Edgar Filing: Boardwalk Pipeline Partners, LP

form10-q_march2008.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 March 31, 2008

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 is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one)

Large accelerated filer x Accelerated filer o Non-accelerated filer o Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x

As of April 23, 2008, the registrant had 90,656,122 common units outstanding and 33,093,878 subordinated units outstanding.

TABLE OF CONTENTS

FORM 10-Q

March 31, 2008

BOARDWALK PIPELINE PARTNERS, LP

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

Condensed Consolidated Balance Sheets………………………………………………………………………………………...3

Condensed Consolidated Statements of Income…………………………………………………………………………………5

Condensed Consolidated Statements of Cash Flows……………………………………………………………………………6

Condensed Consolidated Statements of Changes in Partners’ Capital………………………………………………………7

Condensed Consolidated Statements of Comprehensive Income……………………………………………………………...8

Notes to Condensed Consolidated Financial Statements………………………………………………………………………9

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations……………............20

Item 3. Quantitative and Qualitative Disclosures About Market Risk……………………………………………............28

Item 4. Controls and Procedures………………………………………………………………………………….........…..30

PART II - OTHER INFORMATION

Item 1. Legal Proceedings……………………………………………………………………………………………..........31

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds……………………………………………….........31

Item 6. Exhibits…………………………………………………………………………………………………....…............32

Signatures……………………………………………………………………………………………………………......….33

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Millions)

(Unaudited)

	March 31,		December 31,
ASSETS	2008		2007
Current Assets:
Cash and cash equivalents	$	36.4	$	317.3
Receivables:
Trade, net		60.4		60.7
Other		11.9		12.7
Gas Receivables:
Transportation and exchange		23.6		12.5
Storage		-		1.3
Inventories		18.9		16.6
Costs recoverable from customers		7.2		6.3
Gas stored underground		22.9		16.3
Prepaid expenses and other current assets		11.8		11.9
Total current assets		193.1		455.6

Property, Plant and Equipment:
Natural gas transmission plant		2,780.6		2,392.5
Other natural gas plant		227.3		224.0
		3,007.9		2,616.5
Less—accumulated depreciation and amortization		288.8		262.5
		2,719.1		2,354.0
Construction work in progress		1,079.6		951.4
Property, plant and equipment, net		3,798.7		3,305.4

Other Assets:
Goodwill		163.5		163.5
Gas stored underground		152.3		172.4
Costs recoverable from customers		15.8		15.9
Other		46.3		44.5
Total other assets		377.9		396.3

Total Assets	$	4,369.7	$	4,157.3

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

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Millions)

(Unaudited)

	March 31,			December 31,
LIABILITIES AND PARTNERS’ CAPITAL	2008			2007
Current Liabilities:
Payables:
Trade	$	149.8		$	190.6
Affiliates		1.2			1.3
Other		4.6			5.1
Gas Payables:
Transportation and exchange		9.8			17.8
Storage		19.3			35.3
Accrued taxes, other		44.9			20.2
Accrued interest		23.1			30.8
Accrued payroll and employee benefits		14.3			22.3
Construction retainage		18.1			32.2
Deferred income		3.6			7.2
Other current liabilities		35.6			26.5
Total current liabilities		324.3			389.3

Long –Term Debt		2,095.8			1,847.9

Other Liabilities and Deferred Credits:
Pension and postretirement benefits		18.0			17.2
Asset retirement obligation		16.3			16.1
Provision for other asset retirement		42.9			42.4
Other		66.9			41.4
Total other liabilities and deferred credits		144.1			117.1

Commitments and Contingencies

Partners’ Capital:
Common units – 90.7 million units issued and outstanding as of March 31, 2008 and December 31, 2007		1,494.3			1,473.9
Subordinated units – 33.1 million units issued and outstanding as of March 31, 2008 and December 31, 2007		299.2			291.7
General partner		33.8			33.2
Accumulated other comprehensive (loss) income		(21.8	)		4.2
Total partners’ capital		1,805.5			1,803.0
Total Liabilities and Partners’ Capital	$	4,369.7		$	4,157.3

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

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Millions, except earnings per unit)

(Unaudited)

	For the Three Months Ended March 31,
	2008			2007
Operating Revenues:
Gas transportation	$	176.5		$	152.9
Parking and lending		5.1			18.4
Gas storage		10.7			7.7
Other		5.0			9.1
Total operating revenues		197.3			188.1

Operating Costs and Expenses:
Operation and maintenance		40.8			39.5
Administrative and general		25.2			25.8
Depreciation and amortization		27.4			19.9
Contract settlement gain		(11.2	)		-
Asset impairment		1.4			-
Net loss on disposal of operating assets and related contracts		0.2			2.6
Taxes other than income taxes		12.0			8.0
Total operating costs and expenses		95.8			95.8

Operating income		101.5			92.3

Other Deductions (Income):
Interest expense		19.0			16.8
Interest income		(0.9	)		(4.6	)
Interest income from affiliates, net		(0.1	)		-
Miscellaneous other income, net		(4.9	)		(0.3	)
Total other deductions		13.1			11.9

Income before income taxes		88.4			80.4

Income taxes		0.3			0.2

Net income	$	88.1		$	80.2

Calculation of limited partners’ interest in Net income:
Net income	$	88.1	$	80.2
Less general partner’s interest in Net income		3.3		1.8
Limited partners’ interest in Net income	$	84.8	$	78.4
Basic and diluted net income per limited partner unit:
Common and subordinated units	$	0.60	$	0.61
Cash distribution to common and subordinated units	$	0.46	$	0.415
Weighted-average number of limited partner units outstanding:
Common units		90.7		76.0
Subordinated units		33.1		33.1

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 Three Months Ended March 31,
	2008			2007
OPERATING ACTIVITIES:
Net income	$	88.1		$	80.2
Adjustments to reconcile to cash provided by operations:
Depreciation and amortization		27.4			19.9
Amortization of deferred costs		2.4			1.8
Amortization of acquired executory contracts		(0.1	)		(0.8	)
Asset impairment		1.4			-
Loss on disposal of operating assets and related contracts		0.2			2.6
Changes in operating assets and liabilities:
Trade and other receivables		1.1			3.5
Gas receivables and storage assets		3.6			19.2
Costs recoverable from customers		(0.8	)		3.6
Other assets		(10.6	)		0.6
Trade and other payables		(9.2	)		(14.5	)
Gas payables		0.4			(24.2	)
Accrued liabilities		(12.5	)		(4.1	)
Other liabilities		(2.1	)		(10.5	)
Net cash provided by operating activities		89.3			77.3
INVESTING ACTIVITIES:
Capital expenditures		(542.5	)		(162.1	)
Proceeds from sale of operating assets		-			0.4
Advances to affiliates, net		(0.3	)		0.7
Net cash used in investing activities		(542.8	)		(161.0	)
FINANCING ACTIVITIES:
Proceeds from long-term debt, net of issuance costs		247.2			-
Proceeds from borrowings on revolving credit agreement		153.0			-
Repayment of borrowings on revolving credit agreement		(153.0	)		-
Treasury rate lock settlement		(15.0	)		-
Distributions		(59.6	)		(46.1	)
Proceeds from sale of common units, net of related transaction costs		-			287.9
Capital contribution from parent and general partner		-			6.0
Net cash provided by financing activities		172.6			247.8
(Decrease) increase in cash and cash equivalents		(280.9	)		164.1
Cash and cash equivalents at beginning of period		317.3			399.1
Cash and cash equivalents at end of period	$	36.4		$	563.2

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			Subordinated Units			General Partner			Accumulated Other Comp Income (Loss)			Total Partners’ Capital
Balance January 1, 2007	$	941.8		$	285.5		$	22.1		$	23.1		$	1,272.5
Add (deduct):
Net income		54.6			23.8			1.8			-			80.2
Distributions paid		(31.2	)		(13.7	)		(1.2	)		-			(46.1	)
Sale of common units, net of related transaction costs (8.0 million common units)		287.9			-			-			-			287.9
Capital contribution from general partner		-			-			6.0			-			6.0
Other comprehensive loss		-			-			-			(9.1	)		(9.1	)
Balance March 31, 2007	$	1,253.1		$	295.6		$	28.7		$	14.0		$	1,591.4

