Boardwalk Pipeline Partners (BWP) 10-Q 2011 Q3 Quarterly report

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 September 30, 2011

OR

o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

   For the transition period from _______________ to _______________

Commission file number:      01-32665
BOARDWALK PIPELINE PARTNERS, LP
(Exact name of registrant as specified in its charter)
DELAWARE
(State or other jurisdiction of incorporation or organization)
20-3265614
(I.R.S. Employer Identification No.)
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 registered
Common Units Representing Limited Partner Interests	New York Stock Exchange
Securities 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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 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 November 1, 2011, the registrant had 175,721,916 common units outstanding and 22,866,667 class B units outstanding.

TABLE OF CONTENTS

 FORM 10-Q

September 30, 2011

BOARDWALK PIPELINE PARTNERS, LP

PART I - FINANCIAL INFORMATION

PART II - OTHER INFORMATION

2

PART I – FINANCIAL INFORMATION

Item 1.  Financial Statements

 BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Millions)

(Unaudited)

ASSETS	September 30, 2011		December 31, 2010
Current Assets:
Cash and cash equivalents	$	84.2	$	55.0
Receivables:
Trade, net		84.1		101.0
Affiliate		0.8		-
Other		17.7		5.2
Gas transportation receivables		7.6		12.2
Costs recoverable from customers		10.0		11.3
Gas stored underground		8.0		3.6
Prepayments		16.0		11.4
Other current assets		4.3		3.5
Total current assets		232.7		203.2
Property, Plant and Equipment:
Natural gas transmission and other plant		6,992.4		6,933.9
Construction work in progress		127.9		109.9
Property, plant and equipment, gross		7,120.3		7,043.8
Less—accumulated depreciation and amortization		933.5		785.8
Property, plant and equipment, net		6,186.8		6,258.0
Other Assets:
Goodwill		163.5		163.5
Gas stored underground		119.3		125.8
Costs recoverable from customers		15.4		15.7
Other		87.1		111.8
Total other assets		385.3		416.8
Total Assets	$	6,804.8	$	6,878.0

The accompanying notes are an integral part of these condensed consolidated financial statements.

3

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Millions)

(Unaudited)

LIABILITIES AND PARTNERS’ CAPITAL	September 30,  2011			December 31, 2010
Current Liabilities:
Payables:
Trade	$	30.5		$	48.8
Affiliate		3.1			3.2
Other		5.9			10.1
Gas Payables:
Transportation		11.6			20.5
Storage		6.1			4.2
Accrued taxes, other		60.5			40.4
Accrued interest		27.2			40.5
Accrued payroll and employee benefits		17.7			17.0
Construction retainage		4.3			8.3
Deferred income		3.3			6.3
Other current liabilities		15.2			14.5
Total current liabilities		185.4			213.8
Long–term debt		3,098.2			3,152.3
Long–term debt – affiliate		100.0			100.0
Total long-term debt		3,198.2			3,252.3
Other Liabilities and Deferred Credits:
Pension liability		21.1			27.0
Asset retirement obligation		16.5			17.2
Provision for other asset retirement		53.7			51.7
Payable to affiliate		16.0			16.0
Other		66.5			58.6
Total other liabilities and deferred credits		173.8			170.5
Commitments and Contingencies
Partners’ Capital:
Common units – 175.7 million and 169.7 million units issued and outstanding as of September 30, 2011 and December 31, 2010		2,547.1			2,534.4
Class B units – 22.9 million units issued and outstanding as of September 30, 2011 and December 31, 2010		677.8			683.6
General partner		62.9			62.9
Accumulated other comprehensive loss		(40.4	)		(39.5	)
Total partners’ capital		3,247.4			3,241.4
Total Liabilities and Partners’ Capital	$	6,804.8		$	6,878.0

The accompanying notes are an integral part of these condensed consolidated financial statements.

4

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Millions, except per unit amounts)

(Unaudited)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2011			2010			2011			2010
Operating Revenues:
Gas transportation	$	251.8		$	234.2		$	786.6		$	734.0
Parking and lending		2.2			5.5			8.5			23.8
Gas storage		12.0			13.1			37.5			41.5
Other		2.9			4.8			9.3			15.5
Total operating revenues		268.9			257.6			841.9			814.8
Operating Costs and Expenses:
Fuel and gas transportation		26.7			27.7			78.7			81.8
Operation and maintenance		45.9			36.8			123.1			100.2
Administrative and general		31.1			33.2			101.9			98.8
Depreciation and amortization		55.8			54.2			168.9			161.3
Asset impairment		0.1			3.3			28.6			5.8
Net gain on disposal of operating assets		(5.3	)		(12.7	)		(3.9	)		(11.6	)
Taxes other than income taxes		22.2			22.0			67.1			66.0
Total operating costs and expenses		176.5			164.5			564.4			502.3
Operating income		92.4			93.1			277.5			312.5
Other Deductions (Income):
Interest expense		37.6			35.3			113.5			106.2
Interest expense – affiliates		2.0			2.0			6.0			6.0
Loss on debt extinguishment		5.8			-			13.2			-
Interest income		(0.1	)		(0.2	)		(0.3	)		(0.5	)
Miscellaneous other income, net		(0.2	)		-			(0.6	)		(0.1	)
Total other deductions		45.1			37.1			131.8			111.6
Income before income taxes		47.3			56.0			145.7			200.9
Income taxes		0.1			0.2			0.3			0.4
Net Income	$	47.2		$	55.8		$	145.4		$	200.5
Net Income per Unit:
Basic and diluted net income per unit:
Common units	$	0.23		$	0.28		$	0.72		$	1.02
Class B units	$	-		$	0.07		$	0.04		$	0.39
Cash distribution declared and paid to common units	$	0.525		$	0.51		$	1.5675		$	1.515
Cash distribution declared and paid to class B units	$	0.30		$	0.30		$	0.90		$	0.90
Weighted-average number of units outstanding:
Common units		175.7			169.7			172.5			169.7
Class B units		22.9			22.9			22.9			22.9

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 Nine Months Ended September 30,
OPERATING ACTIVITIES:	2011			2010
Net income	$	145.4		$	200.5
Adjustments to reconcile to cash provided by operations:
Depreciation and amortization		168.9			161.3
Amortization of deferred costs		8.1			7.0
Asset impairment		28.6			5.8
Loss on debt extinguishment		13.2			-
Storage gas loss		3.7			-
Net gain on disposal of operating assets		(3.9	)		(11.6	)
Changes in operating assets and liabilities:
Trade and other receivables		13.8			13.2
Other receivables, affiliates		(0.8	)		-
Gas receivables and storage assets		(3.8	)		4.0
Costs recoverable from customers		(2.7	)		(4.1	)
Other assets		(13.1	)		5.5
Trade and other payables		(10.2	)		(24.1	)
Other payables, affiliates		(0.2	)		1.9
Gas payables		(0.8	)		5.9
Accrued liabilities		9.8			14.2
Other liabilities		(10.5	)		(24.7	)
Net cash provided by operating activities		345.5			354.8
INVESTING ACTIVITIES:
Capital expenditures		(116.9	)		(174.2	)
Proceeds from sale of operating assets		17.5			16.4
Net cash used in investing activities		(99.4	)		(157.8	)
FINANCING ACTIVITIES:
Proceeds from long-term debt, net of issuance costs		437.6			-
Repayment of borrowings from long-term debt		(250.0	)		-
Payments of premiums on extinguishment of long-term debt		(21.0	)		-
Proceeds from borrowings on revolving credit agreement		515.0			150.0
Repayment of borrowings on revolving credit agreement		(760.0	)		-
Payments on note payable		-			(0.3	)
Payments associated with registration rights agreement		-			(10.7	)
Advances from affiliate		-			3.9
Distributions paid		(312.1	)		(296.9	)
Proceeds from sale of common units		170.0			-
Capital contribution from general partner		3.6			-
Net cash used in financing activities		(216.9	)		(154.0	)
Increase in cash and cash equivalents		29.2			43.0
Cash and cash equivalents at beginning of period		55.0			45.8
Cash and cash equivalents at end of period	$	84.2		$	88.8

The accompanying notes are an integral part of these condensed consolidated financial statements.

6

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

PARTNERS’ CAPITAL

(Millions)

(Unaudited)

	Common Units			Class B Units			General Partner			Accumulated Other Comp Loss			Total Partners’ Capital
Balance January 1, 2010	$	2,640.5		$	683.6		$	65.5		$	(25.4	)	$	3,364.2
Add (deduct):
Net income		162.9			20.6			17.0			-			200.5
Distributions paid		(257.1	)		(20.6	)		(19.2	)		-			(296.9	)
Other comprehensive loss		-			-			-			(8.2	)		(8.2	)
Balance September 30, 2010	$	2,546.3		$	683.6		$	63.3		$	(33.6	)	$	3,259.6
Balance January 1, 2011	$	2,534.4		$	683.6		$	62.9		$	(39.5	)	$	3,241.4
Add (deduct):
Net income		111.7			14.8			18.9			-			145.4
Distributions paid		(269.0	)		(20.6	)		(22.5	)		-			(312.1	)
Sale of common units, net of related transactions costs		170.0			-			-			-			170.0
Capital contribution from general partner		-			-			3.6			-			3.6
Other comprehensive loss		-			-			-			(0.9	)		(0.9	)
Balance September 30, 2011	$	2,547.1		$	677.8		$	62.9		$	(40.4	)	$	3,247.4

The accompanying notes are an integral part of these condensed consolidated financial statements.

