bwp-20100930_form10q.htm

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, 2010

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 October 22, 2010, the registrant had 169,721,916 common units outstanding and 22,866,667 class B units outstanding.

TABLE OF CONTENTS

FORM 10-Q

September 30, 2010

BOARDWALK PIPELINE PARTNERS, LP

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

Condensed Consolidated Balance Sheets 3

Condensed Consolidated Statements of Income 5

Condensed Consolidated Statements of Cash Flows 6

Condensed Consolidated Statements of Changes in Partners’ Capital 7

Condensed Consolidated Statements of Comprehensive Income 8

Notes to Condensed Consolidated Financial Statements 9

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 30

Item 3. Quantitative and Qualitative Disclosures About Market Risk 37

Item 4. Controls and Procedures 38

PART II - OTHER INFORMATION

Item 1. Legal Proceedings 39

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 39

Item 6. Exhibits 40

Signatures 41

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Millions)

(Unaudited)

	September 30,		December 31,
ASSETS	2010		2009
Current Assets:
Cash and cash equivalents	$	88.8	$	45.8
Receivables:
Trade, net		83.2		95.5
Other		8.3		13.5
Gas transportation receivables		7.5		7.9
Costs recoverable from customers		10.1		6.0
Gas stored underground		5.7		2.1
Prepayments		14.2		10.1
Other current assets		4.2		10.0
Total current assets		222.0		190.9

Property, Plant and Equipment:
Natural gas transmission and other plant		6,771.3		6,623.8
Construction work in progress		222.7		231.4
Property, plant and equipment, gross		6,994.0		6,855.2
Less—accumulated depreciation and amortization		732.4		577.3
Property, plant and equipment, net		6,261.6		6,277.9

Other Assets:
Goodwill		163.5		163.5
Gas stored underground		133.4		133.7
Costs recoverable from customers		15.8		16.1
Other		111.2		113.7
Total other assets		423.9		427.0

Total Assets	$	6,907.5	$	6,895.8

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

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Millions)

(Unaudited)

	September 30,			December 31,
LIABILITIES AND PARTNERS’ CAPITAL	2010			2009
Current Liabilities:
Payables:
Trade	$	35.6		$	58.4
Affiliates		8.3			8.6
Other		22.2			17.8
Gas Payables:
Transportation		15.2			5.0
Storage		5.3			-
Accrued taxes, other		63.6			41.2
Accrued interest		30.9			41.8
Accrued payroll and employee benefits		18.5			16.4
Construction retainage		11.6			21.0
Deferred income		5.9			20.9
Other current liabilities		12.8			19.8
Total current liabilities		229.9			250.9

Long–term debt		3,151.8			3,000.0
Long–term debt – affiliate		100.0			100.0
Total long-term debt		3,251.8			3,100.0

Other Liabilities and Deferred Credits:
Pension liability		25.0			31.6
Asset retirement obligation		17.0			18.0
Provision for other asset retirement		50.4			47.0
Payable to affiliate		16.0			20.6
Other		57.8			63.5
Total other liabilities and deferred credits		166.2			180.7

Commitments and Contingencies

Partners’ Capital:
Common units – 169.7 million units issued and outstanding as of September 30, 2010, and December 31, 2009		2,546.3			2,640.5
Class B units – 22.9 million units issued and outstanding as of September 30, 2010, and December 31, 2009		683.6			683.6
General partner		63.3			65.5
Accumulated other comprehensive loss		(33.6	)		(25.4	)
Total partners’ capital		3,259.6			3,364.2
Total Liabilities and Partners’ Capital	$	6,907.5		$	6,895.8

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

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,
	2010			2009			2010			2009
Operating Revenues:
Gas transportation	$	234.2		$	175.7		$	734.0		$	545.9
Parking and lending		5.5			9.5			23.8			25.3
Gas storage		13.1			14.3			41.5			42.2
Other		4.8			5.9			15.5			16.8
Total operating revenues		257.6			205.4			814.8			630.2

Operating Costs and Expenses:
Fuel and gas transportation		27.7			11.6			81.8			38.1
Operation and maintenance		36.8			35.7			100.2			98.7
Administrative and general		33.2			29.8			98.8			89.3
Depreciation and amortization		54.2			52.5			161.3			150.5
Asset impairment		3.3			-			5.8			-
Net (gain) loss on disposal of operating assets		(12.7	)		1.4			(11.6	)		7.8
Taxes other than income taxes		22.0			20.0			66.0			59.6
Total operating costs and expenses		164.5			151.0			502.3			444.0

Operating income		93.1			54.4			312.5			186.2

Other Deductions (Income):
Interest expense		35.3			32.6			106.2			90.5
Interest expense – affiliates		2.0			3.1			6.0			4.8
Interest income		(0.2	)		-			(0.5	)		(0.2	)
Miscellaneous other income, net		-			-			(0.1	)		(0.2	)
Total other deductions		37.1			35.7			111.6			94.9

Income before income taxes		56.0			18.7			200.9			91.3

Income taxes (benefit)		0.2			(0.1	)		0.4			0.2

Net Income	$	55.8		$	18.8		$	200.5		$	91.1

Net Income per Unit:

Basic and diluted net income per unit:
Common units	$	0.28		$	0.10		$	1.02		$	0.51
Class B units	$	0.07		$	(0.10	)	$	0.39		$	(0.09	)
Cash distribution to common units	$	0.51		$	0.49		$	1.515		$	1.455
Cash distribution to class B units	$	0.30		$	0.30		$	0.90		$	0.90
Weighted-average number of units outstanding:
Common units		169.7			166.2			169.7			158.9
Class B units		22.9			22.9			22.9			22.9

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

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions)

(Unaudited)

	For the Nine Months Ended September 30,
	2010			2009
OPERATING ACTIVITIES:
Net income	$	200.5		$	91.1
Adjustments to reconcile to cash provided by operations:
Depreciation and amortization		161.3			150.5
Amortization of deferred costs		7.0			7.0
Asset impairment		5.8			-
Net (gain) loss on disposal of operating assets		(11.6	)		7.8
Changes in operating assets and liabilities:
Trade and other receivables		13.2			(8.3	)
Gas receivables and storage assets		4.0			(5.9	)
Costs recoverable from customers		(4.1	)		-
Inventories		-			(30.8	)
Other assets		5.5			(25.9	)
Trade and other payables		(24.1	)		18.0
Other payables, affiliates		1.9			2.8
Gas payables		5.9			(0.8	)
Accrued liabilities		14.2			21.0
Other liabilities		(24.7	)		39.2
Net cash provided by operating activities		354.8			265.7
INVESTING ACTIVITIES:
Capital expenditures		(174.2	)		(656.9	)
Proceeds from sale of operating assets		16.4			-
Sales of short-term investments		-			175.0
Net cash used in investing activities		(157.8	)		(481.9	)
FINANCING ACTIVITIES:
Proceeds from long-term debt, net of issuance costs		-			346.7
Proceeds from borrowings on revolving credit agreement		150.0			161.5
Repayment of borrowings on revolving credit agreement		-			(475.0	)
Payments on note payable		(0.3	)		(1.0	)
Proceeds from long-term debt - affiliate		-			200.0
Repayment of long-term debt - affiliate		-			(100.0	)
Payments associated with registration rights agreement		(10.7	)		-
Advances from affiliate		3.9			-
Distributions paid		(296.9	)		(263.9	)
Proceeds from sale of common units		-			326.3
Capital contribution from general partner		-			6.8
Net cash (used in) provided by financing activities		(154.0	)		201.4
Increase (decrease) in cash and cash equivalents		43.0			(14.8	)
Cash and cash equivalents at beginning of period		45.8			137.7
Cash and cash equivalents at end of period	$	88.8		$	122.9