Balance January 1, 2008	$	1,473.9		$	291.7		$	33.2		$	4.2		$	1,803.0
Add (deduct):
Net income		62.1			22.7			3.3			-			88.1
Distributions paid		(41.7	)		(15.2	)		(2.7	)		-			(59.6	)
Other comprehensive loss		-			-			-			(26.0	)		(26.0	)
Balance March 31, 2008	$	1,494.3		$	299.2		$	33.8		$	(21.8	)	$	1,805.5

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

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Millions)

(Unaudited)

	For the Three Months Ended
	March 31,
	2008			2007
Net income	$	88.1		$	80.2
Other comprehensive (loss) income:
Loss on cash flow hedges		(24.4	)		(7.4	)
Reclassification adjustment transferred to Net income from cash flow hedges		0.6			(3.1	)
Pension and other postretirement benefits costs		(2.2	)		1.4
Total comprehensive income	$	62.1		$	71.1

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 Boardwalk Pipelines, LP (Boardwalk Pipelines) and its subsidiaries, Gulf South Pipeline Company, LP (Gulf South) and Texas Gas Transmission, LLC (Texas Gas) (together, the operating subsidiaries). Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned subsidiary of Loews Corporation (Loews), owns 53.3 million common units and 33.1 million subordinated units constituting approximately 68% of the Partnership’s capital. Boardwalk GP, LP (Boardwalk GP), an indirect wholly-owned subsidiary of BPHC, is the Partnership’s general partner and holds a 2% general partner interest and all of the incentive distribution rights, further described in Note 7. The Partnership’s common units are traded under the symbol “BWP” on the New York Stock Exchange.

The accompanying unaudited condensed consolidated financial statements of the Partnership were prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations. In the opinion of management, the accompanying condensed consolidated financial statements reflect all adjustments (consisting of only normal recurring accruals) necessary to present fairly the financial position as of March 31, 2008 and December 31, 2007, and the results of operations, changes in cash flow, changes in partners’ equity and comprehensive income for the three months ended March 31, 2008 and 2007. Reference is made to the Notes to Consolidated Financial Statements in the 2007 Annual Report on Form 10-K, which should be read in conjunction with these unaudited condensed consolidated financial statements. The accounting policies described in Note 2 to the Consolidated Financial Statements included in such Annual Report on Form 10-K are the same used in preparing the accompanying unaudited condensed consolidated financial statements.

Net income for interim periods may not necessarily be indicative of results for the full year. All intercompany items have been eliminated in consolidation.

Note 2: Gas in Storage and Gas Receivables/Payables

Gulf South and Texas Gas store gas on behalf of others. Due to the method of storage accounting elected by Gulf South, the Partnership does not reflect volumes held by Gulf South on behalf of others on its Condensed Consolidated Balance Sheets. As of March 31, 2008 and December 31, 2007, Gulf South held 32.2 trillion British thermal units (TBtu) and 52.0 TBtu of gas owned by shippers. Gulf South loaned 0.3 and 0.2 TBtu of gas to shippers as of March 31, 2008 and December 31, 2007. Consistent with the method of storage accounting elected by Texas Gas and the risk-of-loss provisions included in its tariff, Texas Gas reflects gas held on behalf of others in Gas stored underground and records an equal offsetting payable. The amount reflected in Gas Payables on the Condensed Consolidated Balance Sheets is valued at a historical cost of gas of $19.3 million and $35.3 million at March 31, 2008 and December 31, 2007.

Note 3: Derivative Financial Instruments

Subsidiaries of the Partnership use futures, swaps, and option contracts (collectively, derivatives) to hedge exposure to various risks, including natural gas commodity price risk and interest rate risk. These hedge contracts are reported at fair value in accordance with Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended.

Certain volumes of gas stored underground are available for sale and subject to commodity price risk. At March 31, 2008 and December 31, 2007, approximately $22.9 million and $16.3 million of gas stored underground, which the Partnership owns and carries as current Gas stored underground, was exposed to commodity price risk. The Partnership utilizes derivatives to hedge certain exposures to market price fluctuations on the anticipated operational sales of gas.

As a result of the approval of Phase III of the Western Kentucky storage expansion project in the first quarter 2008, approximately 5.1 billion cubic feet (Bcf) of gas stored underground with a book value of $11.8 million became available for sale. The Partnership entered into derivatives, which were designated as cash flow hedges, to hedge the price exposure related to the expected sale of this gas.

In the second quarter 2007, the Partnership entered into natural gas price swaps to hedge exposure to prices associated with the purchase of 2.1 Bcf of natural gas to be used for line pack for the Gulf Crossing and Southeast Expansion projects, approximately 1.3 Bcf of which remained outstanding at March 31, 2008. The derivatives were not designated as hedges and were marked to fair value resulting in a gain of $3.1 million in Miscellaneous other income, net on the Condensed Consolidated Statements of Income for the three months ended March 31, 2008.

The Partnership recognized a loss of $2.1 million in the first quarter 2007 on derivatives and related contracts not designated as hedges related to gas stored underground that became available for sale as a result of Phase II of the Western Kentucky project.

In August 2007, the Partnership entered into a Treasury rate lock for a notional amount of $150.0 million of principal to hedge the risk attributable to changes in the risk-free component of forward 10-year interest rates through February 1, 2008. The Treasury rate lock was designated as a cash flow hedge in accordance with SFAS No. 133. On February 1, 2008, the Partnership settled the rate lock and paid the counterparty approximately $15.0 million. The loss will be amortized to interest expense over 10 years. As of December 31, 2007, the Partnership recorded a payable of $8.4 million and a corresponding amount in Accumulated other comprehensive income for the fair value of the rate lock.

With the exception of the derivatives related to certain storage gas volumes related to Phase II of the Western Kentucky storage expansion project and line pack gas purchases referred to above, the derivatives related to the sale or purchase of natural gas, cash for fuel reimbursement and debt generally qualify for cash flow hedge accounting under SFAS No. 133 and are designated as such. The effective component of related unrealized gains and losses resulting from changes in fair values of the derivatives contracts designated as cash flow hedges are deferred as a component of Accumulated other comprehensive income. The deferred gains and losses are recognized in the Condensed Consolidated Statements of Income when the anticipated transactions affect earnings. Generally, for gas sales and cash for fuel reimbursement, any gains and losses on the related derivatives would be recognized in Operating Revenues. For the sale of gas related to Phase II of the Western Kentucky storage expansion project, any gains and losses on the related derivatives were recognized in Net gain on disposal of operating assets and related contracts. Any gains and losses on the derivatives related to the line pack gas purchases would be recognized in Miscellaneous other income, net.

The fair values of derivatives existing as of March 31, 2008 and December 31, 2007, were included in the following captions in the Condensed Consolidated Balance Sheets (in millions):

	March 31, 2008			December 31, 2007
Prepaid expenses and other current assets	$	2.8		$	2.2
Other current liabilities		16.5			9.4
Other non-current liabilities		0.2			-
Accumulated other comprehensive loss		(32.7	)		(8.9	)

The changes in fair values of the derivatives designated as cash flow hedges are expected to, and do, have a high correlation to changes in value of the anticipated transactions. Each reporting period the Partnership measures the effectiveness of the cash flow hedge contracts. To the extent the changes in the fair values of the hedge contracts do not effectively offset the changes in the estimated cash flows of the anticipated transactions, the ineffective portion of the hedge contracts is currently recognized in earnings. If the anticipated transactions are no longer deemed probable to occur, hedge accounting would be terminated and if the transactions are deemed probable of not occurring changes in the fair values of the associated derivative financial instruments would be recognized currently in earnings. Ineffectiveness decreased Net income by less than $0.1 million for the three months ended March 31, 2008 and increased Net income by $0.4 million for the three months ended March 31, 2007. The Partnership did not discontinue any cash flow hedges during the three month periods ended March 31, 2008 and 2007.