7

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Millions)

(Unaudited)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2011			2010			2011			2010
Net income	$	47.2		$	55.8		$	145.4		$	200.5
Other comprehensive income (loss):
Gain on cash flow hedges		1.5			1.3			2.9			7.6
Reclassification adjustment transferred to Net income from cash flow hedges		(0.2	)		(7.4	)		0.7			(11.2	)
Pension and other postretirement benefit costs		(1.5	)		(1.5	)		(4.5	)		(4.6	)
Total Comprehensive Income	$	47.0		$	48.2		$	144.5		$	192.3

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 its subsidiaries: Boardwalk Pipelines, LP (Boardwalk Pipelines), and its subsidiaries, Gulf Crossing Pipeline Company LLC (Gulf Crossing), Gulf South Pipeline Company, LP (Gulf South) and Texas Gas Transmission, LLC (Texas Gas) (together, the operating subsidiaries). As of September 30, 2011, Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned subsidiary of Loews Corporation (Loews), owned 102.7 million of the Partnership’s common units, all 22.9 million of the Partnership’s class B units and, through Boardwalk GP, LP (Boardwalk GP), an indirect wholly-owned subsidiary of BPHC, holds the 2% general partner interest and all of the incentive distribution rights (IDRs). As of September 30, 2011, the common units, class B units and general partner interest owned by BPHC represent approximately 64% of the Partnership’s equity interests, excluding the IDRs. 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 (GAAP) have been condensed or omitted pursuant to such rules and regulations. In the opinion of management, the accompanying condensed consolidated financial statements reflect all adjustments (consisting of only normal recurring accruals) necessary to present fairly the financial position as of September 30, 2011 and December 31, 2010, and the results of operations and comprehensive income for the three and nine months ended September 30, 2011 and 2010, and changes in cash flows and changes in partners’ capital for the nine months ended September 30, 2011 and 2010. Reference is made to the Notes to Consolidated Financial Statements in the 2010 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 Stored Underground and Gas Receivables and Payables

Gulf South and Texas Gas provide storage services whereby they store gas on behalf of customers and also periodically hold customer gas under parking and lending (PAL) services. Since the customers retain title to the gas held by the Partnership in providing these services, the Partnership does not record the related gas on its balance sheet. The Partnership held for storage or under PAL agreements approximately 74.9 trillion British thermal units (TBtu) of gas owned by third parties as of September 30, 2011. Assuming an average market price during September 2011 of $3.82 per million British thermal units (MMBtu), the market value of gas held on behalf of others was approximately $286.1 million. As of December 31, 2010, the Partnership held for storage or under PAL agreements approximately 82.9 TBtu of gas owned by third parties.

In the course of providing transportation and storage services to customers, the operating subsidiaries may receive different quantities of gas from shippers and operators than the quantities delivered on behalf of those shippers and operators. This results in transportation and exchange gas receivables and payables, commonly known as imbalances, which are settled in cash or the receipt or delivery of gas in the future. Gulf South and Texas Gas also periodically lend gas to customers under PAL services. As of September 30, 2011, the amount of gas owed to the operating subsidiaries due to gas imbalances and gas loaned under PAL agreements was approximately 8.5 TBtu. Assuming an average market price during September 2011 of $3.82 per MMBtu, the market value of that gas was approximately $32.5 million. As of December 31, 2010, the amount of gas owed to the operating subsidiaries due to gas imbalances and gas loaned under PAL agreements was approximately 13.0 TBtu. If any significant customer should have credit or financial problems resulting in a delay or failure to repay the gas owed to the operating subsidiaries, it could have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows.

9

Note 3:  Derivatives

Subsidiaries of the Partnership use futures, swaps and option contracts (collectively, derivatives) to hedge exposure to natural gas commodity price risk related to the future operational sales of natural gas and cash for fuel reimbursement where customers pay cash for the cost of fuel used in providing transportation services as opposed to having fuel retained in kind. This price risk exposure includes approximately $8.0 million and $3.6 million of gas stored underground at September 30, 2011 and December 31, 2010, which the Partnership owns and carries on its balance sheet as current Gas stored underground. Additionally, at December 31, 2010, the Partnership had 4.5 billion cubic feet (Bcf) of gas with a book value of $10.3 million that was available for sale as a result of a change in the storage working gas needed to support operations and no-notice services at its Texas Gas subsidiary, all of which was sold in 2011. At September 30, 2011, approximately 0.8 Bcf of anticipated future sales of natural gas and cash for fuel reimbursement were hedged with derivatives having settlement dates in 2011. The derivatives qualify for cash flow hedge accounting and are designated as such. The Partnership has also periodically used derivatives as cash flow hedges of interest rate risk in anticipation of debt offerings. The Partnership did not discontinue any cash flow hedges during the three and nine months ended September 30, 2011 and 2010.

All of the Partnership’s currently outstanding derivatives are reported at fair value based on New York Mercantile Exchange (NYMEX) quotes for natural gas futures and options. The NYMEX quotes are deemed to be observable inputs in an active market for similar assets and liabilities and are considered Level 2 inputs for purposes of fair value disclosures. The Partnership has not changed its valuation techniques or inputs during the reporting period.

The fair values of derivatives existing as of September 30, 2011 and December 31, 2010, were included in the following captions in the Condensed Consolidated Balance Sheets (in millions):

Asset Derivatives

Liability Derivatives

September 30, 2011

December 31, 2010

September 30, 2011

December 31, 2010

Balance sheet location

Fair Value

Balance  sheet  location

Fair Value

Balance sheet location

Fair Value

Balance sheet location

Fair Value

Derivatives designated as hedging instruments

Commodity contracts

Other current     assets

$

0.8

Other current     assets

$

-

Other current     liabilities

$

-

Other current     liabilities

$

1.7

10

The Partnership estimates that approximately $0.9 million of net losses reported in Accumulated other comprehensive income (loss) (AOCI) as of September 30, 2011, are expected to be reclassified into earnings within the next twelve months. The amount of gains and losses from derivatives recognized in the Condensed Consolidated Statements of Income for the three months ended September 30, 2011, were (in millions):

	Amount of gain/(loss) recognized in AOCI on derivatives (effective portion)		Location of gain/(loss) reclassified from AOCI into income (effective portion)	Amount of gain/(loss) reclassified from AOCI into income (effective portion)			Location of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)		Amount of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)
Derivatives in Cash Flow Hedging Relationship
Commodity contracts	$	1.0	Operating revenues (2)	$	0.4			N/A	$	-
Commodity contracts		0.5	Net gain(loss) on disposal of operating assets		0.2			N/A		-
Interest rate contracts (1)		-	Interest expense		(0.4	)		N/A		-
	$	1.5		$	0.2				$	-

(1)   Related to amounts deferred in AOCI from Treasury rate locks used in hedging interest payments associated with debt offerings that were settled in previous periods and are being amortized to earnings over the terms of the related interest payments, generally the terms of the related debt.  

(2)   $0.1 million was recorded in Gas transportation revenues and $0.3 million was recorded in Other revenues.

The amount of gains and losses from derivatives recognized in the Condensed Consolidated Statements of Income for the three months ended September 30, 2010, were (in millions):

	Amount of gain/(loss) recognized in AOCI on derivatives (effective portion)		Location of gain/(loss) reclassified from AOCI into income (effective portion)	Amount of gain/(loss) reclassified from AOCI into income (effective portion)			Location of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)		Amount of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)
Derivatives in Cash Flow Hedging Relationship
Commodity contracts	$	0.7	Operating revenues (2)	$	3.1			N/A	$	-
Commodity contracts		0.6	Net gain (loss) on disposal of operating assets		4.7			N/A		-
Interest rate contracts (1)		-	Interest expense		(0.4	)		N/A		-
	$	1.3		$	7.4				$	-

(1)   Related to amounts deferred in AOCI from Treasury rate locks used in hedging interest payments associated with debt offerings that were settled in previous periods and are being amortized to earnings over the terms of the related interest payments, generally the terms of the related debt.

(2)   $1.1 million was recorded in Gas transportation revenues and $2.0 million was recorded in Other revenues.  

11

The amount of gains and losses from derivatives recognized in the Condensed Consolidated Statements of Income for the nine months ended September 30, 2011, were (in millions):

	Amount of gain/(loss) recognized in AOCI on derivatives (effective portion)		Location of gain/(loss) reclassified from AOCI into income (effective portion)	Amount of gain/(loss) reclassified from AOCI into income (effective portion)			Location of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)		Amount of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)
Derivatives in Cash Flow Hedging Relationship
Commodity contracts	$	1.6	Operating revenues (2)	$	0.5			N/A	$	-
Commodity contracts		1.3	Net gain on disposal of operating assets		0.1			N/A		-
Interest rate contracts (1)		-	Interest expense		(1.3	)		N/A		-
	$	2.9		$	(0.7	)			$	-

(1)   Related to amounts deferred in AOCI from Treasury rate locks used in hedging interest payments associated with debt offerings that were settled in previous periods and are being amortized to earnings over the terms of the related interest payments, generally the terms of the related debt.

(2)   $0.2 million was recorded in Gas transportation revenues and $0.3 million was recorded in Other revenues.

The amount of gains and losses from derivatives recognized in the Condensed Consolidated Statements of Income for the nine months ended September 30, 2010, were (in millions):

	Amount of gain/(loss) recognized in AOCI on derivatives (effective portion)		Location of gain/(loss) reclassified from AOCI into income (effective portion)	Amount of gain/(loss) reclassified from AOCI into income (effective portion)			Location of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)		Amount of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)
Derivatives in Cash Flow Hedging Relationship
Commodity contracts	$	3.5	Operating revenues (2)	$	7.7			N/A	$	-
Commodity contracts		4.1	Net gain (loss) on disposal of operating assets		4.7			N/A		-
Interest rate contracts (1)		-	Interest expense		(1.2	)		N/A		-
	$	7.6		$	11.2				$	-

(1)   Related to amounts deferred in AOCI from Treasury rate locks used in hedging interest payments associated with debt offerings that were settled in previous periods and are being amortized to earnings over the terms of the related interest payments, generally the terms of the related debt.

(2)   $3.5 million was recorded in Gas transportation revenues and $4.2 million was recorded in Other revenues.

12

Note 4:  Income Taxes

The Partnership is not a taxable entity for federal income tax purposes. As such, it does not directly pay federal income tax. The Partnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the Condensed Consolidated Statements of Income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of the Partnership’s net assets for financial and income tax purposes cannot be readily determined as 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 5:Commitments and Contingencies

Legal Proceedings and Settlements

The Partnership's subsidiaries are parties to various legal actions arising in the normal course of business. Management believes the disposition of these outstanding legal actions will not have a material adverse impact on the Partnership's financial condition, results of operations or cash flows.

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. As of September 30, 2011 and December 31, 2010, the Partnership had an accrued liability of approximately $10.4 million and $11.2 million related to assessment and/or remediation costs associated with the historical use of polychlorinated biphenyls, petroleum hydrocarbons and mercury, groundwater protection measures and other costs. The liability 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. The related expenditures are expected to occur over the next ten years. As of September 30, 2011 and December 31, 2010, approximately $3.6 million was recorded in Other current liabilities for both periods and approximately $6.8 million and $7.6 million were recorded in Other Liabilities and Deferred Credits.

