mississippi Pipeline
      Expansion project for which we began providing services in the first
      quarter 2008, and the remainder of which was due to increased rates on
      firm transportation services from contracts that had expired in 2007 and
      were recontracted at the maximum allowable rates, increased interruptible
      transportation revenues and higher
throughput;
 ·
              $2.2
      million increase in fuel revenues mainly driven by the East Texas to
      Mississippi Pipeline Expansion project;
and
 ·
              $10.3
      million decrease in PAL revenues due to lower natural gas price spreads,
      partly offset by increased firm storage rates and revenues from Phase II
      of the Western Kentucky Storage Expansion project which was placed in
      service in November 2007.
 
 Operating
costs and expenses were unchanged at $95.8 million for the first quarter 2008
and 2007, primarily due to:
 
 ·
              $11.5
      million increase in depreciation and property taxes primarily due to an
      increase in our asset base from expansion;
and
 ·
              $11.2
      million decrease due to a gain from the settlement of a contract claim in
      the Calpine Bankruptcy case.
 
 Total
other deductions increased by $1.2 million, or 10%, to $13.1 million for the
first quarter 2008, compared to $11.9 million for the first quarter 2007. The
increase is primarily due to an increase in interest expense due to issuances of
new debt, partially offset by a $3.1 million gain from the mark-to-market effect
of derivatives associated with the purchase of line pack for our pipeline
expansion projects and higher allowance for equity funds used during
construction related to the construction of our pipeline expansion
projects.
 
 
  21
  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
engaged in several pipeline expansion projects, described below, and expect the
estimated total cost of these projects to be as follows (in
millions):
 Initial
      Project Cost
              
              
              Subsequent
      Expansion Cost
              
              
              Total
      Project Cost
              
              
              Cash
      Invested through March 31, 2008East
      Texas to Mississippi Expansion
              
              $
              960
              
              
              
              -
              
              
              $
              960
              
              
              $
              916.1Southeast
      Expansion
              
              
              775
              
              
              
              -
              
              
              
              775
              
              
              
              394.8Gulf
      Crossing Project
              
              
              1,690
              
              
              
              -
              
              
              
              1,690
              
              
              
              256.2Fayetteville
      and Greenville Laterals
              
              
              1,075
              
              
              $
              175
              (a)
              
              
              1,250
              
              
              
              167.8Total
              
              $
              4,500
              
              
              $
              175
              
              
              $
              4,675
              
              
              $
              1,734.9
 
 (a)
              Related
      to the addition of compression to increase the transmission capacity from
      0.8 billion cubic feet (Bcf) per day to approximately 1.2 Bcf per day on
      the Fayetteville Lateral and 1.0 Bcf per day on the Greenville Lateral,
      described more fully below. We expect the compression to be in service in
      2010.
 
 We expect to
incur expansion project capital expenditures of approximately $2.4 billion for
the remainder of 2008 and $0.6 billion in 2009 and 2010 to complete our pipeline
expansion projects, based upon our current cost estimates. We expect to finance
our pipeline expansion capital costs through equity financings and the
incurrence of debt, including sales of debt by us and our subsidiaries and
borrowings under our revolving credit facility, as well as available operating
cash flow in excess of our operating needs.
 
 Our total
estimated cost assumes that we will receive the necessary regulatory approvals
to commence construction by June 1, 2008 on Gulf Crossing and the Fayetteville
and Greenville Laterals and that we will receive the regulatory approvals
necessary to operate the pipelines on certain of our projects at higher
pressures, which will allow us to utilize a higher percentage of the pipeline
capacity. Delays in receipt of any of these approvals will result in higher
costs and additional delays in our expected in-service dates, which would also
result in delays of revenues we would have received had these delays not
occurred, and in certain instances will result in the payment of penalties to
certain customers. Our cost and timing estimates for these projects are subject
to a variety of other risks and uncertainties, including adverse weather
conditions, delays in obtaining key materials, shortages of qualified labor and
escalating costs of labor and materials. Please refer to Item 1A, Risk Factors, in our 2007
Form 10-K regarding risks associated with our expansion projects and the related
financing.
 