Note 4: Fair Value

SFAS No. 157, Fair Value Measurements

In 2008, the Partnership implemented the provisions of SFAS No. 157, except for the provisions related to non-financial assets and liabilities measured at fair value on a non-recurring basis, which provisions are expected to be applied beginning in 2009. Under SFAS No. 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction in the principal market in which the reporting entity transacts based on the assumptions market participants would use when pricing the asset or liability. The standard establishes a fair value hierarchy that prioritizes the information used to develop those assumptions giving the priority, from highest to lowest, to quoted prices in active markets for identical assets and liabilities (Level 1); observable inputs not included in Level 1, for example, quoted prices for similar assets and liabilities (Level 2); and unobservable data (Level 3), for example, a reporting entity’s own internal data based on the best information available in the circumstances.

The Partnership identified its derivatives as items governed by the provisions of SFAS No. 157. The derivatives in existence at March 31, 2008 were natural gas price swaps and options, which were recorded at fair value at March 31, 2008 based on New York Mercantile Exchange (NYMEX) quotes for natural gas futures and options. The NYMEX quotes were deemed to be observable inputs for similar assets and liabilities and rendered Level 2 inputs for purposes of disclosure. The application of SFAS No. 157 had no effect on the Partnership’s financial statements.

The following table shows information regarding the Partnership’s derivatives at March 31, 2008 (in millions):

	Total at March 31, 2008		Quoted Prices in Active Markets for Identical Assets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3
Assets:
Prepaid expenses and other current assets	$	2.8		-	$	2.8		-
Total assets	$	2.8		-	$	2.8		-
Liabilities:
Other current liabilities	$	16.5		-	$	16.5		-
Other non-current liabilities		0.2		-		0.2		-
Total liabilities	$	16.7		-	$	16.7		-

SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities

In 2008, the Partnership had the option to apply the provisions of SFAS No. 159, which allows companies to elect to measure and record certain financial assets and liabilities at fair value that would not otherwise be recorded at fair value, such as long term debt or notes receivable. Unrealized gains and losses on items for which the fair value option was chosen would be reported in earnings. The Partnership reviewed its financial assets and liabilities in existence at January 1, 2008 as well as any financial assets and liabilities entered into during the three month period ended March 31, 2008, and did not elect the fair value option for any applicable items. Consequently, the application of SFAS No. 159 had no effect on the Partnership’s financial statements.

Note 5: Income Taxes

The Partnership is not a taxable entity for federal income tax purposes. As such, it does not directly pay federal income tax. The Partnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the Condensed Consolidated Statements of Income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of the Partnership’s net assets for financial and income tax purposes cannot be readily determined as the Partnership does not have access to the information about each partner’s tax attributes. The subsidiaries of the Partnership directly incur some income-based state taxes which are presented in Income taxes on the Condensed Consolidated Statements of Income.

Note 6: Commitments and Contingencies

A. Calpine Energy Services (Calpine) Settlement

In December 2007, Gulf South and Calpine filed a stipulation and agreement in Calpine’s Chapter 11 Bankruptcy proceedings to settle, for approximately $16.5 million, Gulf South’s claim against Calpine related to Calpine’s non-payment under a transportation agreement. The claim, which was approved in January 2008, was to be paid in the form of Calpine stock, along with other general creditors having claims in the Bankruptcy proceeding. In the fourth quarter 2007, the Partnership recognized $4.1 million of revenues related to previously reserved amounts invoiced to Calpine for transportation services in 2007 and 2006. In January 2008, the Partnership sold the entire claim to a third party and received a cash payment of approximately $15.3 million. The transfer of the claim was deemed a sale and any recourse related to the sale expired in January 2008. As a result, in the first quarter 2008, the Partnership recorded a net gain of $11.2 million related to the realization of the unrecognized portion of the claim which was reported as Contract settlement gain on the Condensed Consolidated Statements of Income. The matter is considered settled and the Partnership does not expect to receive additional amounts related to the claim.

B. Legal Proceedings

Napoleonville Salt Dome Matter

In December 2003, natural gas leaks were observed near two natural gas storage caverns that were being leased and operated by Gulf South for natural gas storage in Napoleonville, Louisiana. Gulf South commenced remediation efforts immediately and ceased using those storage caverns. Two class action lawsuits were filed relating to this incident and were converted to individual actions. Several additional individual actions have been filed against Gulf South and other defendants by local residents and businesses. In addition, the lessor of the property has filed a claim against Gulf South in an action filed against the lessor by one of Gulf South's insurers. Gulf South continues to vigorously defend each of these actions, however it is not possible to predict the outcome of this litigation as the cases remain in discovery. Litigation is subject to many uncertainties, and it is possible these actions could be decided unfavorably. Gulf South has settled many of the cases filed against it and may enter into discussions in an attempt to settle other cases if Gulf South believes it is appropriate to do so.

Other Legal Matters

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

C. Regulatory and Rate Matters

Expansion Capital Projects

The Partnership is engaged in several pipeline expansion projects as described below:

East Texas to Mississippi Expansion. The pipeline and two of the three compression facilities are now in service for the East Texas to Mississippi expansion, which project consists of approximately 242 miles of 42-inch pipeline from DeSoto Parish in western Louisiana to near Harrisville, Mississippi and approximately 110,000 horsepower of new compression having approximately 1.7 Bcf of new peak-day transmission capacity. The Partnership is serving the full contract demand which consists of customers that have contracted at fixed rates for 1.4 Bcf per day of firm transportation capacity on a long-term basis (with a weighted average term of approximately 6.8 years), which represents substantially all of the normal operating capacity. The Partnership is in the process of commissioning the remaining compression facility associated with this project, which is expected to be completed during the second quarter 2008. Through March 31, 2008, the Partnership has spent $916.1 million related to this project.

Southeast Expansion. In September 2007, the Federal Energy Regulatory Commission (FERC) granted the Partnership the authority to construct, own and operate a pipeline expansion originating near Harrisville, Mississippi and extending to an interconnect with Transcontinental Pipe Line Company (Transco) in Choctaw County, Alabama (Transco 85). This expansion will initially consist of approximately 112 miles of 42-inch pipeline having approximately 1.2 Bcf of peak-day transmission capacity. To accommodate volumes expected to come from the Gulf Crossing leased capacity discussed below, this project will be expanded to up to 2.2 Bcf of peak-day transmission capacity. In addition, the FERC approved the Partnership’s 260 million cubic feet (MMcf) per day operating lease with Destin Pipeline Company which will provide the Partnership enhanced access to markets in Florida. Customers have contracted at fixed rates for 660 MMcf per day of firm transportation capacity on a long-term basis (with a weighted-average term of 9.2 years), in addition to the capacity leased to Gulf Crossing discussed below. Construction has commenced and the Partnership expects the initial 1.2 Bcf of capacity to be in service during the second quarter 2008. The Partnership expects the remaining capacity to be in service during the first quarter 2009. Through March 31, 2008, the Partnership has spent $394.8 million related to this project.

Gulf Crossing Project. The Partnership is pursuing the construction of a new interstate pipeline that will begin near Sherman, Texas and proceed to the Perryville, Louisiana area. The project will be owned by Gulf Crossing Pipeline Company LLC, the Partnership’s newly formed interstate pipeline subsidiary, and will consist of approximately 357 miles of 42-inch pipeline having up to approximately 1.7 Bcf of peak-day transmission capacity. Additionally, Gulf Crossing has entered into, subject to regulatory approval: (i) an operating lease for up to 1.4 Bcf per day of capacity on the Partnership’s Gulf South pipeline system (including capacity on the Southeast Expansion and capacity on a portion of the East Texas to Mississippi Expansion) to make deliveries to an interconnect with Transco 85; and (ii) an operating lease with Enogex, a third-party intrastate pipeline, which will bring certain gas supplies to the Partnership’s system. Customers have contracted at fixed rates for 1.1 Bcf per day of long-term firm transportation capacity (with a weighted average term of approximately 9.5 years). The Final Environmental Impact Statement was received in the first quarter 2008, and the Partnership is awaiting the certificate to commence construction of the project. The Partnership expects this project to be in service during the first quarter 2009. Through March 31, 2008, the Partnership has spent $256.2 million related to this project.