Clean Air Act

The Partnership’s pipelines are subject to the Clean Air Act (CAA) and the CAA Amendments of 1990 (Amendments) which added significant provisions to the CAA. The Amendments require the EPA to promulgate new regulations pertaining to mobile sources, air toxics, areas of ozone non-attainment, greenhouse gases and regulations affecting reciprocating engines subject to Maximum Achievable Control Technology (MACT). The operating subsidiaries presently operate two facilities in areas affected by non-attainment requirements for the current ozone standard (eight-hour standard). If the EPA designates additional new non-attainment areas or promulgates new air regulations where the Partnership operates, the cost of additions to property, plant and equipment is expected to increase. The Partnership has assessed the impact of the CAA on its facilities and does not believe compliance with these regulations will have a material impact on its financial condition, results of operations or cash flows.

In 2008, the EPA adopted regulations lowering the 8-hour ozone standard relevant to non-attainment areas. Under the regulations, new non-attainment areas will be identified which may require additional emission controls for compliance at as many as 12 facilities operated by the operating subsidiaries. The EPA is expected to finalize a new standard in 2011, which will lower the 8-hour ozone standard set in 2008 and set a compliance deadline between 2014 and 2031. The Partnership is currently evaluating its affected facilities to determine the costs necessary to comply with this standard.

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Beginning in 2011, the Partnership was required to file reports with the EPA regarding greenhouse gas emissions from its facilities, mainly its compressor stations, pursuant to final rules issued by the EPA regarding the reporting of greenhouse gas emissions from sources in the U.S. that annually emit 25,000 or more metric tons of greenhouse gases, including carbon dioxide, methane and others. As a result, the Partnership conducted various facility surveys across its entire system to comply with the EPA’s greenhouse gas emission calculations and reporting regulations.Some states have also adopted laws regulating greenhouse gas emissions, although none of the states in which the Partnership operates have adopted such laws. The new federal rules and determinations regarding greenhouse gas emissions have not had, and are not expected to have, a material effect on the Partnership’s financial condition, results of operations or cash flows.

In 2010, the EPA adopted regulations requiring further emission controls for air toxics, specifically formaldehyde, from certain compression engines utilizing MACT. The Partnership estimates that certain of its compression engines will require the installation of certain emission controls by late 2013. The Partnership does not believe the regulation will have a material effect on its financial condition, results of operations or cash flows.

Commitments for Construction

The Partnership’s future capital commitments are comprised of binding commitments under purchase orders for materials ordered but not received and firm commitments under binding construction service agreements existing at September 30, 2011. The commitments as of September 30, 2011, were approximately (in millions):

2011	$	31.1
2012		-
2013		-
2014		-
2015		-
Thereafter		-
Total	$	31.1

There were no substantial changes to the Partnership’s operating lease commitments or pipeline capacity agreements disclosed in Note 3 to the Partnership’s 2010 Annual Report on Form 10-K.

Note 6:  Cash Distributions and Net Income per Unit

Cash Distributions

The Partnership’s cash distribution policy requires that the Partnership distribute to its various ownership interests on a quarterly basis all of its available cash, as defined in its partnership agreement. IDRs, which represent a limited partner ownership interest and are currently held by the Partnership’s general partner, represent the contractual right to receive an increasing percentage of quarterly distributions of available cash as follows:

	Total Quarterly Distribution	Marginal Percentage Interest in Distributions
	Target Amount	Limited Partner Unitholders (1)	General  Partner and IDRs
First Target Distribution	up to $0.4025	98%	2%
Second Target Distribution	above $0.4025 up to $0.4375	85%	15%
Third Target Distribution	above $0.4375 up to $0.5250	75%	25%
Thereafter	above $0.5250	50%	50%

(1)   The class B unitholders participate in distributions on a pari passu basis with the Partnership’s common units up to $0.30 per unit per quarter. The class B units do not participate in quarterly distributions above $0.30 per unit.

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In the third quarter 2011, the Partnership declared and paid quarterly distributions to its common unitholders of record of $0.525 per common unit, $0.30 per class B unit to the holder of the class B units and amounts to the general partner on behalf of its 2% general partner interest and as holder of the IDRs. In the third quarter 2010, the Partnership declared and paid quarterly distributions to unitholders of record of $0.51 per common unit, $0.30 per class B unit to the holder of the class B units and amounts to the general partner on behalf of its 2% general partner interest and as holder of the IDRs. In October 2011, the Partnership declared a quarterly cash distribution to unitholders of record of $0.5275 per common unit.

Net Income per Unit

For purposes of calculating net income per unit, net income for the current period is reduced by the amount of available cash that will be distributed with respect to that period. Any residual amount representing undistributed net income (or loss) is assumed to be allocated to the various ownership interests in accordance with the contractual provisions of the partnership agreement.

Under the Partnership’s partnership agreement, for any quarterly period, the IDRs participate in net income only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed net income or losses. Accordingly, undistributed net income is assumed to be allocated to the other ownership interests on a pro rata basis, except that the class B units’ participation in net income is limited to $0.30 per unit per quarter. Payments made on account of the Partnership’s various ownership interests are determined in relation to actual declared distributions and are not based on the assumed allocations required under GAAP.

 The following table provides a reconciliation of net income and the assumed allocation of net income to the common and class B units for purposes of computing net income per unit for the three months ended September 30, 2011, (in millions, except per unit data):

	Total			Common Units			Class B Units			General Partner and IDRs
Net income	$	47.2
Declared distribution		107.8		$	92.7		$	6.9		$	8.2
Assumed allocation of undistributed net loss		(60.6	)		(52.5	)		(6.9	)		(1.2	)
Assumed allocation of net income	$	47.2		$	40.2		$	-		$	7.0
Weighted-average units outstanding					175.7			22.9
Net income per unit				$	0.23		$	-

The following table provides a reconciliation of net income and the assumed allocation of net income to the common and class B units for purposes of computing net income per unit for the three months ended September 30, 2010, (in millions, except per unit data):

	Total			Common Units			Class B Units			General Partner and IDRs
Net income	$	55.8
Declared distribution		101.2		$	87.4		$	6.9		$	6.9
Assumed allocation of undistributed net loss		(45.4	)		(39.2	)		(5.3	)		(0.9	)
Assumed allocation of net income	$	55.8		$	48.2		$	1.6		$	6.0
Weighted-average units outstanding					169.7			22.9
Net income per unit				$	0.28		$	0.07

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The following table provides a reconciliation of net income and the assumed allocation of net income to the common and class B units for purposes of computing net income per unit for the nine months ended September 30, 2011, (in millions, except per unit data):

	Total			Common Units			Class B  Units			General Partner and IDRs
Net income	$	145.4
Declared distribution		317.6		$	273.6		$	20.6		$	23.4
Assumed allocation of undistributed net loss		(172.2	)		(149.0	)		(19.7	)		(3.5	)
Assumed allocation of net income	$	145.4		$	124.6		$	0.9		$	19.9
Weighted-average units outstanding					172.5			22.9
Net income per unit				$	0.72		$	0.04

The following table provides a reconciliation of net income and the assumed allocation of net income to the common and class B units for purposes of computing net income per unit for the nine months ended September 30, 2010, (in millions, except per unit data):

	Total			Common Units			Class B Units			General Partner and IDRs
Net income	$	200.5
Declared distribution		300.3		$	259.6		$	20.7		$	20.0
Assumed allocation of undistributed net loss		(99.8	)		(86.1	)		(11.7	)		(2.0	)
Assumed allocation of net income	$	200.5		$	173.5		$	9.0		$	18.0
Weighted-average units outstanding					169.7			22.9
Net income per unit				$	1.02		$	0.39

Note 7:  Financing

Notes and Debentures

In January 2011, the Partnership received net proceeds of approximately $322.0 million after deducting initial purchaser discounts and offering expenses of $3.0 million from the sale of $325.0 million of 4.50% senior unsecured notes of Texas Gas due February 1, 2021 (2021 Notes). In June 2011, the Partnership issued an additional $115.0 million of the 2021 Notes. The additional issuance was priced at a premium and the Partnership received net proceeds of approximately $115.6 million after deducting underwriter discounts and offering expenses of $1.0 million. The net proceeds of both offerings were used to reduce borrowings under the Partnership’s revolving credit facility and to redeem Texas Gas’ 5.50% notes due April 1, 2013 (2013 Notes), as discussed below. The 2021 Notes are redeemable, in whole or in part, at the Partnership’s option at any time, at a redemption price equal to the greater of 100% of the principal amount of the notes to be redeemed or a “make whole” redemption price based on the remaining scheduled payments of principal and interest discounted to the date of redemption at a rate equal to the Treasury rate plus 20 basis points plus accrued and unpaid interest, if any. Other customary covenants apply, including those concerning events of default.

In February 2011, the Partnership redeemed $135.0 million of Texas Gas’ 2013 Notes at a premium of $11.8 million and in July 2011, redeemed the remaining $115.0 million at a premium of $9.2 million. The Partnership had unamortized discounts and deferred offering costs of $1.1 million related to the 2013 Notes which were redeemed. Due to the application of regulatory accounting, approximately $8.9 million of the premium and unamortized discounts related to the 2013 Notes were recognized as a regulatory asset, and will be amortized over the life of the 2021 Notes. A $7.4 million loss on the early extinguishment of debt was recognized in the first quarter 2011 and an additional loss of $5.8 million was recognized in the third quarter 2011.  

As of September 30, 2011 and December 31, 2010, the Partnership had notes and debentures outstanding of $2.7 billion and $2.5 billion with a weighted-average interest rate of 5.69% and 5.89%. The Partnership has $225.0 million of notes maturing August 2012. These notes are included in long-term debt on the Condensed Consolidated Balance Sheets since the Partnership expects to refinance these notes on a long-term basis and there is adequate available capacity under the revolving credit facility to extend the amount that would otherwise come due in less than a year.

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The indentures governing the notes and debentures have restrictive covenants which provide that, with certain exceptions, neither the Partnership nor any of its subsidiaries may create, assume or suffer to exist any lien upon any property to secure any indebtedness unless the debentures and notes shall be equally and ratably secured. All debt obligations are unsecured. At September 30, 2011, Boardwalk Pipelines and its operating subsidiaries were in compliance with their debt covenants.