 The
following paragraphs describe each of our pipeline expansion projects in more
detail:
 
 East Texas to Mississippi
Expansion.  The pipeline and two of the three compression
facilities are now in service for our East Texas to Mississippi expansion, which
project consists of approximately 242 miles of 42-inch pipeline from DeSoto
Parish in western Louisiana to near Harrisville, Mississippi and approximately
110,000 horsepower of new compression having approximately 1.7 Bcf of new
peak-day transmission capacity. We are serving the full contract demand which
consists of customers that have contracted at fixed rates for 1.4 Bcf per day of
firm transportation capacity on a long-term basis (with a weighted average term
of approximately 6.8 years) which represents substantially all of the normal
operating capacity. We are in the process of commissioning the remaining
compression facility associated with this project, which we expect to be
completed during the second quarter 2008.
 
 22
  Southeast
Expansion.  In September 2007, the FERC granted us the
authority to construct, own and operate a pipeline expansion originating near
Harrisville, Mississippi and extending to an interconnect with Transcontinental
Pipe Line Company (Transco) in Choctaw County, Alabama (Transco 85). This
expansion will initially consist of approximately 112 miles of 42-inch pipeline
having approximately 1.2 Bcf of peak-day transmission capacity. To accommodate
volumes expected to come from the Gulf Crossing leased capacity discussed below,
this project will be expanded to up to 2.2 Bcf of peak-day transmission
capacity. In addition, the FERC approved our 260 million cubic feet (MMcf) per
day operating lease with Destin Pipeline Company which will provide us enhanced
access to markets in Florida. Customers have contracted at fixed rates for 660
MMcf per day of firm transportation capacity on a long-term basis (with a
weighted-average term of 9.2 years), in addition to the capacity leased to Gulf
Crossing discussed below. Construction has commenced and we expect the initial
1.2 Bcf of capacity to be in service during the second quarter 2008. We expect
the remaining capacity to be in service during the first quarter
2009.
 
 Gulf Crossing Project.We are
pursuing the construction of a new interstate pipeline that will begin near
Sherman, Texas and proceed to the Perryville, Louisiana area. The project will
be owned by Gulf Crossing Pipeline Company LLC, our newly formed interstate
pipeline subsidiary, and will consist of approximately 357 miles of 42-inch
pipeline having up to approximately 1.7 Bcf of peak-day transmission capacity.
Additionally, Gulf Crossing has entered into, subject to regulatory approval:
(i) an operating lease for up to 1.4 Bcf per day of capacity on our Gulf South
pipeline system (including capacity on the Southeast Expansion and capacity on a
portion of the East Texas to Mississippi Expansion) to make deliveries to an
interconnect with Transco 85; and (ii) an operating lease with Enogex, a
third-party intrastate pipeline, which will bring certain gas supplies to our
system. Customers have contracted at fixed rates for 1.1 Bcf per day of
long-term firm transportation capacity (with a weighted average term of
approximately 9.5 years). The Final Environmental Impact Statement was received
in the first quarter 2008, and we are awaiting the certificate to commence
construction of the project. We expect this project to be in service during the
first quarter 2009.
 
 Fayetteville and Greenville
Laterals.   We are pursuing the construction of two
laterals connected to 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 consisting of
approximately 95 miles of 36-inch pipeline. The Greenville Lateral will allow
customers to access additional markets, primarily in the Midwest, Northeast and
Southeast. This project had an initial design capacity of 0.8 Bcf of peak-day
transmission capacity which did not include compression facilities. We recently
executed contracts for additional capacity that would require us to add
compression to the project to increase the peak-day transmission capacity from
0.8 Bcf to approximately 1.2 Bcf for the Fayetteville Lateral and from
approximately 0.8 to approximately 1.0 Bcf for the Greenville
Lateral.
 
 Including
the new capacity, the contracts on the Fayetteville Lateral provide, after
phase-in periods through 2012, for 975 MMcf per day of initial capacity, with
options for additional capacity that, if exercised, could add 225 MMcf per day
of capacity. On the Greenville Lateral, contracts for 818 MMcf per day of
initial capacity are phased in through 2012 with options for additional capacity
that, if exercised, could add 172 MMcf per day of capacity. The contracts
associated with this project are at fixed rates with a weighted average term of
9.9 years. The Final Environmental Impact Statement was received in the first
quarter 2008 and we are awaiting the certificate to commence construction of the
project. We expect the first 60 miles of the Fayetteville Lateral to be in
service during the third quarter 2008 and the remainder of the pipeline related
to the Fayetteville and Greenville Laterals to be in service during the first
quarter 2009. We expect to make additional filings with FERC regarding the
additional compression required to increase the peak-day transmission capacity
and expect the additional capacity to be in service during 2010.
 