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

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, 2009	$	2,504.8		$	692.8		$	62.9		$	(15.5	)	$	3,245.0
Add (deduct):
Net income		70.0			10.1			11.0			-			91.1
Distributions paid		(228.7	)		(20.6	)		(14.6	)		-			(263.9	)
Sale of common units, net of related transaction costs		320.2			-			6.8			-			327.0
Other comprehensive loss		-			-			-			(12.0	)		(12.0	)
Balance September 30, 2009	$	2,666.3		$	682.3		$	66.1		$	(27.5	)	$	3,387.2

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

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

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,
	2010			2009			2010			2009
Net income	$	55.8		$	18.8		$	200.5		$	91.1
Other comprehensive (loss) income:
Gain (loss) on cash flow hedges		1.3			(0.2	)		7.6			7.8
Reclassification adjustment transferred to Net income from cash flow hedges		(7.4	)		(5.8	)		(11.2	)		(13.8	)
Pension and other postretirement benefit costs		(1.5	)		(1.1	)		(4.6	)		(6.0	)
Total Comprehensive Income	$	48.2		$	11.7		$	192.3		$	79.1

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

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 subsidiary, 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, 2010, 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, 2010, the common units, class B units and general partner interest owned by BPHC represented approximately 66% 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, 2010, and December 31, 2009, and the results of operations and comprehensive income for the three and nine months ended September 30, 2010 and 2009, and changes in cash flow and changes in partners’ equity for the nine months ended September 30, 2010 and 2009. Reference is made to the Notes to Consolidated Financial Statements in the 2009 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 74.6 trillion British thermal units (TBtu) of gas owned by third parties as of September 30, 2010. Assuming an average market price during September 2010 of $3.82 per million British thermal units (MMBtu), the market value of gas held on behalf of others was approximately $285.0 million. As of December 31, 2009, the Partnership held for storage or under PAL agreements approximately 84.7 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 agreements. As of September 30, 2010, the amount of gas owed to the operating subsidiaries due to gas imbalances and gas loaned under PAL agreements was approximately 6.8 TBtu. Assuming an average market price during September 2010 of $3.82 per MMBtu, the market value of that gas was approximately $26.0 million. As of December 31, 2009, the amount of gas owed to the operating subsidiaries due to gas imbalances and gas loaned under PAL agreements was approximately 14.9 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.

Note 3: Derivative Financial Instruments

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 $4.7 million and $2.3 million of gas stored underground at September 30, 2010, and December 31, 2009, which the Partnership owns and carries on its condensed consolidated balance sheets as current Gas stored underground.

At September 30, 2010, approximately 0.2 billion cubic feet (Bcf) of anticipated future sales of natural gas and cash for fuel reimbursement were hedged with derivatives having settlement dates in 2010. 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. Approximately 3.3 Bcf of gas with a book value of $7.5 million became available for sale as a result of Phase III of the Western Kentucky Storage Expansion. This gas was sold in the third quarter 2010 and the related derivatives were settled, resulting in a gain of $12.1 million.

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, 2010, and December 31, 2009, were included in the following captions in the Condensed Consolidated Balance Sheets (in millions):

Asset Derivatives

Liability Derivatives

September 30, 2010

December 31, 2009

September 30, 2010

December 31, 2009

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

0.9

Other current

assets

6.2

Other current

liabilities

Other current

liabilities

The changes in fair values of the derivatives designated as cash flow hedges are expected to, and do, have a high correlation to changes in value of the anticipated transactions. Each reporting period the Partnership measures the effectiveness of the cash flow hedge contracts. To the extent the changes in the fair values of the hedge contracts do not effectively offset the changes in the estimated cash flows of the anticipated transactions, the ineffective portion of the hedge contracts is currently recognized in earnings. If it becomes probable that the anticipated transactions will not occur, hedge accounting would be terminated and changes in the fair values of the associated derivative financial instruments would be recognized currently in earnings. The Partnership did not discontinue any cash flow hedges during the three and nine month periods ended September 30, 2010 and 2009.

The effective component of unrealized gains and losses resulting from changes in fair values of the derivatives designated as cash flow hedges are deferred as a component of accumulated other comprehensive income or loss (AOCI). The deferred gains and losses associated with the anticipated operational sale of gas reported as current Gas stored underground are recognized in operating revenues when the anticipated transactions affect earnings. In situations where continued reporting of a loss in AOCI would result in recognition of a future loss on the combination of the derivative and the hedged transaction, the loss is required to be immediately recognized in earnings for the amount that is not expected to be recovered. No such losses were recognized for the three and nine month periods ended September 30, 2010 and 2009.

The Partnership estimates that approximately $0.5 million of net gains reported in AOCI as of September 30, 2010, 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, 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.

The amount of gains and losses from derivatives recognized in the Condensed Consolidated Statements of Income for the three months ended September 30, 2009, 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	$	(0.2	)	Operating revenues (2)	$	6.5		Net gain/(loss) on disposal of operating assets and related contracts		$	(0.3	)

Interest rate contracts (1)		-		Interest expense		(0.4	)		N/A		-
	$	(0.2	)		$	6.1				$	(0.3	)

(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)	$1.7 million was recorded in Gas transportation revenues and $4.8 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.

The amount of gains and losses from derivatives recognized in the Condensed Consolidated Statements of Income for the nine months ended September 30, 2009, 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	$	7.8	Operating revenues (2)	$	15.5		Net gain/(loss) on disposal of operating assets and related contracts		$	(0.4	)

Interest rate contracts (1)		-	Interest expense		(1.3	)		N/A		-
	$	7.8		$	14.2				$	(0.4	)

(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)	$4.7 million was recorded in Gas transportation revenues and $10.8 million was recorded in Other Revenues.