Revolving Credit Facility

The Partnership has a revolving credit facility which has aggregate lending commitments of $950.0 million. Borrowings outstanding under the credit facility as of September 30, 2011 and December 31, 2010, were $458.5 million and $703.5 million with a weighted-average borrowing rate of 0.48% and 0.53%. At September 30, 2011, the Partnership had available borrowing capacity of $491.5 million and had no letters of credit issued.

The credit facility contains various restrictive covenants and other usual and customary terms and conditions, including limitations on the payment of cash dividends by the Partnership’s subsidiaries and other restricted payments, the incurrence of additional debt, the sale of assets and sale-leaseback transactions. The financial covenants under the credit facility require the Partnership and its subsidiaries to maintain, among other things, a ratio of total consolidated debt to consolidated EBITDA (as defined in the credit agreement) measured for the previous twelve months of not more than 5.0 to 1.0. The Partnership and its subsidiaries were in compliance with all covenant requirements under the credit facility as of September 30, 2011. The revolving credit facility has a maturity date of June 29, 2012, however all outstanding revolving loans on such date may be converted to term loans having a maturity date of June 29, 2013.

Long-Term Debt – Affiliate

In 2009, Boardwalk Pipelines entered into a Subordinated Loan Agreement with BPHC under which Boardwalk Pipelines borrowed $200.0 million (Subordinated Loans). The Subordinated Loans bear interest at 8.00% per year, payable semi-annually in June and December, commencing December 2009, and mature six months after the maturity (including any term-out period) of the revolving credit facility. As of September 30, 2011 and December 31, 2010, the Partnership had $100.0 million outstanding under the Subordinated Loan Agreement with no additional borrowing capacity available. BPHC waived the mandatory prepayment provision under the Subordinated Loan Agreement that would have required prepayment of the outstanding Subordinated Loans as a result of the issuance and sale of the 2021 Notes and common units in June 2011 discussed below.

Common Unit Offering

In June 2011, the Partnership completed a public offering of 6.0 million of its common units at a price of $29.33 per unit. The Partnership received net cash proceeds of approximately $173.6 million after deducting underwriting discounts and offering expenses of $6.0 million and including a $3.6 million contribution received from the general partner to maintain its 2% general partner interest.

Registration Rights Agreement

The Partnership has entered into an Amended and Restated Registration Rights Agreement with BPHC under which the Partnership has agreed to register the resale by BPHC of 27.9 million common units and to reimburse BPHC up to a maximum price of $0.914 per common unit for underwriting discounts and commissions. In February 2010, BPHC sold 11.5 million common units of the Partnership in a secondary offering and consequently, the Partnership reimbursed BPHC $10.5 million for underwriting discounts and commissions and incurred other offering costs of approximately $0.2 million, all of which were recorded against a previously established liability pursuant to the registration rights agreement. As of September 30, 2011 and December 31, 2010, the Partnership had an accrued liability of approximately $16.0 million for future underwriting discounts and commissions that would be reimbursed to BPHC and other registration and offering costs that are expected to be incurred by the Partnership.

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Note 8:  Property, Plant and Equipment (PPE)

In February 2011, a fire occurred at one of the Partnership’s compressor stations near Carthage, Texas, which caused significant damage to the compressor building, the compressor units and related equipment housed in the building. The cost to repair the building facilities and replace equipment damaged by the fire was approximately $18.0 million. The Partnership has insurance which will cover the costs incurred to restore the damaged equipment and facilities, subject to a $5.0 million deductible. In the first quarter 2011, the Partnership recognized expenses of $5.0 million related to the incident which is recorded in the Condensed Consolidated Statements of Income and has recorded a receivable related to expected insurance recoveries of $8.9 million on the Condensed Consolidated Balance Sheets.

Note 9:  Bistineau Storage Gas Loss

In the second quarter 2011, the Partnership completed a series of tests to verify the quantity of gas stored at its Bistineau storage facility. These tests indicated that a gas loss of approximately 6.7 Bcf occurred at the facility. As a result, the Partnership recorded a charge to Fuel and gas transportation expense of $3.7 million to recognize the loss in base gas which had a carrying value of $0.53 per MMBtu.The Partnership has not yet determined the root cause of the gas loss or whether the gas will need to be replaced.

Note 10:  Asset Impairments and Dispositions

Materials and Supplies

The Partnership holds materials and supplies comprised of pipe, valves, fittings and other materials to support its ongoing operations and for potential future growth projects.  In 2011, the Partnership determined that a portion of the materials and supplies would not be used given the types of projects the Partnership would likely pursue under its new growth strategy and the costs to carry and maintain the materials.  As a result, the Partnership recognized an impairment charge of $28.6 million to adjust the carrying amount of those materials and supplies to an estimated fair value of $6.4 million. The fair value of the materials was determined by obtaining information from brokers, resellers and distributors of these types of materials which are considered Level 3 inputs under the fair value hierarchy. At September 30, 2011, the Partnership held approximately $26.2 million of materials and supplies which was reflected in Other Assets on the Condensed Consolidated Balance Sheets.

In the third quarter 2010, the Partnership agreed to sell pipe materials with a book value of $11.5 million for estimated consideration of approximately $8.2 million and recorded an impairment charge of $3.3 million.  The fair value measurement of the pipe materials was based on Level 3 inputs under the fair value hierarchy.

Gas Sales

For the three and nine months ended September 30, 2011, the Partnership sold approximately 3.1 Bcf and 4.5 Bcf of gas stored underground with a book value of $6.9 million and $10.3 million that became available for sale due to a change in the storage working gas needed to support operations and no-notice services at its Texas Gas subsidiary.  As a result, the Partnership recognized gains of $6.0 million and $9.2 million for the three and nine months ended September 30, 2011.  In the third quarter 2010, approximately 3.3 Bcf of gas stored underground with a book value of $7.5 million was sold related to Phase III of the Western Kentucky Storage Expansion.  As a result, the Partnership recognized a gain of $12.1 million for the three and nine months ended September 30, 2010.  The gains related to these gas sales were recorded in Net gain on disposal of operating assets.

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Overton Lateral

In 2010, the Partnership completed the sale of certain of its gathering assets in the Overton Field area in northeastern Texas for a nominal amount. In the second quarter 2010, the Partnership recognized an impairment charge of approximately $2.2 million, representing the net book value of the assets.

Note 11:  Employee Benefits

Defined Benefit Retirement Plans and Postretirement Benefits Other Than Pension (PBOP)

Texas Gas employees hired prior to November 1, 2006, are covered under a non-contributory, defined benefit pension plan (Pension Plan). The Texas Gas Supplemental Retirement Plan provides pension benefits for the portion of an eligible employee’s pension benefit under the Pension Plan 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.

Components of net periodic benefit cost for both the Retirement Plans and PBOP for the three months ended September 30, 2011 and 2010 were as follows (in millions):

	Retirement Plans						PBOP
	For the Three Months Ended September 30,						For the Three Months Ended September 30,
	2011			2010			2011			2010
Service cost	$	1.0		$	0.9		$	0.1		$	0.1
Interest cost		1.6			1.7			0.6			0.7
Expected return on plan assets		(2.0	)		(1.7	)		(0.8	)		(0.9	)
Amortization of prior service credit		-			-			(1.9	)		(2.0	)
Amortization of unrecognized net loss		0.3			0.3			0.1			0.2
Regulatory asset decrease		-			-			1.4			1.4
Net periodic benefit cost	$	0.9		$	1.2		$	(0.5	)	$	(0.5	)

Components of net periodic benefit cost for both the Retirement Plans and PBOP for the nine months ended September 30, 2011 and 2010 were as follows (in millions):

	Retirement Plans						PBOP
	For the Nine Months Ended September 30,						For the Nine Months Ended September 30,
	2011			2010			2011			2010
Service cost	$	3.0		$	2.8		$	0.3		$	0.3
Interest cost		4.8			5.1			1.8			2.1
Expected return on plan assets		(6.0	)		(5.2	)		(2.4	)		(2.8	)
Amortization of prior service credit		-			-			(5.7	)		(5.8	)
Amortization of unrecognized net loss		0.9			1.0			0.4			0.6
Regulatory asset decrease		-			-			4.2			4.1
Net periodic benefit cost	$	2.7		$	3.7		$	(1.4	)	$	(1.5	)

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 In 2011, the Partnership contributed $9.0 million to its defined benefit pension plan.

 Defined Contribution Plans

Texas Gas employees hired on or after November 1, 2006, and Gulf South employees are provided retirement benefits under a similar 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 $2.0 million and $5.8 million for the three and nine months ended September 30, 2011, and $2.0 million and $5.5 million for the three and nine months ended September 30, 2010.

Note 12:  Related Party Transactions

Loews provides to the Partnership a variety of corporate services under services agreements, including but not limited to, information technology, tax, risk management, internal audit and corporate development services, plus allocated overhead. The Partnership incurred charges related to these services of $3.6 million and $13.9 million for the three and nine months ended September 30, 2011, and $3.2 million and $12.4 million for the three and nine months ended September 30, 2010.

Distributions paid related to limited partner units held by BPHC and the 2% general partner interest and IDRs held by Boardwalk GP were $204.0 million and $201.2 million during the nine months ended September 30, 2011 and 2010.

Note 13:  Accumulated Other Comprehensive Loss

The following table shows the components of Accumulated other comprehensive loss which is included in Partners’ Capital on the Condensed Consolidated Balance Sheets (in millions):

	As of September 30, 2011			As of December 31, 2010
Loss on cash flow hedges	$	(10.1	)	$	(13.7	)
Deferred components of net periodic benefit cost		(30.3	)		(25.8	)
Total Accumulated other comprehensive loss	$	(40.4	)	$	(39.5	)

Note 14:  Financial Instruments

The following methods and assumptions were used in estimating the Partnership’s fair value disclosures for financial instruments:

Cash and Cash Equivalents: For cash and short-term financial assets, the carrying amount is a reasonable estimate of fair value due to the short maturity of those instruments.

Long-Term Debt: The estimated fair value of the Partnership’s publicly traded debt is based on quoted market prices at September 30, 2011 and December 31, 2010. The fair market value of the debt that is not publicly traded is based on market prices of similar debt at September 30, 2011 and December 31, 2010.