Fayetteville and Greenville Laterals. The Partnership is pursuing the construction of two laterals connected to its Texas Gas pipeline system to transport gas from the Fayetteville Shale area in Arkansas to markets directly and indirectly served by the Partnership’s existing interstate pipelines. The Fayetteville Lateral will originate in Conway County, Arkansas and proceed southeast through the Bald Knob, Arkansas, area to an interconnect with the Texas Gas mainline in Coahoma County, Mississippi and consist of approximately 165 miles of 36-inch pipeline. The Greenville Lateral will originate at the Texas Gas mainline near Greenville, Mississippi and proceed east to the Kosciusko, Mississippi, area consisting of approximately 95 miles of 36-inch pipeline. The Greenville Lateral will allow customers to access additional markets, primarily in the Midwest, Northeast and Southeast. This project had an initial design capacity of 0.8 Bcf of peak-day transmission capacity which did not include compression facilities. The Partnership recently executed contracts for additional capacity that would require it to add compression to the project to increase the peak-day transmission capacity from 0.8 Bcf to approximately 1.2 Bcf for the Fayetteville Lateral and from approximately 0.8 to approximately 1.0 Bcf for the Greenville Lateral.

Including the new capacity, the contracts on the Fayetteville Lateral provide, after phase-in periods through 2012, for 975 MMcf per day of initial capacity, with options for additional capacity that, if exercised, could add 225 MMcf per day of capacity. On the Greenville Lateral, contracts for 818 MMcf per day of initial capacity are phased in through 2012 with options for additional capacity that, if exercised, could add 172 MMcf per day of capacity. The contracts associated with this project are at fixed rates with a weighted average term of 9.9 years. The Final Environmental Impact Statement was received in the first quarter 2008, and the Partnership is awaiting the certificate to commence construction of the project. The Partnership expects the first 60 miles of the Fayetteville Lateral to be in service during the third quarter 2008 and the remainder of the pipeline related to the Fayetteville and Greenville Laterals to be in service during the first quarter 2009. The Partnership expects to make additional filings with FERC regarding the additional compression required to increase the peak-day transmission capacity and expects the additional capacity to be in service during 2010. Through March 31, 2008, the Partnership has spent $167.8 million related to this project.

In addition to the pipeline expansion projects described above, the Partnership is currently engaged in the following storage expansion project:

Western Kentucky Storage Expansion Phase III. In February 2008, the FERC granted the Partnership authority to develop up to 8.3 Bcf of new working gas capacity and granted market-based rate authority for this new capacity. This expansion is supported by 10-year precedent agreements for 5.1 Bcf of storage capacity. The cost of this project will be dependent on the ultimate size of the expansion. The Partnership expects 5.4 Bcf of storage capacity to be in service during 2008. Through March 31, 2008, the Partnership has spent $3.7 million related to this project.

D. Environmental and Safety Matters

The operating subsidiaries are subject to federal, state, and local environmental laws and regulations in connection with the operation and remediation of various operating sites. The Partnership accrues for environmental expenses resulting from existing conditions that relate to past operations when the costs are probable and can be reasonably estimated. In addition to federal and state mandated remediation requirements, the Partnership often enters into voluntary remediation programs with the agencies.

As of March 31, 2008 and December 31, 2007, the Partnership had an accrued liability of approximately $16.7 million and $17.0 million related to assessment and/or remediation costs associated with the historical use of polychlorinated biphenyls, petroleum hydrocarbons and mercury, enhancement of groundwater protection measures and other costs. The expenditures are expected to occur over approximately the next ten years. The accrual represents management’s estimate of the undiscounted future obligations based on evaluations and discussions with counsel and operating personnel and the current facts and circumstances related to these matters. As of March 31, 2008 and December 31, 2007, approximately $2.7 million was recorded in Other current liabilities and approximately $14.0 million and $14.3 million were recorded in Other Liabilities and Deferred Credits.

In March 2008, the Environmental Protection Agency (EPA) adopted regulations lowering the 8-hour ozone standard relevant to non-attainment areas. Under the regulation new non-attainment areas will be identified which may require additional emission controls for compliance at as many as 14 facilities operated by the Partnership. The anticipated effective date for compliance with the proposed standard in its current state is between 2013 and 2016.

The Partnership considers environmental assessment, remediation costs and costs associated with compliance with environmental standards to be recoverable through base rates, as they are prudent costs incurred in the ordinary course of business and, therefore, no regulatory asset has been recorded to defer these costs. The actual costs incurred will depend on the actual amount and extent of contamination discovered, the final cleanup standards mandated by the EPA or other governmental authorities and other factors.

E. Commitments

The Partnership’s future capital commitments as of March 31, 2008, for contracts already authorized are expected to approximate the following amounts (in millions):

Less than 1 year	$	573.7
1-3 years		24.1
4-5 years		-
More than 5 years		-
Total	$	597.8

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

Note 7: Net Income per Limited Partner Unit and Cash Distributions

The Partnership calculates net income per limited partner unit in accordance with Emerging Issues Task Force (EITF) Issue No. 03-6, Participating Securities and the Two-Class Method under FASB Statement No. 128. In Issue 3 of EITF No. 03-6, the EITF reached a consensus that undistributed earnings for a period should be allocated to a participating security based on the contractual participation rights of the security to share in those earnings as if all of the earnings for the period had been distributed. The Partnership's general partner holds contractual participation rights which are incentive distribution rights (IDRs) in accordance with the partnership agreement as follows:


	Total Quarterly Distribution	Marginal Percentage Interest in Distributions
	Target Amount	Common and Subordinated Unitholders	General Partner
Minimum Quarterly Distribution	$0.3500	98%	2%
First Target Distribution	up to $0.4025	98%	2%
Second Target Distribution	above $0.4025 up to $0.4375	85%	15%
Third Target Distribution	above $0.4375 up to $0.5250	75%	25%
Thereafter	above $0.5250	50%	50%

The amounts reported for net income per limited partner unit on the Condensed Consolidated Statements of Income for the three month periods ended March 31, 2008 and 2007, were adjusted to take into account an assumed allocation to the general partner's IDRs. Payments made on account of the IDRs are determined in relation to actual declared distributions. A reconciliation of the limited partners' interest in net income and net income available to limited partners used in computing net income per limited partner unit follows (in millions, except per unit data):

	For the Three Months Ended March 31,
	2008		2007
Limited partners' interest in net income	$	84.8	$	78.4
Less assumed allocation to IDRs		11.0		12.0
Net income available to limited partners		73.8		66.4
Less assumed allocation to subordinated units		19.7		20.2
Net income available to common units	$	54.1	$	46.2
Weighted average common units		90.7		76.0
Weighted average subordinated units		33.1		33.1
Net income per limited partner unit – common and subordinated units	$	0.60	$	0.61

In the three month periods ended March 31, 2008 and 2007, the Partnership declared quarterly distributions per unit to unitholders of record, including common and subordinated units and the 2% general partner interest and IDRs held by its general partner as follows (in millions, except distribution per unit):

Payable Date	Distribution per Unit	Amount Paid to Common and Subordinated Unitholders	Amount Paid to General Partner (Including IDRs)
February 25, 2008	$ 0.460	$ 56.9	$ 2.7
February 27, 2007	0.415	44.9	1.2

Note 8: Financing

Senior Unsecured Debt

On March 27, 2008, the Partnership received net proceeds of approximately $247.2 million after deducting initial purchaser discounts and offering expenses of $2.8 million from the sale of $250.0 million of 5.50% senior unsecured notes of Texas Gas due April 1, 2013. Interest on the notes will be payable on April 1 and October 1 of each year, beginning on October 1, 2008. The notes are redeemable, in whole or in part, at the option of Texas Gas at any time, at a redemption price equal to the greater of 100% of the principal amount of the notes to be redeemed or a “make whole” redemption price based on the remaining scheduled payments of principal and interest discounted to the date of redemption at a Treasury rate plus 50 basis points, plus accrued and unpaid interest, if any. Other customary covenants apply, including those concerning events of default.

As of March 31, 2008 and December 31, 2007, the weighted-average interest rate of the Partnership’s long-term debt was 5.88% and 5.82%.