At September 30, 2010, all of the Partnership’s derivatives were with two counterparties, however outstanding asset positions under derivative contracts have not resulted in a material concentration of credit risk. In accordance with the contracts governing the Partnership’s derivatives, the counterparty or the Partnership may be required to post cash collateral when credit risk exceeds certain thresholds. At September 30, 2010, and at December 31, 2009, the Partnership was not required to post any collateral nor did it hold any collateral associated with its outstanding derivatives.

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 taxes which are presented in Income taxes on the Condensed Consolidated Statements of Income.

Note 5: Commitments and Contingencies

Legal Proceedings

Napoleonville Salt Dome Matter

Following the December 2003 accidental release of natural gas from storage in a salt dome cavern operated by Gulf South at the Dow Hydrocarbon and Resources, Inc. (Dow Hydrocarbon), Grand Bayou facility in Belle Rose, Louisiana, several suits were filed, including two that were initially filed as class actions. One of the cases initially filed as a class action was settled in 2008.

The other, a lawsuit entitled Crystal Aucoin, et al. v. Gulf South Pipeline Company, LP, et al., No. 28,157, was filed on February 12, 2004, in the 23rd Judicial District Court for the Parish of Assumption, State of Louisiana. The suit was initially filed as a class action. The defendants at the trial were Gulf South, Dow Chemical Company (Dow Chemical), Dow Hydrocarbon and one of Gulf South’s insurers, Oil Insurance Limited (OIL). The plaintiffs voluntarily dismissed their class action allegations on February 2, 2006. Since that time the case has proceeded in the same court as a mass joinder of approximately 1,200 individual claims. The plaintiffs seek damages for alleged inconvenience and emotional distress arising from being forced to drive on a detour around a road closed due to the gas release. In October 2010, the parties to the mass joinder claims have agreed to a tentative settlement for an immaterial amount which the Partnership expects to be covered by insurance. The settlement is subject to preliminary court approval, notice to the plaintiffs and final court approval. Final settlement of the matter is expected to occur in the first quarter 2011.

In March 2010, Gulf South and its insurers settled all of the claims between them and Dow Hydrocarbon and its affiliates arising out of the December 2003 accidental release referred to above. These claims were settled with no material adverse impact on the Partnership's financial condition, results of operations or cash flows. Pursuant to the settlement agreement, Gulf South and OIL have agreed to indemnify Dow for any damages awarded in the Aucoin case.

Other Legal Matters

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. The Partnership accrues for environmental expenses resulting from existing conditions that relate to past operations when the costs are probable and can be reasonably estimated. In addition to federal and state mandated remediation requirements, the Partnership often enters into voluntary remediation programs with regulatory agencies. Depending on the results of on-going assessments and review of any data collected, the Partnership’s liabilities for environmental remediation are updated based on new facts and circumstances. The actual costs incurred will depend on the actual amount and extent of contamination discovered, the final cleanup standards mandated by the Environmental Protection Agency or other governmental authorities and other factors.

As of September 30, 2010, and December 31, 2009, the Partnership had an accrued liability of approximately $12.2 million and $14.1 million related to assessment and/or remediation costs associated with the historical use of polychlorinated biphenyls, petroleum hydrocarbons and mercury, enhancement of groundwater protection measures and other costs. The 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, 2010, and December 31, 2009, approximately $3.0 million was recorded in Other current liabilities for both periods and approximately $9.2 million and $11.1 million were recorded in Other Liabilities and Deferred Credits.

Commitments

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 agreements. These commitments as of September 30, 2010, were approximately (in millions):

Less than 1 year	$	26.9
1-3 years		-
4-5 years		-
More than 5 years		-
Total	$	26.9

There were no substantial changes to the Partnership’s operating lease commitments or pipeline capacity agreements disclosed in Note 3 to the Partnership’s 2009 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%

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%

(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.

In the third quarter 2010, the Partnership paid quarterly distributions to its common 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 the third quarter 2009, the Partnership paid quarterly distributions to unitholders of record of $0.49 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 2010, the Partnership declared a quarterly cash distribution to unitholders of record of $0.515 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 losses) 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, 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

	Total			Common Units			Class B Units			General Partner and IDRs
Net income	$	18.8
Declared distribution		96.7		$	84.0		$	6.9		$	5.8
Assumed allocation of undistributed net loss		(77.9	)		(67.1	)		(9.2	)		(1.6	)
Assumed allocation of net income (loss)	$	18.8		$	16.9		$	(2.3	)	$	4.2
Weighted average units outstanding					166.2			22.9
Net income (loss) per unit				$	0.10		$	(0.10	)

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

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, 2009 (in millions, except per unit data):

	Total			Common Units			Class B Units			General Partner and IDRs
Net income	$	91.1
Declared distribution		274.9		$	238.3		$	20.6		$	16.0
Assumed allocation of undistributed net loss		(183.8	)		(157.4	)		(22.7	)		(3.7	)
Assumed allocation of net income (loss)	$	91.1		$	80.9		$	(2.1	)	$	12.3
Weighted average units outstanding					158.9			22.9
Net income (loss) per unit				$	0.51		$	(0.09	)

Note 7: Financing

Notes and Debentures

As of September 30, 2010, and December 31, 2009, the Partnership had notes and debentures outstanding of $2.4 billion with a weighted-average interest rate of 5.89%. 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, 2010, Boardwalk Pipelines and its operating subsidiaries were in compliance with their debt covenants.

In August 2009, the Partnership received net proceeds of approximately $346.7 million after deducting initial purchaser discounts and offering expenses of $3.3 million from the sale of $350.0 million of 5.75% senior unsecured notes of Boardwalk Pipelines due September 15, 2019.

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, 2010, and December 31, 2009, were $703.5 million and $553.5 million with a weighted-average borrowing rate of 0.52% and 0.48%.

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, 2010. 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 the second quarter 2009, Boardwalk Pipelines entered into a Subordinated Loan Agreement with BPHC, under which Boardwalk Pipelines borrowed $200.0 million. At September 30, 2010 and December 31, 2009, the Partnership had $100.0 million outstanding under the Subordinated Loan Agreement with no additional borrowing capacity available.

Common Unit Offering

In August 2009, the Partnership completed a public offering of 8.1 million of its common units at a price of $23.00 per unit. The Partnership received net cash proceeds of approximately $183.1 million after deducting underwriting discounts and offering expenses of $7.0 million and including a $3.8 million contribution received from its general partner to maintain its 2% general partner interest.

In June 2009, the Partnership issued and sold 6.7 million common units to BPHC at a price of $21.99 per unit. The Partnership received proceeds of $150.0 million, including the general partner contribution of $3.0 million to maintain its 2% interest.