Long-Term Debt - Affiliate: Borrowings under a subordinated loan agreement with BPHC were completed in 2009. The estimated fair value is based on market prices of similar debt, adjusted for the affiliated nature of the transaction.

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The carrying amount and estimated fair values of the Partnership’s financial instruments as of September 30, 2011 and December 31, 2010, were as follows (in millions):

	September 30, 2011				December 31, 2010
Financial Assets	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents	$	84.2	$	84.2	$	55.0	$	55.0
Financial Liabilities
Long-term debt	$	3,098.2	$	3,337.1	$	3,152.3	$	3,314.3
Long-term debt – affiliate		100.0		107.7		100.0		106.3

Note 15:  Supplemental Disclosure of Cash Flow Information (in millions):

	For the Nine Months Ended September 30,
	2011		2010
Cash paid during the period for:
Interest (net of amount capitalized)(1)	$	149.6	$	116.9
Non-cash adjustments:
Accounts payable and PPE	$	10.4	$	29.0

(1)   The 2011 period includes $21.0 million of premiums paid for the 2013 Notes redemption.

Note 16: Subsequent Events

In October 2011, Boardwalk Pipelines and BPHC entered into an agreement to create a joint venture, Boardwalk HP Storage Company, LLC (Boardwalk Storage). Simultaneously, Boardwalk Storage entered into a definitive agreement to acquire Petal Gas Storage, L.L.C., Hattiesburg Gas Storage Company and related entities from an affiliate of Enterprise Products Partners L.P. for $550.0 million in cash. These entities own and operate salt dome storage and pipeline facilities and are engaged in the storage and transportation of natural gas. Boardwalk Storage expects to fund the acquisition with proceeds from a new $200.0 million five-year bank loan and equity contributions from Boardwalk Pipelines and BPHC.  BPHC will contribute $280.0 million for an 80% equity ownership interest in Boardwalk Storage and Boardwalk Pipelines will contribute $70.0 million for a 20% equity ownership interest in Boardwalk Storage. The acquisition is expected to close in the fourth quarter 2011 subject to customary closing conditions.   

Note 17: Guarantee of Securities of Subsidiaries

Boardwalk Pipelines (subsidiary issuer) has issued securities which have been fully and unconditionally guaranteed by the Partnership (parent guarantor). The Partnership's subsidiaries have no significant restrictions on their ability to pay distributions or make loans to the Partnership except as noted in the debt covenants and have no restricted assets at September 30, 2011 and December 31, 2010. Note 7 contains additional information regarding the Partnership's debt and related covenants.

The Partnership has provided the following condensed consolidating financial information in accordance with Regulation S-X Rule 3-10, Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered.

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Condensed Consolidating Balance Sheets as of September 30, 2011

(Millions)

Assets	Parent Guarantor		Subsidiary  Issuer		Non-guarantor Subsidiaries		Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Cash and cash equivalents	$	0.4	$	78.2	$	5.6	$	-		$	84.2
Receivables		0.8		-		109.2		(7.4	)		102.6
Gas stored underground		-		-		8.0		-			8.0
Prepayments		-		-		16.0		-			16.0
Advances to affiliates		-		-		38.8		(38.8	)		-
Other current assets		0.3		-		29.5		(7.9	)		21.9
Total current assets		1.5		78.2		207.1		(54.1	)		232.7
Investment in consolidated subsidiaries		926.3		5,032.0		-		(5,958.3	)		-
Property, plant and equipment, gross		0.6		-		7,119.7		-			7,120.3
Less–accumulated depreciation and amortization		0.6		-		932.9		-			933.5
Property, plant and equipment, net		-		-		6.186.8		-			6,186.8
Other noncurrent assets		0.3		1.7		383.9		(0.6	)		385.3
Advances to affiliates – noncurrent		2,338.1		-		529.6		(2,867.7	)		-
Total other assets		2,338.4		1.7		913.5		(2,868.3	)		385.3
Total Assets	$	3,266.2	$	5,111.9	$	7,307.4	$	(8,880.7	)	$	6,804.8

Liabilities & Partners' Capital/Member’s Equity	Parent Guarantor		Subsidiary Issuer		Non-guarantor Subsidiaries		Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Payables	$	2.4	$	2.1	$	42.4	$	(7.4	)	$	39.5
Advances from affiliates		-		38.8		-		(38.8	)		-
Other current liabilities		0.1		12.4		141.9		(8.5	)		145.9
Total current liabilities		2.5		53.3		184.3		(54.7	)		185.4
Total long-term debt		-		1,279.9		1,918.3		-			3,198.2
Payable to affiliate		16.0		2,867.7		-		(2,867.7	)		16.0
Other noncurrent liabilities		0.3		-		157.5		-			157.8
Total other liabilities and deferred credits		16.3		2,867.7		157.5		(2,867.7	)		173.8
Total partners’ capital/member’s equity		3,247.4		911.0		5,047.3		(5,958.3	)		3,247.4
Total Liabilities and Partners' Capital/Member’s Equity	$	3,266.2	$	5,111.9	$	7,307.4	$	(8,880.7	)	$	6,804.8

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Condensed Consolidating Balance Sheets as of December 31, 2010

(Millions)

Assets	Parent Guarantor		Subsidiary Issuer		Non-guarantor Subsidiaries		Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Cash and cash equivalents	$	-	$	52.6	$	2.4	$	-		$	55.0
Receivables		-		-		115.2		(9.0	)		106.2
Gas stored underground		-		-		3.6		-			3.6
Prepayments		-		-		11.4		-			11.4
Advances to affiliates		-		107.8		-		(107.8	)		-
Other current assets		-		-		34.9		(7.9	)		27.0
Total current assets		-		160.4		167.5		(124.7	)		203.2
Investment in consolidated subsidiaries		799.4		4,940.9		-		(5,740.3	)		-
Property, plant and equipment, gross		0.6		-		7,043.2		-			7,043.8
Less–accumulated depreciation and amortization		0.5		-		785.3		-			785.8
Property, plant and equipment, net		0.1		-		6,257.9		-			6,258.0
Other noncurrent assets		-		1.8		417.0		(2.0	)		416.8
Advances to affiliates – noncurrent		2,461.4		-		362.2		(2,823.6	)		-
Total other assets		2,461.4		1.8		779.2		(2,825.6	)		416.8
Total Assets	$	3,260.9	$	5,103.1	$	7,204.6	$	(8,690.6	)	$	6,878.0

Liabilities & Partners' Capital/Member’s Equity	Parent Guarantor		Subsidiary Issuer		Non-guarantor Subsidiaries		Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Payables	$	3.5	$	0.3	$	101.3	$	(18.3	)	$	86.8
Advances from affiliates		-		-		107.8		(107.8	)		-
Other current liabilities		-		15.5		112.2		(0.7	)		127.0
Total current liabilities		3.5		15.8		321.3		(126.8	)		213.8
Total long-term debt		-		1,464.3		1,788.0		-			3,252.3
Payable to affiliate		16.0		2,823.6		-		(2,823.6	)		16.0
Other noncurrent liabilities		-		-		154.4		0.1			154.5
Total other liabilities and deferred credits		16.0		2,823.6		154.4		(2,823.5	)		170.5
Total partners’ capital/member’s equity		3,241.4		799.4		4,940.9		(5,740.3	)		3,241.4
Total Liabilities and Partners' Capital/Member’s Equity	$	3, 260.9	$	5,103.1	$	7,204.6	$	(8,690.6	)	$	6,878.0

23

Condensed Consolidating Statements of Income for the Three Months Ended September 30, 2011

(Millions)

	Parent Guarantor			Subsidiary Issuer			Non-guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Operating revenues:
Gas transportation	$	-		$	-		$	276.2		$	(24.4	)	$	251.8
Parking and lending		-			-			2.2			-			2.2
Gas storage		-			-			12.0			-			12.0
Other		-			-			2.9			-			2.9
Total operating revenues		-			-			293.3			(24.4	)		268.9
Operating cost and expenses:
Fuel and gas transportation		-			-			51.1			(24.4	)		26.7
Operation and maintenance		-			-			45.9			-			45.9
Administrative and general		(0.1	)		0.2			31.0			-			31.1
Other operating costs and expenses		0.1			-			72.7			-			72.8
Total operating costs and expenses		-			0.2			200.7			(24.4	)		176.5
Operating income		-			(0.2	)		92.6			-			92.4
Other deductions (income):
Interest expense		-			16.0			21.6			-			37.6
Interest expense, affiliate, net		(7.5	)		11.2			(1.7	)		-			2.0
Loss on debt extinguishment		-			-			5.8			-			5.8
Interest income		-			-			(0.1	)		-			(0.1	)
Equity in earnings of subsidiaries		(39.7	)		(69.9	)		-			109.6			-
Miscellaneous other income		-			-			(0.2	)		-			(0.2	)
Total other (income) deductions		(47.2	)		(42.7	)		25.4			109.6			45.1
Income before income taxes		47.2			42.5			67.2			(109.6	)		47.3
Income Taxes		-			-			0.1			-			0.1
Net Income	$	47.2		$	42.5		$	67.1		$	(109.6	)	$	47.2

24

Condensed Consolidating Statements of Income for the Three Months Ended September 30, 2010

(Millions)

	Parent  Guarantor			Subsidiary Issuer			Non-guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Operating revenues:
Gas transportation	$	-		$	-		$	258.5		$	(24.3	)	$	234.2
Parking and lending		-			-			11.1			(5.6	)		5.5
Gas storage		-			-			13.1			-			13.1
Other		-			-			4.8			-			4.8
Total operating revenues		-			-			287.5			(29.9	)		257.6
Operating cost and expenses:
Fuel and gas transportation		-			-			57.6			(29.9	)		27.7
Operation and maintenance		-			-			36.8			-			36.8
Administrative and general		-			-			33.2			-			33.2
Other operating costs and expenses		0.1			-			66.7			-			66.8
Total operating costs and expenses		0.1			-			194.3			(29.9	)		164.5
Operating (loss) income		(0.1	)		-			93.2			-			93.1
Other deductions (income):
Interest expense		-			16.3			19.0			-			35.3
Interest expense, affiliate, net		(9.7	)		12.1			(0.4	)		-			2.0
Interest income		-			-			(0.2	)		-			(0.2	)
Equity in earnings of subsidiaries		(46.2	)		(74.6	)		-			120.8			-
Total other deductions (income)		(55.9	)		(46.2	)		18.4			120.8			37.1
Income before income taxes		55.8			46.2			74.8			(120.8	)		56.0
Income Taxes		-			-			0.2			-			0.2
Net Income	$	55.8		$	46.2		$	74.6		$	(120.8	)	$	55.8