 23
  In addition to the
pipeline expansion projects described above, we are currently engaged in the
following storage expansion project:
 
 Western Kentucky Storage Expansion
Phase III.  In February 2008, the FERC granted us authority to
develop up to 8.3 Bcf of new working gas capacity and granted 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 2008. The total estimated cost of this
project assuming that we develop the 8.3 Bcf of working gas capacity, is
expected to be approximately $87.8 million. Through March 31, 2008, we have
spent $3.7 million related to this project.
 
 
 Maintenance
Capital Expenditures
 
 Maintenance capital expenditures for
the three months ended March 31, 2008 and 2007 were $5.2 million and $7.0
million. We expect to fund the remaining 2008 maintenance capital expenditures
of approximately $57.4 million from our operating cash flows.
 
 
 Distributions
 
 For the three months ended March 31,
2008 and 2007 we paid distributions of $59.6 million and $46.1 million. Please
see Note 7 in Part 1 in Item 1 of this report for further
discussion.
 
 
 Equity
and Debt Financing
 
 On April
24, 2008, we entered into a Class B Unit Purchase Agreement (the Purchase
Agreement) to issue and sell approximately 22.9 million of our newly created
class B units representing limited partner interests (class B units) to BPHC for
$30 per class B unit, or an aggregate purchase price of $686 million. Our
general partner will also contribute $14 million to us to maintain its 2%
general partner interest. The Purchase Agreement has been approved by the Board
of Directors and the Conflicts Committee of our general partner. We expect to
close this transaction on or about June 17, 2008 and intend to use the proceeds
of approximately $700 million to fund a portion of the costs of our ongoing
expansion projects.
 
 Beginning
with the distribution in respect of the quarter ending September 30, 2008, the
class B units will share in quarterly distributions of available cash from
operating surplus on a pari passu basis with our common units, until each common
unit and class B unit has received a quarterly distribution of $0.30. The class
B units will not participate in quarterly distributions above $0.30 per unit.
The class B units will be convertible into common units by the holder on a
one-for-one basis at any time after June 30, 2013.
 
 The class
B units will represent a separate class of our limited partner interests. The
class B units will have the same voting rights as if they were outstanding
common units and will be 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, at the time of closing of the sale of the
class B units, we will enter into a Registration Rights Agreement with BPHC
covering the common units into which the class B units will be
convertible.
 
 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.
 
 
  24
  Revolving
Credit Facility
 
 We
maintain a $1.0 billion revolving credit facility under which Boardwalk
Pipelines, Gulf South and Texas Gas each may borrow funds, up to applicable
sub-limits. Interest on amounts drawn under the credit facility is payable at a
floating rate equal to an applicable spread per annum over the London Interbank
Offered Rate or a base rate defined as the greater of the prime rate or the
Federal funds rate plus 50 basis points. Under the terms of the agreement, each
of the borrowers must maintain a minimum ratio, as of the last day of each
fiscal quarter, of consolidated total debt to consolidated earnings before
income taxes, depreciation and amortization (as defined in the agreement),
measured for the preceding twelve months, of not more than five to
one.  The revolving credit facility has a maturity date of June 29,
2012.
 
 During
the three month period ended March 31, 2008, we borrowed and repaid $153.0
million under the facility. The interest rates on the borrowings ranged from
2.76% to 3.35%. As of March 31, 2008, we were in compliance with all covenant
requirements under our credit agreement and no funds were drawn under this
facility, however, at March 31, 2008, we had outstanding letters of credit under
the facility for $95.9 million to support certain obligations associated with
the pipeline expansion projects which reduced the available capacity under the
facility by such amount.
 
 
 Changes
in cash flow from operating activities
  Net cash
provided by operating activities increased $12.0 million, or 16%, to $89.3
million for the three months ended March 31, 2008, compared to $77.3 million for
the comparable 2007 period, primarily due to an increase in net income excluding
non-cash items such as depreciation and amortization and the recognition of
income previously deferred.
 