Note 8: Property, Plant and Equipment (PPE)

In 2010, the Partnership placed in service the remaining compression facilities associated with its Gulf Crossing Project and Fayetteville and Greenville Laterals. As a result, approximately $170.7 million was transferred from construction work in progress to plant. In 2009, the Partnership placed in service its Gulf Crossing Project and Fayetteville and Greenville Laterals and the remaining compression facilities associated with its Southeast Expansion project. As a result, approximately $2.3 billion was transferred from construction work in progress to plant. The assets will generally be depreciated over a term of 35 years.

Note 9: Asset Dispositions and Impairments

In the third quarter 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 loss of approximately $2.2 million, representing the remaining net book value of the assets.

The Partnership has agreed to sell pipe materials with a book value of $11.5 million for estimated consideration of approximately $8.2 million. As a result, the Partnership recorded an impairment charge of $3.3 million in the third quarter 2010.

The fair value measurements of the Overton Field assets and pipe materials were based on Level 3 inputs under the fair value hierarchy.

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 which was included in Net gain on disposal of operating assets.

Note 10: 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. 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 and nine months ended September 30, 2010 and 2009 were as follows (in millions):

	Retirement Plans						PBOP
	For the Three Months Ended						For the Three Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Service cost	$	0.9		$	0.9		$	0.1		$	0.1
Interest cost		1.7			1.7			0.7			0.8
Expected return on plan assets		(1.7	)		(1.4	)		(0.9	)		(0.9	)
Amortization of prior service credit		-			-			(2.0	)		(2.0	)
Amortization of unrecognized net loss		0.3			0.5			0.2			0.4
Regulatory asset decrease		-			-			1.4			1.4
Net periodic benefits expense	$	1.2		$	1.7		$	(0.5	)	$	(0.2	)

	Retirement Plans						PBOP
	For the Nine Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Service cost	$	2.8		$	2.7		$	0.3		$	0.3
Interest cost		5.1			5.1			2.1			2.3
Expected return on plan assets		(5.2	)		(4.1	)		(2.8	)		(2.6	)
Amortization of prior service credit		-			-			(5.8	)		(5.8	)
Amortization of unrecognized net loss		1.0			1.4			0.6			1.1
Regulatory asset decrease		-			-			4.1			4.1
Net periodic benefits expense	$	3.7		$	5.1		$	(1.5	)	$	(0.6	)

In 2010, the Partnership contributed $9.2 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 $5.5 million for the three and nine months ended September 30, 2010 and $1.7 million and $5.0 million for the three and nine months ended September 30, 2009.

Note 11: 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, corporate development services and allocated overheads. Loews charged $3.2 million and $12.4 million for the three and nine months ended September 30, 2010 and $4.0 million and $11.9 million for the three and nine months ended September 30, 2009, to the Partnership for performing these services.

Distributions paid related to limited partner units held by BPHC and the 2% general partner interest and IDRs held by Boardwalk GP were $201.2 million and $195.0 million during the nine months ended September 30, 2010 and 2009.

Registration Rights Agreement

In February 2010, BPHC sold 11.5 million Partnership common units in a secondary offering. In accordance with the registration rights agreement between the Partnership and BPHC, 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 the previously established liability. As of September 30, 2010, and December 31, 2009, the Partnership had an accrued liability of $16.0 million and $26.7 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.

Note 12: 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			As of
	September 30, 2010			December 31, 2009
Loss on cash flow hedges	$	(10.3	)	$	(6.7	)
Deferred components of net periodic benefit cost		(23.3	)		(18.7	)
Total Accumulated other comprehensive loss	$	(33.6	)	$	(25.4	)

Note 13: 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, 2010, and December 31, 2009. The fair market value of the debt that is not publicly traded is based on market prices of similar debt at September 30, 2010, and December 31, 2009.

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.

The carrying amount and estimated fair values of the Partnership’s financial instruments as of September 30, 2010, and December 31, 2009, were as follows (in millions):

	September 30, 2010				December 31, 2009
Financial Assets	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents	$	88.8	$	88.8	$	45.8	$	45.8

Financial Liabilities
Long-term debt	$	3,151.8	$	3,390.1	$	3,000.0	$	3,060.6
Long-term debt – affiliate		100.0		106.0		100.0		108.0

Note 14: Supplemental Disclosure of Cash Flow Information (in millions):

	For the Nine Months Ended September 30,
	2010		2009
Cash paid during the period for:
Interest (net of amount capitalized)	$	116.9	$	95.5
Non-cash adjustments:
Accounts payable and PPE	$	29.0	$	74.3
Accrued registration rights costs	$	-	$	6.1

Note 15: 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, 2010, and December 31, 2009. 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.

Condensed Consolidating Balance Sheets as of September 30, 2010

(in millions)

Assets	Parent Guarantor			Subsidiary Issuer		Non- guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Cash and cash equivalents	$	-		$	83.6	$	5.2		$	-		$	88.8
Receivables		-			-		102.4			(10.9	)		91.5
Gas stored underground		-			-		5.7			-			5.7
Prepayments		0.1			-		14.7			(0.6	)		14.2
Advances to affiliates		-			108.8		-			(108.8	)		-
Other current assets		-			-		26.1			(4.3	)		21.8
Total current assets		0.1			192.4		154.1			(124.6	)		222.0
Investment in consolidated subsidiaries		723.6			4,838.1		-			(5,561.7	)		-
Property, plant and equipment, gross		0.6			-		6,993.4			-			6,994.0
Less–accumulated depreciation and amortization		(0.5	)		-		(731.9	)		-			(732.4	)
Property, plant and equipment, net		0.1			-		6,261.5			-			6,261.6
Other noncurrent assets		-			1.9		421.7			0.3			423.9
Advances to affiliates – noncurrent		2,554.7			26.1		297.5			(2,878.3	)		-
Total other assets		2,554.7			28.0		719.2			(2,878.0	)		423.9

Total Assets	$	3,278.5		$	5,058.5	$	7,134.8		$	(8,564.3	)	$	6,907.5

Liabilities & Partners' Capital/Member’s Equity	Parent Guarantor		Subsidiary Issuer		Non- guarantor Subsidiaries		Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Payables	$	2.9	$	6.2	$	92.3	$	(14.8	)	$	86.6
Advances from affiliates		-		-		108.8		(108.8	)		-
Other current liabilities		-		12.4		131.6		(0.7	)		143.3
Total current liabilities		2.9		18.6		332.7		(124.3	)		229.9
Total long-term debt		-		1,464.1		1,787.7		-			3,251.8
Payable to affiliate		16.0		2,852.2		26.1		(2,878.3	)		16.0
Other noncurrent liabilities		-		-		150.2		-			150.2
Total other liabilities and deferred credits		16.0		2,852.2		176.3		(2,878.3	)		166.2
Total partners’ capital/member’s equity		3,259.6		723.6		4,838.1		(5,561.7	)		3,259.6