25

Condensed Consolidating Statements of Income for the Nine Months Ended September 30, 2011

(Millions)

	Parent Guarantor				Subsidiary Issuer			Non-guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Operating revenues:
Gas transportation	$	-			$	-		$	859.2		$	(72.6	)	$	786.6
Parking and lending		-				-			9.3			(0.8	)		8.5
Gas storage		-				-			37.5			-			37.5
Other		-				-			9.3			-			9.3
Total operating revenues		-				-			915.3			(73.4	)		841.9
				��
Operating cost and expenses:
Fuel and gas transportation		-				-			152.1			(73.4	)		78.7
Operation and maintenance		-				-			123.1			-			123.1
Administrative and general		(0.3	)			0.2			102.0			-			101.9
Other operating costs and expenses		0.3				-			260.4			-			260.7
Total operating costs and expenses		-				0.2			637.6			(73.4	)		564.4
Operating income		-				(0.2	)		277.7			-			277.5
Other deductions (income):
Interest expense		-				48.4			65.1			-			113.5
Interest expense, affiliate, net		(23.0	)			33.4			(4.4	)		-			6.0
Loss on debt extinguishment		-				-			13.2			-			13.2
Interest income		-				-			(0.3	)		-			(0.3	)
Equity in earnings of subsidiaries		(122.4	)			(209.2	)		-			331.6			-
Miscellaneous other income		-				-			(0.6	)		-			(0.6	)
Total other (income) deductions		(145.4	)			(127.4	)		73.0			331.6			131.8
Income before income taxes		145.4				127.2			204.7			(331.6	)		145.7
Income taxes		-				-			0.3			-			0.3
Net Income	$	145.4			$	127.2		$	204.4		$	(331.6	)	$	145.4

26

Condensed Consolidating Statements of Income for the Nine Months Ended September 30, 2010

(Millions)

	Parent Guarantor			Subsidiary  Issuer			Non-guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Operating revenues:
Gas transportation	$	-		$	-		$	813.2		$	(79.2	)	$	734.0
Parking and lending		-			-			31.1			(7.3	)		23.8
Gas storage		-			-			41.5			-			41.5
Other		-			-			15.5			-			15.5
Total operating revenues		-			-			901.3			(86.5	)		814.8
Operating cost and expenses:
Fuel and gas transportation		-			-			168.3			(86.5	)		81.8
Operation and maintenance		-			-			100.2			-			100.2
Administrative and general		1.5			-			97.3			-			98.8
Other operating costs and expenses		0.3			-			221.2			-			221.5
Total operating costs and expenses		1.8			-			587.0			(86.5	)		502.3
Operating income (loss)		(1.8	)		-			314.3			-			312.5
Other deductions (income):
Interest expense		-			48.5			57.7			-			106.2
Interest expense, affiliate, net		(27.0	)		33.2			(0.2	)		-			6.0
Interest income		-			-			(0.5	)		-			(0.5	)
Equity in earnings of subsidiaries		(175.3	)		(257.0	)		-			432.3			-
Miscellaneous other income, net		-			-			(0.1	)		-			(0.1	)
Total other deductions (income)		(202.3	)		(175.3	)		56.9			432.3			111.6
Income before income taxes		200.5			175.3			257.4			(432.3	)		200.9
Income Taxes		-			-			0.4			-			0.4
Net Income	$	200.5		$	175.3		$	257.0		$	(432.3	)	$	200.5

27

Condensed Consolidating Statements of Cash Flow for the Nine Months Ended September 30, 2011

(Millions)

	Parent Guarantor			Subsidiary  Issuer			Non-guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Net Cash Provided by (Used In) Operating Activities	$	21.1		$	20.0		$	405.6		$	(101.2	)	$	345.5
Investing Activities:
Capital expenditures		-			-			(116.9	)		-			(116.9	)
Proceeds from sale of operating assets		-			-			17.5			-			17.5
Advances to affiliates, net		123.1			107.8			(206.1	)		(24.8	)		-
Investment in consolidated subsidiary		(5.3	)		-			-			5.3			-
Net Cash Provided by (Used in) Investing Activities		117.8			107.8			(305.5	)		(19.5	)		(99.4	)
Financing Activities:
Proceeds from long-term debt, net of issuance costs		-			-			437.6			-			437.6
Repayment of borrowings from long- term debt		-			-			(250.0	)		-			(250.0	)
Payments of premiums on extinguishment of long-term debt		-			-			(21.0	)		-			(21.0	)
Proceeds from borrowings on revolving credit agreement		-			235.0			280.0			-			515.0
Repayment of borrowings on revolving credit agreement		-			(420.0	)		(340.0	)		-			(760.0	)
Contribution from parent		-			-			5.3			(5.3	)		-
Advances from affiliates, net		-			82.8			(107.8	)		25.0			-
Distributions paid		(312.1	)		-			(101.0	)		101.0			(312.1	)
Proceeds from sale of common units		170.0			-			-			-			170.0
Capital Contribution from general partner		3.6			-			-			-			3.6
Net Cash (Used in) Provided by Financing Activities		(138.5	)		(102.2	)		(96.9	)		120.7			(216.9	)
Increase in Cash and Cash  Equivalents		0.4			25.6			3.2			-			29.2
Cash and Cash Equivalents at  Beginning of Period		-			52.6			2.4			-			55.0
Cash and Cash Equivalents at End of Period	$	0.4		$	78.2		$	5.6		$	-		$	84.2

28

Condensed Consolidating Statements of Cash Flow for the Nine Months Ended September 30, 2010

(Millions)

	Parent Guarantor			Subsidiary Issuer			Non-guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Net Cash Provided by (Used In) Operating Activities	$	224.4		$	(82.0	)	$	409.2		$	(196.8	)	$	354.8
Investing Activities:
Capital expenditures		-			-			(174.2	)		-			(174.2	)
Proceeds from sale of operating assets		-			-			16.4			-			16.4
Advances to affiliates, net		79.6			114.7			(131.7	)		(62.6	)		-
Net Cash Provided by (Used in) Investing Activities		79.6			114.7			(289.5	)		(62.6	)		(157.8	)
Financing Activities:
Proceeds from borrowings on revolving credit agreement		-			150.0			-			-			150.0
Payments on note payable		(0.3	)		-			-			-			(0.3	)
Payments associated with registration rights agreement		(10.7	)		-			-			-			(10.7	)
Advances from affiliates, net		3.9			52.1			(114.7	)		62.6			3.9
Distributions paid		(296.9	)		(196.8	)		-			196.8			(296.9	)
Net Cash (Used in) Provided by Financing Activities		(304.0	)		5.3			(114.7	)		259.4			(154.0	)
Increase in Cash and Cash Equivalents		-			38.0			5.0			-			43.0
Cash and Cash Equivalents at Beginning of  Period		-			45.6			0.2			-			45.8
Cash and Cash Equivalents at End of Period	$	-		$	83.6		$	5.2		$	-		$	88.8

29

 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, 2010.

Overview

Our transportation services consist of firm transportation, where the customer pays a capacity reservation charge to reserve pipeline capacity at certain receipt and delivery points along our pipeline systems, plus a commodity and fuel charge on the volume of natural gas actually transported, and interruptible transportation, where the customer pays to transport gas only when capacity is available and used. We offer firm storage services in which the customer reserves and pays for a specific amount of storage capacity, including injection and withdrawal rights, and interruptible storage and parking and lending (PAL) services where the customer receives and pays for capacity only when it is available and used. Some PAL agreements are paid for at inception of the service and revenues for these agreements are recognized as service is provided over the term of the agreement. Our operating costs and expenses typically do not vary significantly based upon the amount of gas transported, with the exception of fuel consumed at our compressor stations, which is included in Fuel and gas transportation expenses on our Condensed Consolidated Statements of Income.

Recent Developments

Pending Acquisition

In October 2011, Boardwalk HP Storage Company, LLC (Boardwalk Storage), a joint venture formed by Boardwalk Pipelines and BPHC, entered into a definitive agreement to acquire Petal Gas Storage, L.L.C. (Petal), Hattiesburg Gas Storage Company (Hattiesburg) and related entities from an affiliate of Enterprise Products Partners L.P. for $550.0 million in cash. Boardwalk Storage expects to fund the acquisition with borrowings under a new $200.0 million five-year bank loan and equity contributions from Boardwalk Pipelines and BPHC. BPHC will contribute $280.0 million for an 80% equity ownership interest in Boardwalk Storage and Boardwalk Pipelines will contribute $70.0 million for a 20% equity ownership interest. The acquisition is expected to close in the fourth quarter 2011 subject to customary closing conditions. 

Petal and Hattiesburg operate seven high deliverability salt dome natural gas storage caverns primarily in Forrest County, Mississippi having approximately 29 billion cubic feet (Bcf) of total storage capacity, of which approximately 18.6 Bcf is working gas capacity. Those companies also own and operate a leaching plant, freshwater and brine disposal wells, approximately 69,000 horsepower of compression and approximately 105 miles of pipeline which connect their facilities with several major natural gas pipelines, including ours. The storage capacity is currently fully subscribed under long-term fixed-fee contracts with a weighted-average remaining contract life of approximately seven years.  Gulf South will operate these assets on behalf of the joint venture.

Marcellus Gathering System

In October 2011, our subsidiary, Boardwalk Field Services, LLC, and Southwestern Energy Production Company executed a fifteen year definitive gas gathering agreement which will require construction of a natural gas gathering system in Susquehanna and Lackawanna Counties, Pennsylvania. We will own the gas gathering system that will support Southwestern’s development of Marcellus Shale gas wells in these counties. The gathering system is expected to cost approximately $90 million and will be comprised of approximately 26 miles of twelve-inch high pressure gas pipeline, a low pressure in-field gathering pipeline, compression and dehydration and will interconnect with Tennessee Gas Pipeline Company in Susquehanna County, Pennsylvania. The system will be constructed over several years and is expected to have a delivery capacity of approximately 0.3 Bcf/day when fully constructed.