Revolving Credit Facility

As of March 31, 2008 and December 31, 2007, no funds were drawn under the Partnership’s $1.0 billion revolving credit facility, however, at March 31, 2008, the Partnership had outstanding letters of credit under the facility of $95.9 million to support certain obligations associated with the pipeline expansion projects which reduced the available capacity under the facility by such amount. During the three month period ended March 31, 2008, the Partnership borrowed and repaid $153.0 million under the facility. The interest rates on the borrowings ranged from 2.76% to 3.35%. As of March 31, 2008, the Partnership and its subsidiaries were in compliance with all covenant requirements under the credit agreement.

Capitalized Interest and Allowance for Funds Used During Construction

During the three months ended March 31, 2008 and 2007, the Partnership capitalized interest of $8.6 million and $2.1 million. In accordance with SFAS No. 71, Accounting for the Effect of Certain Types of Regulation, the Partnership’s Texas Gas subsidiary capitalizes allowance for funds used during construction (AFUDC), comprised of debt and equity components. The Partnership capitalized $2.2 million and $0.4 million of AFUDC for the three months ended March 31, 2008 and 2007.

Offering of Common Units

In March 2007, the Partnership completed an equity offering of 8.0 million of its common units for which it received net proceeds of $293.9 million, after deducting underwriting discounts and offering expenses of $4.2 million and including approximately $6.0 million contributed by its general partner to maintain its 2% interest. The proceeds of the offering have been used to finance the Partnership’s expansion activities discussed in Note 6.

Note 9: Property, Plant and Equipment

In first quarter 2008, the Partnership placed in service the remaining pipeline assets associated with the East Texas to Mississippi Expansion project from Delhi, Louisiana to Harrisville, Mississippi and related compression at two facilities. As a result, approximately $382.2 million was transferred from construction work in progress to property, plant and equipment. The assets will generally be depreciated over a term of 35 years.

In the first quarter 2008, the Partnership completed a review of the non-contiguous offshore assets of its Gulf South subsidiary and provided notice to the other interest holders of its intent to discontinue any use of its portion of the available capacity of these assets. As a result, the Partnership reviewed the assets for recoverability in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, and recorded an impairment charge of approximately $1.4 million representing the net book value of the related assets.

Note 10: Credit Concentration

Natural gas price volatility has increased dramatically in recent years, which has materially increased credit risk related to gas loaned to customers. Gas loaned to customers refers to receivables for services provided, as well as volumes owed by customers for imbalances or gas lent by the Partnership to them, generally under parking and lending and no-notice service. As of March 31, 2008, the amount of gas loaned out by the Partnership’s subsidiaries was approximately 37.8 TBtu and the amount considered an imbalance was approximately 3.6 TBtu. Assuming an average market price during March 2008 of $9.32 per million British thermal units (MMBtu), the market value of gas loaned out and considered an imbalance at March 31, 2008, would have been approximately $385.2 million. If any significant customer of the Partnership should have credit or financial problems resulting in a delay or failure to repay the gas they owe to it, this could have a material adverse effect on the Partnership’s financial condition, results of operations and cash flows.

Note 11: Employee Benefits

Defined Benefit Plans

Texas Gas employees hired prior to November 1, 2006 are covered under a non-contributory, defined benefit pension plan. The Texas Gas Supplemental Retirement Plan provides pension benefits for the portion of an eligible employee’s pension benefit that becomes subject to compensation limitations under the Internal Revenue Code. Texas Gas provides postretirement medical benefits and life insurance to retired employees who were employed full time, hired prior to January 1, 1996, and have met certain other requirements. The Partnership uses a measurement date of December 31 for its benefits plans.

Components of net periodic benefit cost for both the retirement plans and postretirement benefits other than pensions (PBOP) for the three months ended March 31, 2008 and 2007 were the following (in millions):

	Retirement Plans						PBOP
	For the Three Months Ended						For the Three Months Ended
	March 31,						March 31,
	2008			2007			2008			2007
Service cost	$	0.9		$	0.9		$	0.2		$	0.2
Interest cost		1.6			1.7			0.8			0.9
Expected return on plan assets		(1.7	)		(1.8	)		(1.3	)		(1.2	)
Amortization of prior service credit		-			-			(1.9	)		(1.9	)
Amortization of unrecognized net loss		-			-			-			0.2
Settlement charge		-			3.1			-			-
Regulatory asset decrease		-			-			1.4			1.4
Net periodic pension expense	$	0.8		$	3.9		$	(0.8	)	$	(0.4	)

Defined Contribution Plans

Gulf South employees and Texas Gas employees hired on or after November 1, 2006 are provided retirement benefits under a defined contribution money purchase plan. The operating subsidiaries also provide 401(k) plan benefits to their employees. Costs related to the Partnership’s defined contribution plans were $1.5 million and $1.2 million for the three months ended March 31, 2008 and 2007.

Note 12: Related Parties

Loews provides a variety of corporate services to the Partnership and its subsidiaries under services agreements. Services provided by Loews include, among others, information technology, tax, risk management, internal audit and corporate development services. Loews charged $4.0 million and $4.2 million for the three months ended March 31, 2008 and 2007 to the Partnership based on the actual time spent by Loews personnel performing these services, plus related expenses.

Distributions paid related to common and subordinated units held by BPHC, 2% general partner interest and IDRs held by Boardwalk GP were $42.4 million and $37.0 million during the first quarter 2008 and 2007.

The Partnership pays franchise and certain other taxes on behalf of BPHC and records a note receivable from BPHC for the amounts paid, which is settled quarterly. The notes accrue interest at London Interbank Offered Rate plus one percent. For the three months ended March 31, 2008 and 2007, the Partnership paid $0.1 million and less than $0.1 million on behalf of BPHC. A note receivable of $1.9 million remained at March 31, 2008.

Note 13: Accumulated Other Comprehensive Income (Loss)

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

	As of			As of
	March 31, 2008			December 31, 2007
Loss on cash flow hedges	$	(32.7	)	$	(8.9	)
Deferred components of net periodic benefit cost		10.9			13.1
Total Accumulated other comprehensive (loss) income	$	(21.8	)	$	4.2

Note 14: Guarantee of Securities of Subsidiaries

The Partnership has no independent assets or operations other than its investment in its subsidiaries. The Partnership’s operating subsidiaries have issued securities which have all been fully and unconditionally guaranteed by the Partnership. The Partnership does have separate partners’ capital including publicly traded limited partner common units.

The Partnership’s subsidiaries have no significant restrictions on their ability to pay distributions or make loans to the Partnership and had no restricted assets at March 31, 2008.

Note 15: Recently Issued Accounting Pronouncements

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, which requires entities to provide enhanced disclosures about (a) how and why the entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect the entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008. The Partnership is evaluating the effect that SFAS No. 161 will have on its financial statements.

In March 2008 the FASB approved EITF Issue No. 07-4, Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships, which requires that master limited partnerships use the two-class method of allocating earnings to calculate earnings per unit. EITF Issue No. 07-4 is effective for fiscal years and interim periods beginning after December 15, 2008. The Partnership is evaluating the effect that EITF Issue No. 07-4 will have on its earnings per unit and financial statements.

Note 16: Subsequent Events

On April 24, 2008, the Partnership entered into a Class B Unit Purchase Agreement (the Purchase Agreement) to issue and sell approximately 22.9 million of the newly created class B units representing limited partner interests (class B units) to BPHC for $30 per class B unit, or an aggregate purchase price of $686 million. The Partnership’s general partner will also contribute $14 million to the Partnership to maintain its 2% general partner interest. The Purchase Agreement has been approved by the Board of Directors and the Conflicts Committee of the Partnership’s general partner. The Partnership expects to close this transaction on or about June 17, 2008 and intends to use the proceeds of approximately $700 million to fund a portion of the costs of its ongoing expansion projects.

Beginning with the distribution in respect of the quarter ending September 30, 2008, the class B units will share in quarterly distributions of available cash from operating surplus on a pari passu basis with the Partnership’s common units, until each common unit and class B unit has received a quarterly distribution of $0.30. The class B units will not participate in quarterly distributions above $0.30 per unit. The class B units will be convertible into common units by the holder on a one-for-one basis at any time after June 30, 2013.