Total Liabilities and Partners' Capital/Member’s Equity	$	3, 278.5	$	5,058.5	$	7,134.8	$	(8,564.3	)	$	6,907.5

Condensed Consolidating Balance Sheets as of December 31, 2009

(in millions)

Assets	Parent Guarantor			Subsidiary Issuer		Non- guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Cash and cash equivalents	$	-		$	45.6	$	0.2		$	-		$	45.8
Receivables		-			-		137.9			(28.9	)		109.0
Gas stored underground		-			-		2.1			-			2.1
Prepayments		-			-		10.1			-			10.1
Advances to affiliates		-			128.0		-			(128.0	)		-
Other current assets		0.3			-		25.2			(1.6	)		23.9
Total current assets		0.3			173.6		175.5			(158.5	)		190.9
Investment in consolidated subsidiaries		754.9			4,592.2		-			(5,347.1	)		-
Property, plant and equipment, gross		0.6			-		6,854.6			-			6,855.2
Less–accumulated depreciation and amortization		(0.4	)		-		(576.9	)		-			(577.3	)
Property, plant and equipment, net		0.2			-		6,277.7			-			6,277.9
Other noncurrent assets		0.4			2.1		424.5			-			427.0
Advances to affiliates – noncurrent		2,638.2			121.6		165.8			(2,925.6	)		-
Total other assets		2,638.6			123.7		590.3			(2,925.6	)		427.0

Total Assets	$	3,394.0		$	4,889.5	$	7,043.5		$	(8,431.2	)	$	6,895.8

Liabilities & Partners' Capital/Member’s Equity	Parent Guarantor		Subsidiary Issuer			Non- guarantor Subsidiaries		Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Payables	$	8.9	$	0.3		$	104.5	$	(28.9	)	$	84.8
Advances from affiliates		-		-			128.0		(128.0	)		-
Other current liabilities		0.3		16.9			150.5		(1.6	)		166.1
Total current liabilities		9.2		17.2			383.0		(158.5	)		250.9
Total long-term debt		-		1,313.5			1,786.5		-			3,100.0
Payable to affiliate		20.6		2,804.0			121.6		(2,925.6	)		20.6
Other noncurrent liabilities		-		(0.1	)		160.2		-			160.1
Total other liabilities and deferred credits		20.6		2,803.9			281.8		(2,925.6	)		180.7
Total partners’ capital/member’s equity		3,364.2		754.9			4,592.2		(5,347.1	)		3,364.2

Total Liabilities and Partners' Capital/Member’s Equity	$	3,394.0	$	4,889.5		$	7,043.5	$	(8,431.2	)	$	6,895.8

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

(in 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 income (loss)		(0.1	)		-			93.2			-			93.1

Other deductions (income):
Interest expense, affiliate, net		(9.7	)		12.1			(0.4	)		-			2.0
Interest expense		-			16.3			19.0			-			35.3
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

Condensed Consolidating Statements of Income for the Three Months Ended September 30, 2009

(in millions)

	Parent Guarantor			Subsidiary Issuer			Non- guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Operating revenues:
Gas transportation	$	-		$	-		$	192.5		$	(16.8	)	$	175.7
Parking and lending		-			-			11.9			(2.4	)		9.5
Gas storage		-			-			14.3			-			14.3
Other		-			-			5.9			-			5.9
Total operating revenues		-			-			224.6			(19.2	)		205.4

Operating cost and expenses:
Fuel and gas transportation		-			-			30.8			(19.2	)		11.6
Operation and maintenance		-			-			35.7			-			35.7
Administrative and general		-			-			29.8			-			29.8
Other operating costs and expenses		-			-			73.9			-			73.9
Total operating costs and Expenses		-			-			170.2			(19.2	)		151.0
Operating income		-			-			54.4			-			54.4

Other deductions (income):
Interest expense, affiliate, net		(9.6	)		10.4			2.3			-			3.1
Interest expense		-			13.2			19.4			-			32.6
Equity in earnings of subsidiaries		(9.2	)		(32.8	)		-			42.0			-
Total other deductions (income)		(18.8	)		(9.2	)		21.7			42.0			35.7
														-
Income before income taxes		18.8			9.2			32.7			(42.0	)		18.7
Income Taxes (Benefit)		-			-			(0.1	)		-			(0.1	)

Net Income	$	18.8		$	9.2		$	32.8		$	(42.0	)	$	18.8

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

(in 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, affiliate, net		(27.0	)		33.2			(0.2	)		-			6.0
Interest expense		-			48.5			57.7			-			106.2
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

Condensed Consolidating Statements of Income for the Nine Months Ended September 30, 2009

(in millions)

	Parent Guarantor			Subsidiary Issuer			Non- guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Operating revenues:
Gas transportation	$	-		$	-		$	570.5		$	(24.6	)	$	545.9
Parking and lending		-			-			28.6			(3.3	)		25.3
Gas storage		-			-			42.5			(0.3	)		42.2
Other		-			-			16.8			-			16.8
Total operating revenues		-			-			658.4			(28.2	)		630.2

Operating cost and expenses:
Fuel and gas transportation		-			-			66.0			(27.9	)		38.1
Operation and maintenance		-			-			99.0			(0.3	)		98.7
Administrative and general		(0.3	)		-			89.6			-			89.3
Other operating costs and expenses		0.3			-			217.6			-			217.9
Total operating costs and Expenses		-			-			472.2			(28.2	)		444.0
Operating income		-			-			186.2			-			186.2

Other deductions (income):
Interest expense, affiliate, net		(33.6	)		35.9			2.5			-			4.8
Interest expense		-			34.3			56.2			-			90.5
Interest income		-			(0.2	)		-			-			(0.2	)
Equity in earnings of subsidiaries		(57.5	)		(127.5	)		-			185.0			-
Miscellaneous other income, net		-			-			(0.2	)		-			(0.2	)
Total other deductions (income)		(91.1	)		(57.5	)		58.5			185.0			94.9
														-
Income before income taxes		91.1			57.5			127.7			(185.0	)		91.3
Income Taxes		-			-			0.2			-			0.2

Net Income	$	91.1		$	57.5		$	127.5		$	(185.0	)	$	91.1

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

(in 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 (Used in) Provided by 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 Provided by (Used in) 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

Condensed Consolidating Statements of Cash Flow for the Nine Months Ended September 30, 2009

(in millions)

	Parent Guarantor			Subsidiary Issuer			Non- guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Net Cash Provided by (Used In) Operating Activities	$	91.9		$	(63.3)		$	294.6		$	(57.5	)	$	265.7