30

Market Conditions and Contract Renewals

The majority of our revenues are derived from capacity reservation charges that are not impacted by the volume of natural gas transported, however a smaller portion of our revenues are derived from charges based on actual volumes transported under firm and interruptible services. For example, for the last twelve months ended September 30, 2011, approximately 19% of our revenues were derived from charges based on actual volumes transported.

As of September 30, 2011, a substantial portion of our operating capacity has been contracted for under firm agreements having a weighted-average remaining life of approximately 6.0 years. However, an important aspect of our business is our ability to market available short-term firm or interruptible transportation capacity and renew existing longer-term transportation contracts. We actively market our available capacity which includes reserved capacity not fully utilized. The revenues we will be able to earn from that available capacity and from renewals of expiring contracts will be influenced by basis spreads and other factors discussed below.

Our ability to market available transportation capacity is impacted by supply and demand for natural gas, competition from other pipelines, natural gas price volatility, the price differential between physical locations on our pipeline systems (basis spreads), economic conditions and other factors. Over the past several years, new sources of natural gas have been identified throughout the U.S. and new pipeline infrastructure has been developed, which has led to changes in pricing dynamics between supply basins, pooling points and market areas and an overall weakening of basis spreads across our pipeline systems.

The narrowing of basis spreads on our pipeline systems has made it more difficult to renew expiring long-term firm transportation contracts at previously contracted rates because, as basis spreads decrease, the rates customers are willing to pay decrease. In addition, as rates decline customers typically seek longer-term agreements while we generally seek shorter terms. However, changing basis spreads do not have as significant or immediate an impact on long-term firm agreements as they do on short-term or interruptible services because long-term agreements are also influenced by other factors, such as baseload supply needs, certainty of delivery, predictability of long-term costs, the ability to manage those costs through the capacity release mechanism and the terms of service.

Our ability to market available storage capacity and PAL is impacted by many of the factors indicated above, as well as natural gas price differentials between time periods, such as winter to summer (time period price spreads). These time period price spreads have declined over the 2010 to 2011 periods and have resulted in a significant reduction in our PAL and interruptible storage revenues in 2011 as compared to 2010.

Pipeline System Maintenance

We incur substantial costs for ongoing maintenance of our pipeline systems and related facilities, some of which reflect increased regulatory requirements applicable to all interstate pipelines. These costs include those incurred for pipeline integrity management activities, equipment overhauls, general upkeep and repairs. Maintenance costs may be capitalized or expensed, depending on the nature of the activities. For any given reporting period the mix of projects that we undertake will affect the amounts we record as property, plant and equipment on our balance sheet or expense in our earnings.

In 2011, we expect to incur costs of approximately $250.0 million to maintain our pipeline systems, of which approximately $82.0 million is expected to be recorded as maintenance capital, excluding expenditures related to the Carthage Compressor Station incident discussed below. In 2010, these costs were approximately $212.6 million, approximately $63.0 million of which was recorded as maintenance capital. The increase of $37.4 million is primarily related to pipeline integrity management, reliability and general pipeline maintenance and repairs which are necessary to comply with regulatory requirements. The increased costs for pipeline system maintenance are expected to continue in 2012.

31

Carthage Compressor Station Incident

In the first quarter 2011, a fire occurred at one of our compressor stations near Carthage, Texas, which caused significant damage to the compressor building, the compressor units and related equipment housed in the building. The incident did not affect our ability to meet our contractual obligations under firm transportation agreements, because we were able to utilize other system assets to meet our obligations. The repairs to the building and the replacement of the equipment damaged by the fire were completed in the third quarter 2011 at a total cost of approximately $18.0 million. We have insurance which will cover the costs incurred to restore the damaged equipment and facilities, subject to a $5.0 million deductible. In 2011, we recognized expenses of $5.0 million related to the incident which represents the amount of the insurance deductible.

Materials and Supplies Impairment

We hold materials and supplies comprised of pipe, valves, fittings and other materials to support our ongoing operations and for potential future growth projects.  In 2011, we determined that a portion of our materials and supplies would not be used given the types of projects we would likely pursue under our new growth strategy and the costs to carry and maintain the materials.  As a result, we recognized an impairment charge of $28.6 million to adjust the carrying amount of those materials and supplies to an estimated fair value of $6.4 million. At September 30, 2011, we held approximately $26.2 million of materials and supplies which was included in Other Assets on the Condensed Consolidated Balance Sheets.

Results of Operations for the Three Months Ended September 30, 2011 and 2010

Our net income for the three months ended September 30, 2011, decreased $8.6 million, or 15%, to $47.2 million compared to $55.8 million for the three months ended September 30, 2010. The decrease in net income was a result of decreased PAL and storage revenues, increased operation and maintenance expenses and a loss on the early extinguishment of debt, all as discussed below. These unfavorable impacts to net income were partially offset by higher gas transportation revenues from increased capacities.

Operating revenues for the three months ended September 30, 2011, increased $11.3 million, or 4%, to $268.9 million, compared to $257.6 million for the three months ended September 30, 2010. Gas transportation revenues, excluding fuel, increased $18.6 million primarily from increased capacities resulting from the completion of several compression projects in 2010 and operating our Fayetteville Lateral at its design capacity. PAL and storage revenues decreased $4.4 million due to decreased parking opportunities from unfavorable natural gas price spreads between time periods and fuel retained decreased $2.9 million primarily due to lower natural gas prices.

Operating costs and expenses for the three months ended September 30, 2011, increased $12.0 million, or 7%, to $176.5 million, compared to $164.5 million for the three months ended September 30, 2010. The primary drivers of the increase were increased operation and maintenance expenses of $9.1 million due to maintenance projects mainly for pipeline integrity management and reliability spending and lower gains of $6.0 million from the sale of storage gas. The 2010 period was impacted by a $3.3 million impairment charge related to surplus pipe.

Total other deductions increased by $8.0 million, or 22%, to $45.1 million, for the three months ended September 30, 2011, compared to $37.1 million for the 2010 period, driven by a $5.8 million loss on the early extinguishment of debt and higher interest expense of $2.3 million resulting from higher average interest rates on our long-term debt and lower capitalized interest.

Results of Operations for the Nine Months Ended September 30, 2011 and 2010

Our net income for the nine months ended September 30, 2011, decreased $55.1 million, or 27%, to $145.4 million compared to $200.5 million for the nine months ended September 30, 2010. The decrease in net income was a result of the factors described above for the three month period, as well as charges related to our materials and supplies and the Carthage Compressor Station incident. These unfavorable impacts to net income were partially offset by higher gas transportation revenues from increased capacities.

32

Operating revenues for the nine months ended September 30, 2011, increased $27.1 million, or 3%, to $841.9 million, compared to $814.8 million for the nine months ended September 30, 2010. Gas transportation revenues, excluding fuel, increased $57.1 million primarily from increased capacities resulting from the completion of several compression projects in 2010 and operating our Fayetteville Lateral at its design capacity. PAL and storage revenues decreased $19.3 million due to decreased parking opportunities from unfavorable natural gas price spreads between time periods and fuel retained decreased $10.7 million primarily due to lower natural gas prices.

 Operating costs and expenses for the nine months ended September 30, 2011, increased $62.1 million, or 12%, to $564.4 million, compared to $502.3 million for the nine months ended September 30, 2010. In 2011, we recognized an impairment charge of $28.6 million related to materials and supplies. Operation and maintenance expenses increased by $21.8 million primarily due to maintenance projects for pipeline integrity management and reliability spending and lower amounts of labor capitalized from fewer growth projects. Other drivers for the increased operating expenses were higher depreciation and property taxes of $8.7 million associated with an increase in our asset base, a charge of $5.0 million related to the Carthage Compression incident, which impacted Loss on Disposal of Operating Assets and Operation and Maintenance expenses and $3.7 million of gas losses associated with our Bistineau storage facility. These increases were partially offset by lower fuel consumed of $6.1 million primarily due to lower natural gas prices. The 2010 period was impacted by impairment charges of $5.5 million related to the Overton Lateral and surplus pipe, both of which were subsequently sold.

Total other deductions increased by $20.2 million, or 18%, to $131.8 million for the nine months ended September 30, 2011, compared to $111.6 million for the 2010 period, driven by a $13.2 million loss on the early extinguishment of debt and higher interest expense of $7.3 million resulting from higher average interest rates on our long-term debt, lower capitalized interest and higher debt levels.

Liquidity and Capital Resources

We are a partnership holding company and derive all of our operating cash flow from our operating subsidiaries. Our principal sources of liquidity include cash generated from operating activities, our revolving credit facility, debt issuances and sales of limited partner units. Our operating subsidiaries use cash 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 our revolving credit facility to service outstanding indebtedness and make distributions or advances to us to fund our distributions to unitholders. We have no material guarantees of debt or other similar commitments to unaffiliated parties.

Capital Expenditures

Maintenance capital expenditures for the nine months ended September 30, 2011 and 2010 were $60.6 million and $26.4 million. Growth capital expenditures, including trailing costs associated with our recently completed pipeline expansion projects, were $56.3 million and $145.0 million for the nine months ended September 30, 2011 and 2010. Excluding capital expenditures related to the Carthage Compressor Station incident for which insurance proceeds are expected to be received, we expect our 2011 growth and maintenance capital expenditures to be approximately $160.0 million, $82.0 million of which is for system maintenance primarily related to pipeline integrity management and reliability spending.

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Equity and Debt Financing

In January 2011, we received net proceeds of approximately $322.0 million after deducting initial purchaser discounts and offering expenses of $3.0 million from the sale of $325.0 million of 4.50% senior unsecured notes of Texas Gas due February 1, 2021 (2021 Notes). In June 2011, we issued an additional $115.0 million of the 2021 Notes. The additional issuance was priced at a premium resulting in net proceeds of $115.6 million after deducting underwriter discounts and offering expenses of $1.0 million. We used the proceeds from both offerings to repay borrowings under our revolving credit facility and redeem Texas Gas’ 5.50% notes due April 1, 2013 (2013 Notes) for which we paid premiums of $21.0 million. Note 7 in Item 1 of this report contains more information about the 2021 Notes and redemption of the 2013 Notes.

In June 2011, we completed a public offering of 6.0 million of our common units at a price of $29.33 per unit. We received net cash proceeds of approximately $173.6 million after deducting underwriting discounts and offering expenses of $6.0 million and including a $3.6 million contribution received from our general partner to maintain its 2% general partner interest.