The class B units will represent a separate class of the Partnership’s limited partner interests. The class B units will have the same voting rights as if they were outstanding common units and will be entitled to vote as a separate class on any matters that materially adversely affect the rights or preferences of the class B units in relation to other classes of partnership interests or as required by law. Pursuant to the Purchase Agreement, at the time of closing of the sale of the class B units, the Partnership will enter into a Registration Rights Agreement with BPHC covering the common units into which the class B units will be convertible.

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

The following discussion and analysis of financial condition and results of operations should be read in conjunction with our accompanying interim condensed consolidated financial statements and related notes, included elsewhere in this report and prepared in accordance with accounting principles generally accepted in the United States of America and our consolidated financial statements, related notes, Management's Discussion and Analysis of Financial Condition and Results of Operations and Risk Factors included in our Annual Report on Form 10-K for the year ended December 31, 2007.

We are a Delaware limited partnership formed in 2005 to own and operate the business conducted by Boardwalk Pipelines, LP (Boardwalk Pipelines) and its subsidiaries, Gulf South Pipeline Company, LP (Gulf South) and Texas Gas Transmission, LLC (Texas Gas) (together, operating subsidiaries). Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned subsidiary of Loews Corporation (Loews), owns 53.3 million of our common units and 33.1 million of our subordinated units, constituting approximately 68% of our partners’ equity. Boardwalk GP, LP (Boardwalk GP), an indirect, wholly-owned subsidiary of BPHC, is our general partner and holds a 2% general partner interest and all of our incentive distribution rights. Our common units are traded under the symbol “BWP” on the New York Stock Exchange.

Results of Operations – Business Overview

We derive our revenues primarily from the interstate transportation and storage of natural gas for third parties. Transportation and storage services are provided under firm and interruptible service agreements. Transportation rates are subject to maximum tariff rates established by the Federal Energy Regulatory Commission (FERC), although discounts from the maximum allowable cost-based rates are often granted to customers due to competition in the marketplace. Our Gulf South subsidiary is authorized to charge market-based rates for its firm and interruptible storage services. In first quarter 2008, our Texas Gas subsidiary was provided authority to charge market-based rates for the storage services associated with Phase III of our Western Kentucky Storage Expansion project.

Our transportation services consist of firm transportation, whereby the customer pays a capacity reservation charge to reserve pipeline capacity at certain receipt and delivery points along our pipeline systems, plus a commodity and fuel charge on the volume actually transported, and interruptible transportation, whereby the customer pays to transport gas only when capacity is available and used. We offer firm storage services in which the customer reserves and pays for a specific amount of storage capacity, including injection and withdrawal rights, and interruptible storage and parking and lending (PAL) services where the customer receives and pays for capacity only when it is available and used. Some PAL agreements are paid for at inception of the service and revenues for these agreements are recognized as service is provided over the term of the agreement.

Our operating costs and expenses typically do not vary significantly based upon the amount of gas transported, with the exception of fuel consumed at Gulf South’s compressor stations, which is part of Operation and maintenance expenses. We charge shippers for fuel in accordance with each pipeline’s individual tariff guidelines and Gulf South’s fuel recoveries are included as part of Gas transportation revenues.

We are not in the business of buying and selling natural gas other than for system management purposes, but changes in the price of natural gas can affect the overall supply and demand of natural gas, which in turn does affect our results of operations. We deliver to a broad mix of customers including local distribution companies, municipalities, interstate and intrastate pipelines, direct industrial users, electric power generation plants, marketers and producers. In addition to serving directly connected markets, our pipeline systems have indirect market access to the northeastern and southeastern United States through interconnections with unaffiliated pipelines.

Our business is affected by trends involving natural gas price levels and natural gas price spreads, including spreads between physical locations on our pipeline system, which affects our transportation revenues, and spreads in natural gas prices across time (for example summer to winter), which primarily affects our PAL and storage revenues. High natural gas prices in recent years have helped to drive increased production levels in producing locations such as the Bossier Sands and Barnett Shale gas producing regions in East Texas, which has resulted in additional supply being available on the west side of our system. This has resulted in widened west-to-east basis differentials which have benefited our transportation revenues. The high natural gas prices have also driven increased production in regions such as the Fayetteville Shale in Arkansas and the Caney Woodford Shale in Oklahoma, which, together with the higher production levels in East Texas, have formed the basis for several pipeline expansion projects including those being undertaken by us. Wide spreads in natural gas prices between time periods during the past two to three years, for example fall 2006 to spring 2007, were favorable for our PAL and interruptible storage services during that period. These spreads decreased substantially in 2007 and have continued to decrease into the first quarter 2008, which resulted in reduced PAL and interruptible storage revenues. We cannot predict future time period spreads or basis differentials.

Results of Operations for the Three Months Ended March 31, 2008 and 2007

Our net income for the first quarter 2008, increased $7.9 million, or 10%, from the comparable period in 2007. The primary drivers for the increase were higher revenues from firm transportation services associated with our East Texas to Mississippi Pipeline Expansion project and a gain from the settlement of a contract claim. The favorable drivers were partly offset by higher depreciation and property taxes due to an increase in our asset base from expansion and lower PAL revenues due to lower natural gas price spreads.

Operating revenues increased $9.2 million, or 5%, to $197.3 million for the first quarter 2008, compared to $188.1 million for the first quarter 2007, primarily due to:

$16.8 million increase in gas transportation revenues, excluding fuel, $10.9 million of which was generated by the East Texas to Mississippi Pipeline Expansion project for which we began providing services in the first quarter 2008, and the remainder of which was due to increased rates on firm transportation services from contracts that had expired in 2007 and were recontracted at the maximum allowable rates, increased interruptible transportation revenues and higher throughput;

·	$2.2 million increase in fuel revenues mainly driven by the East Texas to Mississippi Pipeline Expansion project; and

·	$10.3 million decrease in PAL revenues due to lower natural gas price spreads, partly offset by increased firm storage rates and revenues from Phase II of the Western Kentucky Storage Expansion project which was placed in service in November 2007.

Operating costs and expenses were unchanged at $95.8 million for the first quarter 2008 and 2007, primarily due to:

·	$11.5 million increase in depreciation and property taxes primarily due to an increase in our asset base from expansion; and

·	$11.2 million decrease due to a gain from the settlement of a contract claim in the Calpine Bankruptcy case.

Total other deductions increased by $1.2 million, or 10%, to $13.1 million for the first quarter 2008, compared to $11.9 million for the first quarter 2007. The increase is primarily due to an increase in interest expense due to issuances of new debt, partially offset by a $3.1 million gain from the mark-to-market effect of derivatives associated with the purchase of line pack for our pipeline expansion projects and higher allowance for equity funds used during construction related to the construction of our pipeline expansion projects.

Liquidity and Capital Resources

We are a partnership holding company and derive all of our operating cash flow from our operating subsidiaries. Our operating subsidiaries use funds from their respective operations to fund their operating activities and maintenance capital requirements, service their indebtedness and make advances or distributions to Boardwalk Pipelines. Boardwalk Pipelines uses cash provided from the operating subsidiaries and, as needed, borrowings under its revolving credit facility discussed below, to service its outstanding indebtedness and, when available, make distributions or advances to us to fund our distributions to unitholders.

Expansion Capital Expenditures

We are engaged in several pipeline expansion projects, described below, and expect the estimated total cost of these projects to be as follows (in millions):

	Initial Project Cost		Subsequent Expansion Cost			Total Project Cost		Cash Invested through March 31, 2008
East Texas to Mississippi Expansion	$	960		-		$	960	$	916.1
Southeast Expansion		775		-			775		394.8
Gulf Crossing Project		1,690		-			1,690		256.2
Fayetteville and Greenville Laterals		1,075	$	175	(a)		1,250		167.8
Total	$	4,500	$	175		$	4,675	$	1,734.9

(a)

Related to the addition of compression to increase the transmission capacity from 0.8 billion cubic feet (Bcf) per day to approximately 1.2 Bcf per day on the Fayetteville Lateral and 1.0 Bcf per day on the Greenville Lateral, described more fully below. We expect the compression to be in service in 2010.

We expect to incur expansion project capital expenditures of approximately $2.4 billion for the remainder of 2008 and $0.6 billion in 2009 and 2010 to complete our pipeline expansion projects, based upon our current cost estimates. We expect to finance our pipeline expansion capital costs through equity financings and the incurrence of debt, including sales of debt by us and our subsidiaries and borrowings under our revolving credit facility, as well as available operating cash flow in excess of our operating needs.