Investing Activities:
Capital expenditures		-			-			(656.9	)		-			(656.9	)
Advances to affiliates, net		(366.5	)		(120.4	)		247.1			239.8			-
Distribution from consolidated subsidiary		206.4			-			-			(206.4	)		-
Investment in consolidated subsidiary		-			(85.6	)		-			85.6			-
Note receivable – affiliate		-			(3.0	)		-			3.0			-
Sales of short-term investments		-			175.0			-			-			175.0
Net Cash (Used in) Provided by Investing Activities		(160.1	)		(34.0)			(409.8	)		122.0			(481.9	)

Financing Activities:
Proceeds from long-term debt, net of issuance costs		-			346.7			-			-			346.7
Proceeds from borrowings on revolving credit agreement		-			-			161.5			-			161.5
Repayment of borrowings on revolving credit agreement		-			(225.0	)		(250.0	)		-			(475.0	)
Note payable – affiliate		-			-			3.0			(3.0	)		-
Payments on notes payable		(1.0	)		-			-			-			(1.0	)
Proceeds from long-term debt – affiliate		-			200.0			-			-			200.0
Repayment of long-term debt – affiliate		-			(100.0	)		-			-			(100.0	)
Contribution from parent		-			-			85.6			(85.6	)		-
Distributions paid		(263.9	)		(263.9	)		-			263.9			(263.9	)
Proceeds from sale of common units		326.3			-			-			-			326.3
Capital contribution from general partner		6.8			-			-			-			6.8
Advances from affiliates, net		-			119.4			120.4			(239.8	)		-
Net Cash Provided by (Used in) Financing Activities		68.2			77.2			120.5			(64.5	)		201.4

Increase (Decrease) in Cash and Cash Equivalents		-			(20.1	)		5.3			-			(14.8	)
Cash and Cash Equivalents at Beginning of Period		-			137.6			0.1			-			137.7
Cash and Cash Equivalents at End of Period	$	-		$	117.5		$	5.4		$	-		$	122.9

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, 2009.

Overview

Through our operating subsidiaries, Gulf Crossing Pipeline Company LLC (Gulf Crossing), Gulf South Pipeline Company, LP (Gulf South) and Texas Gas Transmission, LLC (Texas Gas), we own and operate three interstate natural gas pipeline systems including integrated storage facilities. Our pipeline systems originate in the Gulf Coast region including Oklahoma and Arkansas, and extend northeasterly to the Midwestern states of Tennessee, Kentucky, Illinois, Indiana and Ohio. As of September 30, 2010, Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned subsidiary of Loews Corporation (Loews) owned 102.7 million of our common units, all 22.9 million of our 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, 2010, the common units, class B units and general partner interest owned by BPHC represented approximately 66% of our equity interests, excluding the IDRs. Our common units are traded under the symbol “BWP” on the New York Stock Exchange.

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

Competition and Contract Renewals

Our ability to market available interstate transportation and storage capacity is impacted by demand for natural gas, competition from other pipelines, natural gas price volatility, the price differential between receipt and delivery points on our pipeline systems (basis spreads), economic conditions and numerous other factors beyond our control. We compete with numerous interstate and intrastate pipelines, including several pipeline projects which have recently been placed in service or are in the process of being developed. Additionally, significant new sources of natural gas have recently been identified throughout the United States which have created changes in pricing dynamics between supply basins, pooling points and market areas. As a result of the increase in overall pipeline capacity and the new sources of supply, the price differentials on our pipeline systems have narrowed.

Given current market conditions, marketing our currently available capacity and renewing expiring contracts have become more difficult. Our ability to renew some of our expiring contracts at favorable rates, and our revenues from interruptible and short-term firm transportation services, have been negatively impacted by these market conditions. Capacity that we have available on a short-term basis will decrease as long-term capacity commitments on our recently completed pipeline expansion projects increase through 2011. However, some of our capacity will continue to be available for sale on a short-term firm or interruptible basis and each year a portion of our existing contracts expire. The revenues we will be able to earn from that available capacity and from renewals of expiring contracts will be heavily dependent upon basis spreads. It is not possible to accurately predict future basis spreads.

Growth Projects

During 2010, we placed in service the remaining compression facilities associated with our Gulf Crossing Pipeline and the Fayetteville and Greenville Laterals which increased the peak-day delivery capacities of those projects. With the exception of post-construction activities such as right-of-way restoration, our East Texas Pipeline, Southeast Expansion, Gulf Crossing Project and Fayetteville and Greenville Laterals (pipeline expansion projects) are complete.

In the fourth quarter 2010, we received authority from the Pipeline and Hazardous Materials Safety Administration (PHMSA) to operate our Fayetteville Lateral at higher than normal operating pressures. This will allow us to operate the Fayetteville Lateral at its design capacity of 1.3 billion cubic feet (Bcf) per day and to meet its increasing contractual obligations in the fourth quarter 2010.

Set forth below is information with respect to the status of our announced growth projects.

Haynesville Project. The Haynesville Project consists of adding compression to our East Texas Pipeline in Louisiana, which adds approximately 0.6 Bcf per day of peak-day transmission capacity with delivery capabilities from the DeSoto, Louisiana, area to the Perryville, Louisiana, area. The Haynesville Project was placed in service in October 2010. Customers have contracted for substantially all of the firm capacity on this project at a weighted-average contract life of approximately 12.2 years.

Clarence Compression Project. The Clarence Compression Project, which also targets production from the Haynesville Shale, will add approximately 0.1 Bcf per day of peak-day transmission capacity. This project will receive gas from the Holly Field area in Northwest Louisiana, and deliver to a third-party pipeline interconnect near Olla, Louisiana. Customers have contracted for approximately 0.1 Bcf per day of capacity with a weighted-average contract life of approximately 11.0 years. We recently received Federal Energy Regulatory Commission (FERC) approval for this project which is expected to be in service in late 2011.

Results of Operations for the Three Months Ended September 30, 2010 and 2009

Our net income for the three months ended September 30, 2010 increased $37.0 million, or 197%, to $55.8 million compared to $18.8 million for the three months ended September 30, 2009. The primary drivers were higher revenues from transportation services from our pipeline expansion projects and gains on gas sales associated with our Western Kentucky Storage Expansion project, partially offset by increased operating expenses associated with our pipeline expansion projects. In 2009, gas transportation revenues and throughput were negatively impacted due to operating our pipeline expansion projects at reduced operating pressures and portions of the pipeline expansion projects being shut down for periods of time following the discovery and remediation of anomalies in certain joints of pipe.

Operating revenues for the three months ended September 30, 2010 increased $52.2 million, or 25%, to $257.6 million, compared to $205.4 million for the three months ended September 30, 2009. Gas transportation revenues, excluding fuel, increased $46.4 million and fuel retained increased $11.0 million primarily due to our pipeline expansion projects.