 
 Changes
in cash flow from investing activities
  Net cash
used in investing activities increased $381.8 million to $542.8 million for the
three months ended March 31, 2008, compared to $161.0 million for the comparable
2007 period, primarily due to capital expenditures related to our expansion
projects.
 
 
 Changes
in cash flow from financing activities
  Net cash
provided by financing activities decreased $75.2 million to $172.6 million for
the three months ended March 31, 2008, compared to $247.8 million for the
comparable 2007 period, primarily due to:
 
 ·
              $293.9
      million decrease in net proceeds from the sale of common units and related
      general partner capital contributions in
2007;
 ·
              $15.0
      million decrease in cash due to the settlement of treasury locks in
      2008;
 ·
              $13.5
      million decrease in cash from an increase in distributions;
      and
 ·
              $247.2
      million increase in net proceeds from the issuance of long term debt in
      March 2008.
 
 
 Contractual
Obligations
  The table below is updated for
significant changes in contractual cash payment obligations as of March 31,
2008, by period (in millions):
  25
  
 Total
              
              
              Less than
                1
      Year
              
              
              1-3 Years
              
              
              4-5 Years
              
              
              More
      than 5 YearsPrincipal
      payments on long-term debt
              
              $
              2,110.0
              
              
              
              -
              
              
              
              -
              
              
              $
              225.0
              
              
              $
              1,885.0Interest
      on long-term debt
              
              
              999.0
              
              
              $
              77.4
              
              
              $
              234.9
              
              
              
              234.9
              
              
              
              451.8Capital
      commitments
              
              
              597.8
              
              
              
              573.7
              
              
              
              24.1
              
              
              
              -
              
              
              
              -Total
              
              $
              3,706.8
              
              
              $
              651.1
              
              
              $
              259.0
              
              
              $
              459.9
              
              
              $
              2,336.8
 
 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 March 31, 2008, relating to our expansion
projects. For information on these projects, please read “Expansion Capital
Expenditures” above.
 
 
 Off-Balance
Sheet Arrangements
  At March 31, 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 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 first quarter 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.
 
 26
 Forward-looking statements are based on
current expectations and projections about future events and are inherently
subject to a variety of risks and uncertainties, many of which are beyond our
control that could cause actual results to differ materially from those
anticipated or projected. These risks and uncertainties include, among
others:
 
 ·
              We
      may not complete projects, including growth or expansion projects, that we
      have commenced or will commence, or we may complete projects on materially
      different terms, cost or timing than anticipated and we may not be able to
      achieve the intended economic or operational benefits of any such project,
      if completed.
 
 ·
              The
      successful completion, timing, cost, scope and future financial
      performance of our expansion projects could differ materially from our
      expectations due to availability of contractors or equipment, weather,
      difficulties or delays in obtaining regulatory approvals or denied
      applications, land owner opposition, the lack of adequate materials, labor
      difficulties or shortages, expansion costs that are higher than
      anticipated and numerous other factors beyond our
  control.
 
 ·
              We
      may not complete any future debt or equity financing
      transaction.
 
 ·
              The
      gas transmission and storage operations of our subsidiaries are subject to
      rate-making policies and actions by the FERC or customers that could have
      an adverse impact on the rates we charge and our ability to recover our
      income tax allowance, our full cost of operating our pipelines and a
      reasonable return.
 
 ·
              We
      are subject to laws and regulations relating to the environment and
      pipeline operations which may expose us to significant costs, liabilities
      and loss of revenues. Any changes in such regulations or their application
      could negatively affect our business, financial condition and results of
      operations.
 
 ·
              Our
      operations are subject to operational hazards and unforeseen interruptions
      for which we may not be adequately
insured.
 
 ·
              The
      cost of insuring our assets may increase
  dramatically.
 
 ·
              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.
 
 ·
              Successful
      development of LNG import terminals in the eastern or northeastern United
      States could reduce the demand for our
services.
 
 ·
              We
      may not be able to maintain or replace expiring gas transportation and
      storage contracts at favorable
rates.
 
 ·
              Significant
      changes in natural gas prices could affect supply and demand, reducing
      system throughput and adversely affecting our
  revenues.
 