Our total estimated cost assumes that we will receive the necessary regulatory approvals to commence construction by June 1, 2008 on Gulf Crossing and the Fayetteville and Greenville Laterals and that we will receive the regulatory approvals necessary to operate the pipelines on certain of our projects at higher pressures, which will allow us to utilize a higher percentage of the pipeline capacity. Delays in receipt of any of these approvals will result in higher costs and additional delays in our expected in-service dates, which would also result in delays of revenues we would have received had these delays not occurred, and in certain instances will result in the payment of penalties to certain customers. Our cost and timing estimates for these projects are subject to a variety of other risks and uncertainties, including adverse weather conditions, delays in obtaining key materials, shortages of qualified labor and escalating costs of labor and materials. Please refer to Item 1A, Risk Factors, in our 2007 Form 10-K regarding risks associated with our expansion projects and the related financing.

The following paragraphs describe each of our pipeline expansion projects in more detail:

East Texas to Mississippi Expansion. The pipeline and two of the three compression facilities are now in service for our East Texas to Mississippi expansion, which project consists of approximately 242 miles of 42-inch pipeline from DeSoto Parish in western Louisiana to near Harrisville, Mississippi and approximately 110,000 horsepower of new compression having approximately 1.7 Bcf of new peak-day transmission capacity. We are serving the full contract demand which consists of customers that have contracted at fixed rates for 1.4 Bcf per day of firm transportation capacity on a long-term basis (with a weighted average term of approximately 6.8 years) which represents substantially all of the normal operating capacity. We are in the process of commissioning the remaining compression facility associated with this project, which we expect to be completed during the second quarter 2008.

Southeast Expansion. In September 2007, the FERC granted us the authority to construct, own and operate a pipeline expansion originating near Harrisville, Mississippi and extending to an interconnect with Transcontinental Pipe Line Company (Transco) in Choctaw County, Alabama (Transco 85). This expansion will initially consist of approximately 112 miles of 42-inch pipeline having approximately 1.2 Bcf of peak-day transmission capacity. To accommodate volumes expected to come from the Gulf Crossing leased capacity discussed below, this project will be expanded to up to 2.2 Bcf of peak-day transmission capacity. In addition, the FERC approved our 260 million cubic feet (MMcf) per day operating lease with Destin Pipeline Company which will provide us enhanced access to markets in Florida. Customers have contracted at fixed rates for 660 MMcf per day of firm transportation capacity on a long-term basis (with a weighted-average term of 9.2 years), in addition to the capacity leased to Gulf Crossing discussed below. Construction has commenced and we expect the initial 1.2 Bcf of capacity to be in service during the second quarter 2008. We expect the remaining capacity to be in service during the first quarter 2009.

Gulf Crossing Project. We are pursuing the construction of a new interstate pipeline that will begin near Sherman, Texas and proceed to the Perryville, Louisiana area. The project will be owned by Gulf Crossing Pipeline Company LLC, our newly formed interstate pipeline subsidiary, and will consist of approximately 357 miles of 42-inch pipeline having up to approximately 1.7 Bcf of peak-day transmission capacity. Additionally, Gulf Crossing has entered into, subject to regulatory approval: (i) an operating lease for up to 1.4 Bcf per day of capacity on our Gulf South pipeline system (including capacity on the Southeast Expansion and capacity on a portion of the East Texas to Mississippi Expansion) to make deliveries to an interconnect with Transco 85; and (ii) an operating lease with Enogex, a third-party intrastate pipeline, which will bring certain gas supplies to our system. Customers have contracted at fixed rates for 1.1 Bcf per day of long-term firm transportation capacity (with a weighted average term of approximately 9.5 years). The Final Environmental Impact Statement was received in the first quarter 2008, and we are awaiting the certificate to commence construction of the project. We expect this project to be in service during the first quarter 2009.

Fayetteville and Greenville Laterals. We are pursuing the construction of two laterals connected to our Texas Gas pipeline system to transport gas from the Fayetteville Shale area in Arkansas to markets directly and indirectly served by our existing interstate pipelines. The Fayetteville Lateral will originate in Conway County, Arkansas and proceed southeast through the Bald Knob, Arkansas, area to an interconnect with the Texas Gas mainline in Coahoma County, Mississippi and consist of approximately 165 miles of 36-inch pipeline. The Greenville Lateral will originate at the Texas Gas mainline near Greenville, Mississippi and proceed east to the Kosciusko, Mississippi area consisting of approximately 95 miles of 36-inch pipeline. The Greenville Lateral will allow customers to access additional markets, primarily in the Midwest, Northeast and Southeast. This project had an initial design capacity of 0.8 Bcf of peak-day transmission capacity which did not include compression facilities. We recently executed contracts for additional capacity that would require us to add compression to the project to increase the peak-day transmission capacity from 0.8 Bcf to approximately 1.2 Bcf for the Fayetteville Lateral and from approximately 0.8 to approximately 1.0 Bcf for the Greenville Lateral.

Including the new capacity, the contracts on the Fayetteville Lateral provide, after phase-in periods through 2012, for 975 MMcf per day of initial capacity, with options for additional capacity that, if exercised, could add 225 MMcf per day of capacity. On the Greenville Lateral, contracts for 818 MMcf per day of initial capacity are phased in through 2012 with options for additional capacity that, if exercised, could add 172 MMcf per day of capacity. The contracts associated with this project are at fixed rates with a weighted average term of 9.9 years. The Final Environmental Impact Statement was received in the first quarter 2008 and we are awaiting the certificate to commence construction of the project. We expect the first 60 miles of the Fayetteville Lateral to be in service during the third quarter 2008 and the remainder of the pipeline related to the Fayetteville and Greenville Laterals to be in service during the first quarter 2009. We expect to make additional filings with FERC regarding the additional compression required to increase the peak-day transmission capacity and expect the additional capacity to be in service during 2010.

In addition to the pipeline expansion projects described above, we are currently engaged in the following storage expansion project:

Western Kentucky Storage Expansion Phase III. In February 2008, the FERC granted us authority to develop up to 8.3 Bcf of new working gas capacity and granted market-based rate authority for this new capacity. This expansion is supported by 10-year precedent agreements for 5.1 Bcf of storage capacity. The cost of this project will be dependent on the ultimate size of the expansion. We expect 5.4 Bcf of storage capacity to be in service during 2008. The total estimated cost of this project assuming that we develop the 8.3 Bcf of working gas capacity, is expected to be approximately $87.8 million. Through March 31, 2008, we have spent $3.7 million related to this project.

Maintenance Capital Expenditures

Maintenance capital expenditures for the three months ended March 31, 2008 and 2007 were $5.2 million and $7.0 million. We expect to fund the remaining 2008 maintenance capital expenditures of approximately $57.4 million from our operating cash flows.

Distributions

For the three months ended March 31, 2008 and 2007 we paid distributions of $59.6 million and $46.1 million. Please see Note 7 in Part 1 in Item 1 of this report for further discussion.

Equity and Debt Financing

On April 24, 2008, we entered into a Class B Unit Purchase Agreement (the Purchase Agreement) to issue and sell approximately 22.9 million of our newly created class B units representing limited partner interests (class B units) to BPHC for $30 per class B unit, or an aggregate purchase price of $686 million. Our general partner will also contribute $14 million to us to maintain its 2% general partner interest. The Purchase Agreement has been approved by the Board of Directors and the Conflicts Committee of our general partner. We expect to close this transaction on or about June 17, 2008 and intend to use the proceeds of approximately $700 million to fund a portion of the costs of our ongoing expansion projects.

Beginning with the distribution in respect of the quarter ending September 30, 2008, the class B units will share in quarterly distributions of available cash from operating surplus on a pari passu basis with our common units, until each common unit and class B unit has received a quarterly distribution of $0.30. The class B units will not participate in quarterly distributions above $0.30 per unit. The class B units will be convertible into common units by the holder on a one-for-one basis at any time after June 30, 2013.