Operating costs and expenses for the three months ended September 30, 2010 increased $13.5 million, or 9%, to $164.5 million, compared to $151.0 million for the three months ended September 30, 2009. The primary factors for the increase were increased fuel consumed of $16.5 million due to our pipeline expansion projects and higher natural gas prices, higher depreciation and property taxes of $3.7 million associated with an increase in our asset base and increased maintenance activities of $2.4 million. An impairment loss of $3.3 million was recognized in the third quarter 2010 related to a portion of pipe materials which we expect to dispose of by sale. The increased expenses were partly offset by a $12.3 million gain from the sale of gas related to our Western Kentucky Storage Expansion project. The 2009 period was unfavorably impacted by $1.9 million from pipeline investigation and retirement costs related to the East Texas Pipeline, which impacted operations and maintenance expenses and loss on disposal of assets.

Total other deductions increased by $1.4 million, or 4%, to $37.1 million for the three months ended September 30, 2010, compared to $35.7 million for the 2009 period. The primary factor for the increase was higher interest expense of $1.6 million resulting from increased debt levels.

Results of Operations for the Nine Months Ended September 30, 2010 and 2009

Our net income for the nine months ended September 30, 2010 increased $109.4 million, or 120%, to $200.5 million compared to $91.1 million for the nine months ended September 30, 2009. The primary drivers were higher revenues from transportation services from our pipeline expansion projects and gains on gas sales associated with our Western Kentucky Storage Expansion project, partially offset by increased operating expenses related to increases in depreciation and property taxes associated with the expansion projects and increased interest expense. In 2009, gas transportation revenues and throughput were negatively impacted due to operating our pipeline expansion projects at reduced operating pressures and portions of the pipeline expansion projects being shut down for periods of time following the discovery and remediation of anomalies in certain joints of pipe.

Operating revenues for the nine months ended September 30, 2010 increased $184.6 million, or 29%, to $814.8 million, compared to $630.2 million for the nine months ended September 30, 2009. Gas transportation revenues, excluding fuel, increased $171.5 million and fuel retained increased $29.0 million primarily due to our pipeline expansion projects. The increases were partially offset by $13.7 million of lower interruptible and short-term firm transportation services resulting from lower basis spreads between delivery points on our pipeline systems.

Operating costs and expenses for the nine months ended September 30, 2010 increased $58.3 million, or 13%, to $502.3 million, compared to $444.0 million for the nine months ended September 30, 2009. The primary factors for the increase were increased fuel consumed of $43.7 million due to our pipeline expansion projects and higher depreciation and property taxes of $19.6 million associated with an increase in our asset base. Administrative and general expenses increased $9.5 million due to a legal settlement, an increase in outside services and unit-based compensation driven by an increase in the price of our common units. Impairment losses of $5.8 million were recognized in 2010 related to assets in the Overton Field area in northeast Texas, which were sold in the third quarter 2010, and a portion of pipe materials which we expect to dispose of by sale. The increased expenses were partly offset by a $12.3 million gain from the sale of gas related to our Western Kentucky Storage Expansion project. The 2009 period was unfavorably impacted by $6.0 million as a result of pipeline investigation and retirement costs related to the East Texas Pipeline.

Total other deductions increased by $16.7 million, or 18%, to $111.6 million for the nine months ended September 30, 2010, compared to $94.9 million for the 2009 period. The primary factor for the increase was higher interest expense of $16.9 million resulting from increased debt levels in 2010 and lower capitalized interest due to the completion of our pipeline expansion projects.

Liquidity and Capital Resources

We are a partnership holding company and derive all of our operating cash flow from our operating subsidiaries. Our 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, when available, 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.

Maintenance Capital Expenditures

Maintenance capital expenditures for the nine months ended September 30, 2010 and 2009 were $26.4 million and $26.1 million. Our remaining 2010 maintenance capital expenditures of approximately $24.0 million are expected to be funded from our operating cash flows.

Growth Capital Expenditures

The following table presents our estimate of total capital expenditures for our growth projects and the amounts invested in those projects through September 30, 2010 (in millions):

	Estimated Total Cost (1)		Cash Invested through September 30, 2010
Haynesville Project	$	110	$	76.0
Clarence Compression		30		4.5
Total	$	140	$	80.5

(1)	Our estimated total capital expenditures are based on internally developed financial models and timelines.

In the third quarter, we reduced our cost estimates from $185.0 million to $110.0 million for the Haynesville Project resulting in a $75.0 million reduction, primarily due to lower materials and labor costs and placing the project in service earlier than expected. Growth capital expenditures, including our pipeline expansion projects, were $145.0 million for the nine months ended September 30, 2010. As discussed in Growth Projects, our major pipeline expansion projects are complete. However, we will continue to incur costs for post-construction activities such as clean up, right-of-way restoration and system optimization. For the remainder of 2010 and 2011, we expect to invest approximately $125.0 million to complete our growth projects. Our cost and timing estimates for these projects are subject to a variety of risks and uncertainties as discussed in Item 1A, Risk Factors, of our Annual Report on Form 10-K for the year ended December 31, 2009.

Revolving Credit Facility

As of September 30, 2010, we had $703.5 million in loans outstanding under our revolving credit facility with a weighted-average interest rate of 0.52% and had no letters of credit issued. At September 30, 2010, we had available borrowing capacity of $246.5 million and were in compliance with all covenant requirements under our credit facility.

Distributions

For the nine months ended September 30, 2010 and 2009, we paid distributions of $296.9 million and $263.9 million. Note 6 in Part 1, Item 1 of this report contains further discussion regarding our distributions.

Changes in cash flow from operating activities

Net cash provided by operating activities increased $89.1 million to $354.8 million for the nine months ended September 30, 2010, compared to $265.7 million for the comparable 2009 period, primarily due to an increase in net income.

Changes in cash flow from investing activities

Net cash used in investing activities decreased $324.1 million to $157.8 million for the nine months ended September 30, 2010, compared to $481.9 million for the comparable 2009 period. The decrease was driven by a $482.7 million decrease in capital expenditures primarily related to the completion of our pipeline expansion projects and $16.4 million in proceeds from the sale of assets, mainly comprised of gas sales as a result of the Western Kentucky Storage Expansion. The decreases were partially offset by the sale of $175.0 million of short-term investments which occurred in the 2009 period.

Changes in cash flow from financing activities

Net cash used in financing activities increased $355.4 million to a use of cash of $154.0 million for the nine months ended September 30, 2010, compared to cash provided by financing activities of $201.4 million for the comparable 2009 period. The increase in cash used in financing activities resulted from a $779.8 million reduction in proceeds from the issuance and sale of debt and equity, including related general partner contributions, a $33.0 million increase in distributions to our partners and $10.7 million of payments made under our registration rights agreement. The increases were partly offset by a decrease of $463.5 million in net repayments related to our revolving credit facility.