 Developments in any of these areas
could cause our results to differ materially from results that have been or may
be anticipated or projected. Forward-looking statements speak only as of the
date of this report and we expressly disclaim any obligation or undertaking to
update these statements to reflect any change in our expectations or beliefs or
any change in events, conditions or circumstances on which any forward-looking
statement is based.
 
 
  27
  Item 3.  Quantitative and Qualitative Disclosures About Market
Risk
 
 Our debt has been issued at fixed
rates, therefore interest expense would not be impacted by changes in interest
rates. Total
long-term debt at March 31, 2008, had a carrying value of $2.1 billion and a
fair value of $2.0 billion.A 100 basis point increase in interest rates
on our fixed rate debt would result in a decrease in fair value of approximately
$126.7 million at March 31, 2008. A 100 basis point decrease would result in an
increase in fair value of approximately $137.2 million at March 31, 2008. The weighted-average
interest rate of our long-term debt was 5.88% at March 31,
2008.
 
 Certain
volumes of our gas stored underground are available for sale and subject to
commodity price risk. At March 31, 2008 and December 31, 2007 approximately
$22.9 million and $16.3 million of gas stored underground, which we own and
carry as current Gas stored underground, is exposed to commodity price risk. We
utilize derivatives to hedge certain exposures to market price fluctuations on
the anticipated operational sales of gas.
 
 As a
result of the approval of Phase III of the Western Kentucky storage expansion
project in March 2008, approximately 5.1 Bcf of gas stored underground with a
book value of $11.8 million became available for sale. We entered into
derivatives to hedge the price exposure related to the expected sale of this
gas, which derivatives were designated as cash flow hedges.
 
 In the
second quarter 2007, we entered into natural gas price swaps to hedge exposure
to prices associated with the purchase of 2.1 Bcf of natural gas to be used for
line pack for our Gulf Crossing and Southeast expansion projects, approximately
1.3 Bcf of which remained outstanding at March 31, 2008. The derivatives were
not designated as hedges and were marked to fair value through earnings
resulting in a gain of $3.1 million for the three months ended March 31, 2008.
Changes in the fair value of the derivatives will be recognized in earnings each
quarter until settlement. The changes in the fair value of the gas purchased for
line pack will not be recognized in earnings each quarter. When the gas is
purchased, the ultimate cost will be recorded to Property, Plant and Equipment
along with the other capital components of the projects and recognized in
earnings as the property is depreciated. A $1.00 increase in the price of New
York Mercantile Exchange natural gas futures, would result in the recognition of
a $1.3 million gain in earnings. Conversely, a $1.00 decrease would result in
the recognition of a $1.3 million loss.
 
 With the
exception of the derivatives related to certain storage gas volumes related to
Phase II of the Western Kentucky storage expansion project and line pack gas
purchases referred to above, the derivatives related to the sale or purchase of
natural gas, cash for fuel reimbursement and debt issuance generally qualify for
cash flow hedge accounting under Statement of Financial Accounting Standards No.
133 and are designated as such. The effective component of related unrealized
gains and losses resulting from changes in fair values of the derivatives
contracts designated as cash flow hedges are deferred as a component of
Accumulated other comprehensive income. The deferred gains and losses are
recognized in the Condensed Consolidated Statements of Income when the
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. For the sale of gas related to Phase II of the
Western Kentucky storage expansion project, any gains and losses on the related
derivatives would be recognized in Net gain on disposal of operating assets and
related contracts. Any gains and losses on the derivatives related to the line
pack gas purchases would be recognized in Miscellaneous other income,
net.
 
 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 March 31, 2008, the amount of gas loaned out
by our subsidiaries was approximately 37.8 trillion British thermal units (TBtu)
and the amount considered an imbalance was approximately 3.6 TBtu. Assuming an
average market price during March 2008 of $9.32 per million British thermal
units (MMBtu), the market value of gas loaned out and considered an imbalance at
March 31, 2008, would have been approximately $385.2 million. As of December 31,
2007, the amount of gas loaned out by our subsidiaries was approximately 12.7
TBtu and the amount considered an imbalance was approximately 2.5 TBtu. Assuming
an average market price during December 2007 of $7.13 per MMBtu, the market
value of gas loaned out at December 31, 2007 would have been approximately
$108.2 million.  If any significant customer of ours should have
credit or financial problems resulting in a delay or failure to repay the gas
they owe to us, this could have a material adverse effect on our financial
condition, results of operations and cash flows.
 