Our ability to access the capital markets for debt and equity financing under reasonable terms depends on our financial condition, credit ratings and market conditions. We anticipate that our existing capital resources, including our revolving credit facility, and cash flow generated from future operations will be adequate to fund our operations, including our capital expenditures. From time to time, we expect to issue and sell debt and/or equity securities and to incur other indebtedness for general corporate purposes, including to refinance outstanding debt, including our revolving credit facility, and for potential acquisitions and growth opportunities.

Revolving Credit Facility

As of September 30, 2011, we had $458.5 million of loans outstanding under our revolving credit facility with a weighted-average interest rate of 0.48% and no letters of credit issued thereunder. At September 30, 2011, we had available borrowing capacity of $491.5 million and were in compliance with all covenant requirements under our credit facility.

Distributions

For the nine months ended September 30, 2011 and 2010, we paid distributions of $312.1 million and $296.9 million to our partners. Note 6 in Part I, Item 1 of this report contains further discussion regarding our distributions.

Changes in cash flow from operating activities

Net cash provided by operating activities decreased $9.3 million to $345.5 million for the nine months ended September 30, 2011, compared to $354.8 million for the comparable 2010 period, primarily due to a decrease in net income, excluding the non-cash materials and supplies impairment charge.

Changes in cash flow from investing activities

Net cash used in investing activities decreased $58.4 million to $99.4 million for the nine months ended September 30, 2011, compared to $157.8 million for the comparable 2010 period. The decrease was driven by a $57.3 million decrease in capital expenditures primarily related to the completion of compression projects in 2010.

Changes in cash flow from financing activities

Net cash used in financing activities increased $62.9 million to a use of cash of $216.9 million for the nine months ended September 30, 2011, compared to $154.0 million for the comparable 2010 period. The increase in cash used in financing activities resulted from net repayments of $207.4 million of long-term debt, including net repayments under our revolving credit facility, a $21.0 million premium paid on the early extinguishment of long-term debt and a $15.2 million increase in distributions to our partners. The increase in the use of cash was partly offset by a $173.6 million increase in proceeds from the issuance and sale of equity, including related general partner contributions, and $10.7 million of payments made under our registration rights agreement in 2010.

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Contractual Obligations

The following table summarizes significant contractual cash payment obligations under firm commitments as of September 30, 2011, by period (in millions):

	Total		Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years
Principal payments on long-term debt (1)	$	3,208.5	$	683.5	$	100.0	$	525.0	$	1,900.0
Interest on long-term debt (2)		928.1		151.7		265.4		229.1		281.9
Capital commitments (3)		31.1		31.1		-		-		-
Total	$	4,167.7	$	866.3	$	365.4	$	754.1	$	2,181.9

(1)   Includes our senior unsecured notes, having maturity dates from 2012 to 2027, $458.5 million of loans outstanding under our revolving credit facility, having a maturity date of June 29, 2012, and our Subordinated Loans which mature initially on December 29, 2012. Amounts outstanding under the revolving credit facility and Subordinated Loans are extendable by us for an additional year. We have reflected the $225.0 million of Gulf South notes due August 2012 (Gulf South 2012 Notes) as due in less than one year. The Gulf South 2012 Notes are included in long-term debt on our balance sheet because we expect to refinance these notes on a long-term basis and we have sufficient available capacity under our revolving credit facility to extend the amount that would otherwise come due in less than one year.

(2)   Interest obligations represent interest due on our senior unsecured notes at fixed rates. Future interest obligations under our revolving credit facility are uncertain, due to the variable interest rate and fluctuating balances. Based on a 0.48% weighted-average interest rate on amounts outstanding under our revolving credit facility as of September 30, 2011, $1.6 million would be due under the credit facility in less than one year.

(3)   Capital commitments represent binding commitments under purchase orders for materials ordered but not received and firm commitments under binding construction service agreements existing at September 30, 2011.

Subsequent to September 30, 2011, we entered into a joint venture with BPHC.  We will contribute 20%, or $70.0 million, of the equity interests in that joint venture. Note 16 in Part I, Item 1 of this report contains further discussion regarding this subsequent event.

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. In 2011, we have funded approximately $9.0 million to the Texas Gas pension plan and do not expect to make further contributions in 2011.

Off-Balance Sheet Arrangements

At September 30, 2011, 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

           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.

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During 2011, there have been 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, 2010.

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 our subsidiaries, are also forward-looking statements.

Forward-looking statements are based on current expectations and projections about future events and are inherently subject to a variety of risks and uncertainties, many of which are beyond our control that could cause actual results to differ materially from those anticipated or projected. These risks and uncertainties include, among others:

·   the impact of new pipelines or new gas supply sources on competition and basis spreads on our pipeline systems;

·   our ability to maintain or replace expiring gas transportation and storage contracts and to sell short-term capacity on our pipelines;

·   the impact of changes to laws and regulations, such as the proposed greenhouse gas legislation and the re-authorization by Congress of the Pipeline and Hazardous Materials Safety Administration and any regulatory changes that result from that legislation applicable to interstate pipelines, on our business, including our costs, liabilities and revenues;

·   the costs of maintaining and ensuring the integrity and reliability of our pipeline systems;

·   the timing, cost, scope and financial performance of our recent and future growth projects;

·   volatility or disruptions in the capital or financial markets;

·   the impact of Federal Energy Regulatory Commission’s rate-making policies and actions on the services we offer and the rates we charge and our ability to recover the full cost of operating our pipelines, including earning a reasonable return;

·   operational hazards, litigation and unforeseen interruptions for which we may not have adequate or appropriate insurance coverage;

·   the future cost of insuring our assets;

·   our ability to access new sources of natural gas and the impact on us of any future decreases in supplies of natural gas in our supply areas;

·   the consummation of contemplated transactions and agreements, including the pending acquisition of Petal and Hattiesburg and the anticipated financing of this acquisition;

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·   the impact on our system throughput and revenues from changes in the supply of and demand for natural gas, including as a result of commodity price changes; and

·   the additional risks and uncertainties as described in Part I—Item 1A “—Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2010.

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. 

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Item 3.  Quantitative and Qualitative Disclosures About Market Risk

Refer to Part II, Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2010, for discussion of our market risk.

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Item 4.  Controls and Procedures

Disclosure Controls and Procedures

Our principal executive officer (CEO) and principal financial officer (CFO) undertook an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of the end of the period covered by this report. The CEO and CFO have concluded that our disclosure controls and procedures were effective as of September 30, 2011.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended September 30, 2011, that have materially affected or that are reasonably likely to materially affect our internal control over financial reporting. 

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PART II – OTHER INFORMATION

Item 1.  Legal Proceedings

None.

Item 1A.  Risk Factors

There have been no material changes to the Risk Factors disclosed in Part I—Item 1A “—Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2010.

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Item 6.  Exhibits

The following documents are filed as exhibits to this report:

Exhibit Number
	Description
3.1	Certificate of Limited Partnership of Boardwalk Pipeline Partners, LP (Incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-127578, filed on August 16, 2005).
3.2	Third Amended and Restated Agreement of Limited Partnership of Boardwalk Pipeline Partners, LP dated as of June 17, 2008, (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on June 18, 2008).
3.3	Certificate of Limited Partnership of Boardwalk GP, LP (Incorporated by reference to Exhibit 3.3 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-127578, filed on August 16, 2005).
3.4	Agreement of Limited Partnership of Boardwalk GP, LP (Incorporated by reference to Exhibit 3.4 to Amendment No. 1 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-127578, filed on September 22, 2005).
3.5	Certificate of Formation of Boardwalk GP, LLC (Incorporated by reference to Exhibit 3.5 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-127578, filed on August 16, 2005).
3.6	Amended and Restated Limited Liability Company Agreement of Boardwalk GP, LLC (Incorporated by reference to Exhibit 3.6 to Amendment No. 4 to Registrant’s Registration Statement on Form S-1, Registration No. 333-127578, filed on October 31, 2005).
*3.7	Amendment No. 1 to the Third Amended and Restated Agreement of Limited Partnership of Boardwalk Pipeline Partners, LP, dated as of October 31, 2011.
4.1	Indenture, dated as of January 19, 2011, by and between Texas Gas Transmission, LLC, a Delaware limited liability company and The Bank of New York Mellon Trust Company, N.A., a national banking association (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K, filed on January 19, 2011).
4.2	First Supplemental Indenture dated June 7, 2011, between Texas Gas Transmission, LLC and The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Current report on Form 8-K, filed on June 13, 2011).
4.3	Second Supplemental Indenture dated June 16, 2011, between Texas Gas Transmission, LLC and The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Current report on Form 8-K, filed on June 20, 2011).
10.1	Amendment No. 5 to Amended and Restated Revolving Credit Agreement, dated as of June 3, 2011, 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	Employment agreement between Boardwalk GP, LLC and Stanley C. Horton (incorporated by reference to Exhibit 10.1 to the Registrant’s Current report on Form 8-K, filed on May 2, 2011).
*10.3	Amendment No. 4 to Amended and Restated Revolving Credit Agreement, dated as of August 31, 2010, among the Registrant, Boardwalk Pipelines, LP, Texas Gas Transmission, LLC and Gulf South Pipeline Company, LP, and the agent and lender parties identified therein.
*10.4	Limited Liability Company Agreement of Boardwalk HP Storage Company, LLC dated as of October 16, 2011.
*10.5	Letter agreement between Boardwalk Pipelines, LP and Boardwalk Pipelines Holding Corp. dated as of October 16, 2011.
*31.1	Certification of Stanley C. Horton, 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 Stanley C. Horton, 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.
*101.INS	XBRL Instance Document
*101.SCH	XBRL Taxonomy Extension Schema Document
*101.CAL	XBRL Taxonomy Calculation Linkbase Document
*101.DEF	XBRL Taxonomy Extension Definitions Document
*101.LAB	XBRL Taxonomy Label Linkbase Document
*101.PRE	XBRL Taxonomy Presentation Linkbase Document
* Filed herewith

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SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	Boardwalk Pipeline Partners, LP
		By: Boardwalk GP, LP
		its general partner
		By: Boardwalk GP, LLC
		its general partner
Dated: November 1, 2011			By:	/s/  Jamie L. Buskill
				Jamie L. Buskill
				Senior Vice President, Chief Financial Officer and Treasurer

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