Contractual Obligations

The table below is updated for significant changes in contractual cash payment obligations as of September 30, 2010, by period (in millions):

	Total		Less than 1 Year		1-3 Years		4-5 Years		More than 5 Years
Principal payments on long-term debt (1)	$	3,263.5	$	-	$	1,028.5	$	250.0	$	1,985.0
Interest on long-term debt (2)		909.3		28.8		291.2		227.9		361.4
Capital commitments (3)		26.9		26.9		-		-		-
Total	$	4,199.7	$	55.7	$	1,319.7	$	477.9	$	2,346.4

(1)

Includes our senior unsecured notes, having maturity dates from 2012 to 2027, and $703.5 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. The revolving credit facility and Subordinated Loans are extendable by us on the same terms for an additional 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 0.52% weighted-average interest rate on amounts outstanding under our revolving credit facility as of September 30, 2010, $0.9 million and $5.5 million would be due under the credit facility in less than one year and 1-3 years.

(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, 2010. The amounts shown do not reflect commitments we have made after September 30, 2010. For information on these projects, see Growth Capital Expenditures.

As shown in the table above, approximately $1.3 billion of our long-term debt, including amounts borrowed under our revolving credit facility, is set to mature in the next five years. We expect to refinance the debt through the issuance and sale of new debt.

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 2010, we have funded a total of $9.2 million to the Texas Gas pension plan and do not expect to fund additional amounts in 2010.

Off-Balance Sheet Arrangements

At September 30, 2010, 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 condensed consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities in our financial statements. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with third parties and other methods we consider reasonable. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the periods in which the facts that give rise to the revisions become known.

During 2010, 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, 2009.

Forward-Looking Statements

Investors are cautioned that certain statements contained in this Report, as well as some statements in periodic press releases and some oral statements made by our officials and our subsidiaries during presentations about us, are “forward-looking.” Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will likely result,” and similar expressions. In addition, any statement made by our management concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions by our partnership or its subsidiaries, are also forward-looking statements.

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

·	the impact of new pipelines or new gas supply sources on competition and basis spreads on our pipeline systems, which may impact our ability to maintain or replace expiring gas transportation and storage contracts and to sell short-term capacity on our pipelines;

·	the impact of laws and regulations, including changes to laws and regulations, such as the proposed greenhouse gas legislation and the re-authorization by Congress of PHMSA, on our business, including our costs, liabilities and revenues;

·	the timing, cost, scope and financial performance of our recent and future growth projects, including our ability to continue to operate our East Texas Pipeline, Southeast Expansion, Gulf Crossing Pipeline and operate our Fayetteville Lateral at higher than normal operating pressures;

·	volatility or disruptions in the capital or financial markets;

·	the impact of FERC 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 cost of insuring our assets may increase dramatically;

·	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; and

·	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.

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.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The information contained herein updates, and should be read in conjunction with, information set forth in Part II, Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2009. Since December 31, 2009, there have been no material changes to our interest rate or commodity risk exposures or the management of those exposures. The following is provided to update information regarding our market and credit risks.

Market risk:

Our primary exposure to market risk occurs at the time our existing transportation and storage contracts expire and are subject to renewal or marketing. We actively monitor future expiration dates associated with our contract portfolio.

We compete with numerous interstate and intrastate pipelines, including several pipeline projects which have recently been placed in service or are in the process of being developed. Additionally, significant new sources of natural gas have recently been identified throughout the United States which have created changes in pricing dynamics between supply basins, pooling points and market areas. As a result of the increase in overall pipeline capacity and the new sources of supply, the price differentials on our pipeline systems have narrowed.

Given current market conditions, marketing our available capacity and renewing expiring contracts have become more difficult. Our ability to renew some of our expiring contracts at favorable rates, and our revenues from interruptible and short-term firm transportation services, have been negatively impacted by these trends. Capacity that we have available on a short-term basis will decrease as long-term capacity commitments on our recently completed pipeline expansion projects increase through 2011. However, some of our capacity will continue to be available for sale on a short-term firm or interruptible basis and each year a portion of our existing contracts expire. The revenues we will be able to earn from that available capacity and from renewals of expiring contracts will be heavily dependent upon basis spreads. It is not possible to accurately predict future basis spreads.

Credit risk:

Our credit exposure generally relates to receivables for services provided, as well as volumes owed by customers for imbalances or gas lent by us to them, generally under PAL and no-notice services. Natural gas price volatility can materially increase credit risk related to gas loaned to customers. If any significant customer of ours should have credit or financial problems resulting in a delay or failure to repay the gas they owe to us, this could have a material adverse effect on our business, financial condition, results of operations or cash flows.

As of September 30, 2010, the amount of gas loaned out by our subsidiaries or owed to our subsidiaries due to gas imbalances was approximately 6.8 trillion British thermal units (TBtu). Assuming an average market price during September 2010 of $3.82 per million British thermal units (MMBtu), the market value of that gas was approximately $26.0 million. As of December 31, 2009, the amount of gas loaned out by our subsidiaries or owed to our subsidiaries due to gas imbalances was approximately 14.9 TBtu. Assuming an average market price during December 2009 of $5.36 per MMBtu, the market value of this gas at December 31, 2009, would have been approximately $79.9 million.

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, 2010.

Changes in Internal Control over Financial Reporting

During the third quarter 2010, we implemented a new enterprise resource planning system, including a replacement of the previous general ledger, accounts payable, accounts receivable, project costing, procurement, and other financial systems. In connection with the implementation, internal controls over financial reporting were updated to accommodate modifications to business processes and to leverage enhanced automated controls provided by the new system. There are inherent risks associated with implementing software changes and management believes its controls in the affected areas, as modified, continue to be designed appropriately and operate effectively. There have been no other 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, 2010, that have materially affected or that are reasonably likely to materially affect our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

For a discussion of certain of our current legal proceedings, please read Note 5 of the Notes to Condensed Consolidated Financial Statements in Item 1 of this Report.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer purchases of equity securities

Period		Total number of units purchased				Average price paid per unit				Total number of units purchased as part of publicly announced plans or programs				Maximum number of units that may yet be purchased under the plans or programs
August 1, 2010 to August 31, 2010 (1)			292			$	30.83				-				-

(1)	Our general partner purchased our common units and subsequently granted them to one of our outside directors as part of his annual director compensation.

Item 6. Exhibits

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).
*31.1		Certification of Rolf A. Gafvert, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a).
*31.2		Certification of Jamie L. Buskill, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a).
*32.1		Certification of Rolf A. Gafvert, Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2		Certification of Jamie L. Buskill, Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*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

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	Boardwalk Pipeline Partners, LP

		By: Boardwalk GP, LP
		its general partner

		By: Boardwalk GP, LLC
		its general partner

Dated: October 26, 2010			By:	/s/ Jamie L. Buskill
				Jamie L. Buskill
				Senior Vice President, Chief Financial Officer and Treasurer