 As of March 31, 2008, our cash and cash
equivalents were invested primarily in mutual funds. 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.
 
 
 
  28
  Item 4.  Controls and Procedures
 
 Disclosure
Controls and Procedures
 
 We
maintain a system of disclosure controls and procedures which is designed to
ensure that information required to be disclosed by us in reports that we file
or submit under the federal securities laws, including this report is recorded,
processed, summarized and reported on a timely basis. These disclosure controls
and procedures include controls and procedures designed to ensure that
information required to be disclosed by us under the federal securities laws is
accumulated and communicated to us on a timely basis to allow decisions
regarding required disclosure.
 
 Our
principal executive officer (CEO) and principal financial officer (CFO)
undertook an evaluation of our disclosure controls and procedures as of the end
of the period covered by this report. The CEO and CFO have concluded that our
controls and procedures were effective as of March 31, 2008.
 
 Changes
in Internal Control over Financial Reporting
 
 There
were no changes in our internal control over financial reporting that occurred
during the first quarter 2008, that have materially affected or that are
reasonably likely to materially affect our internal control over financial
reporting.
 
 
  29
  PART
II – OTHER INFORMATION
 
 Item 1.  Legal Proceedings
 
 For a discussion of certain of our
current legal proceedings, please read Note 6 of the Notes to Condensed
Consolidated Financial Statements in Item 1 of this Report.
 
 
 Item 2.  Unregistered Sales of Equity Securities and Use of
Proceeds
  On March 25, 2008, our general partner
purchased 1,500 of our common units in the open market at a price of $23.78 per
unit.  These units were granted to our independent directors as part of
their director compensation.
  30
  Item 6.  Exhibits
 
 
 
 Exhibit
                NumberDescription
 
 3.1
              
              Amendment
      No. 1 to Second Amended and Restated Agreement of Limited Partnership of
      Boardwalk Pipeline Partners, LP, effective as of January 1, 2007.
      (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current
      Report on Form 8-K filed on April 11, 2008).4.1
              
              Indenture
      dated March 27, 2008, between Texas Gas Transmission, LLC and the Bank of
      New York Trust Company, N.A. (Incorporated by reference to Exhibit 4.1 to
      the Registrant’s Current Report on Form 8-K filed on March 27,
      2008).*10.1
              
              Amendment
      No. 3 to Amended and Restated Revolving Credit Agreement, dated as of
      March 6, 2008, among the Registrant, Boardwalk Pipelines, LP, Texas Gas
      Transmission, LLC and Gulf South Pipeline Company, LP, and the agent and
      lender parties identified therein.*10.2
              
              Separation
      Agreement and General Release between H. Dean Jones II and Texas Gas
      Transmission, LLC, Boardwalk GL, LLC, Boardwalk Pipelines Holding Corp.
      and Boardwalk Operating GP, LLC.*31.1
              
              Certification
      of Rolf A. Gafvert, Chief Executive Officer, pursuant to Rule 13a-14(a)
      and Rule 15d-14(a).*31.2
              
              Certification
      of Jamie L. Buskill, Chief Financial Officer, pursuant to Rule 13a-14(a)
      and Rule 15d-14(a).*32.1
              
              Certification
      of Rolf A. Gafvert, Chief Executive Officer, pursuant to Section 906 of
      the Sarbanes-Oxley Act of 2002.*32.2
              
              Certification
      of Jamie L. Buskill, Chief Financial Officer, pursuant to Section 906 of
      the Sarbanes-Oxley Act of 2002.*
      Filed herewith
  31
  SIGNATURES
 
 Pursuant to the requirements of the
Securities Exchange Act of 1934, the Registrant has duly caused this report to
be signed on its behalf by the undersigned, thereunto duly
authorized.
 
 Boardwalk
      Pipeline Partners, LPBy:
      Boardwalk GP, LPits
      general partnerBy:
      Boardwalk GP, LLCits
      general partnerDated:
      April 29, 2008
              
              By:
              /s/
      Jamie L. BuskillJamie
      L. BuskillSenior
      Vice President, Chief Financial Officer and
  Treasurer