The class B units will represent a separate class of our limited partner interests. The class B units will have the same voting rights as if they were outstanding common units and will be entitled to vote as a separate class on any matters that materially adversely affect the rights or preferences of the class B units in relation to other classes of partnership interests or as required by law. Pursuant to the Purchase Agreement, at the time of closing of the sale of the class B units, we will enter into a Registration Rights Agreement with BPHC covering the common units into which the class B units will be convertible.

In March 2008, we received net proceeds of approximately $247.2 million after deducting initial purchaser discounts and offering expenses of $2.8 million from the sale of $250.0 million of 5.50% senior unsecured notes of Texas Gas due April 1, 2013.

Revolving Credit Facility

We maintain a $1.0 billion revolving credit facility under which Boardwalk Pipelines, Gulf South and Texas Gas each may borrow funds, up to applicable sub-limits. Interest on amounts drawn under the credit facility is payable at a floating rate equal to an applicable spread per annum over the London Interbank Offered Rate or a base rate defined as the greater of the prime rate or the Federal funds rate plus 50 basis points. Under the terms of the agreement, each of the borrowers must maintain a minimum ratio, as of the last day of each fiscal quarter, of consolidated total debt to consolidated earnings before income taxes, depreciation and amortization (as defined in the agreement), measured for the preceding twelve months, of not more than five to one. The revolving credit facility has a maturity date of June 29, 2012.

During the three month period ended March 31, 2008, we borrowed and repaid $153.0 million under the facility. The interest rates on the borrowings ranged from 2.76% to 3.35%. As of March 31, 2008, we were in compliance with all covenant requirements under our credit agreement and no funds were drawn under this facility, however, at March 31, 2008, we had outstanding letters of credit under the facility for $95.9 million to support certain obligations associated with the pipeline expansion projects which reduced the available capacity under the facility by such amount.

Changes in cash flow from operating activities

Net cash provided by operating activities increased $12.0 million, or 16%, to $89.3 million for the three months ended March 31, 2008, compared to $77.3 million for the comparable 2007 period, primarily due to an increase in net income excluding non-cash items such as depreciation and amortization and the recognition of income previously deferred.

Changes in cash flow from investing activities

Net cash used in investing activities increased $381.8 million to $542.8 million for the three months ended March 31, 2008, compared to $161.0 million for the comparable 2007 period, primarily due to capital expenditures related to our expansion projects.

Changes in cash flow from financing activities

Net cash provided by financing activities decreased $75.2 million to $172.6 million for the three months ended March 31, 2008, compared to $247.8 million for the comparable 2007 period, primarily due to:

·	$293.9 million decrease in net proceeds from the sale of common units and related general partner capital contributions in 2007;

·	$15.0 million decrease in cash due to the settlement of treasury locks in 2008;

·	$13.5 million decrease in cash from an increase in distributions; and

·	$247.2 million increase in net proceeds from the issuance of long term debt in March 2008.

Contractual Obligations

The table below is updated for significant changes in contractual cash payment obligations as of March 31, 2008, by period (in millions):

	Total		Less than 1 Year		1-3 Years		4-5 Years		More than 5 Years
Principal payments on long-term debt	$	2,110.0		-		-	$	225.0	$	1,885.0
Interest on long-term debt		999.0	$	77.4	$	234.9		234.9		451.8
Capital commitments		597.8		573.7		24.1		-		-
Total	$	3,706.8	$	651.1	$	259.0	$	459.9	$	2,336.8

Pursuant to the settlement of the Texas Gas rate case in 2006, we are required to annually fund an amount to the Texas Gas pension plan equal to the amount of actuarially determined net periodic pension cost, including a minimum of $3.0 million. The above table does not reflect commitments we have made after March 31, 2008, relating to our expansion projects. For information on these projects, please read “Expansion Capital Expenditures” above.

Off-Balance Sheet Arrangements

At March 31, 2008, we had no guarantees of off-balance sheet debt to third parties, no debt obligations that contain provisions requiring accelerated payment of the related obligations in the event of specified levels of declines in credit ratings, and no other off-balance sheet arrangements.

Critical Accounting Policies and Estimates

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

During the first quarter 2008, there were no significant changes to our critical accounting policies, judgments or estimates disclosed in our Annual Report on Form 10-K for the year ended December 31, 2007.

Forward-Looking Statements

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

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

We may not complete projects, including growth or expansion projects, that we have commenced or will commence, or we may complete projects on materially different terms, cost or timing than anticipated and we may not be able to achieve the intended economic or operational benefits of any such project, if completed.

The successful completion, timing, cost, scope and future financial performance of our expansion projects could differ materially from our expectations due to availability of contractors or equipment, weather, difficulties or delays in obtaining regulatory approvals or denied applications, land owner opposition, the lack of adequate materials, labor difficulties or shortages, expansion costs that are higher than anticipated and numerous other factors beyond our control.

·	We may not complete any future debt or equity financing transaction.

The gas transmission and storage operations of our subsidiaries are subject to rate-making policies and actions by the FERC or customers that could have an adverse impact on the rates we charge and our ability to recover our income tax allowance, our full cost of operating our pipelines and a reasonable return.

We are subject to laws and regulations relating to the environment and pipeline operations which may expose us to significant costs, liabilities and loss of revenues. Any changes in such regulations or their application could negatively affect our business, financial condition and results of operations.

·	Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

·	The cost of insuring our assets may increase dramatically.

Because of the natural decline in gas production connected to our system, our success depends on our ability to obtain access to new sources of natural gas, which is dependent on factors beyond our control. Any decrease in supplies of natural gas in our supply areas could adversely affect our business, financial condition and results of operations.

·	Successful development of LNG import terminals in the eastern or northeastern United States could reduce the demand for our services.

·	We may not be able to maintain or replace expiring gas transportation and storage contracts at favorable rates.

·	Significant changes in natural gas prices could affect supply and demand, reducing system throughput and adversely affecting our revenues.

Developments in any of these areas could cause our results to differ materially from results that have been or may be anticipated or projected. Forward-looking statements speak only as of the date of this report and we expressly disclaim any obligation or undertaking to update these statements to reflect any change in our expectations or beliefs or any change in events, conditions or circumstances on which any forward-looking statement is based.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Our debt has been issued at fixed rates, therefore interest expense would not be impacted by changes in interest rates. Total long-term debt at March 31, 2008, had a carrying value of $2.1 billion and a fair value of $2.0 billion. A 100 basis point increase in interest rates on our fixed rate debt would result in a decrease in fair value of approximately $126.7 million at March 31, 2008. A 100 basis point decrease would result in an increase in fair value of approximately $137.2 million at March 31, 2008. The weighted-average interest rate of our long-term debt was 5.88% at March 31, 2008.

Certain volumes of our gas stored underground are available for sale and subject to commodity price risk. At March 31, 2008 and December 31, 2007 approximately $22.9 million and $16.3 million of gas stored underground, which we own and carry as current Gas stored underground, is exposed to commodity price risk. We utilize derivatives to hedge certain exposures to market price fluctuations on the anticipated operational sales of gas.

As a result of the approval of Phase III of the Western Kentucky storage expansion project in March 2008, approximately 5.1 Bcf of gas stored underground with a book value of $11.8 million became available for sale. We entered into derivatives to hedge the price exposure related to the expected sale of this gas, which derivatives were designated as cash flow hedges.

In the second quarter 2007, we entered into natural gas price swaps to hedge exposure to prices associated with the purchase of 2.1 Bcf of natural gas to be used for line pack for our Gulf Crossing and Southeast expansion projects, approximately 1.3 Bcf of which remained outstanding at March 31, 2008. The derivatives were not designated as hedges and were marked to fair value through earnings resulting in a gain of $3.1 million for the three months ended March 31, 2008. Changes in the fair value of the derivatives will be recognized in earnings each quarter until settlement. The changes in the fair value of the gas purchased for line pack will not be recognized in earnings each quarter. When the gas is purchased, the ultimate cost will be recorded to Property, Plant and Equipment along with the other capital components of the projects and recognized in earnings as the property is depreciated. A $1.00 increase in the price of New York Mercantile Exchange natural gas futures, would result in the recognition of a $1.3 million gain in earnings. Conversely, a $1.00 decrease would result in the recognition of a $1.3 million loss.

With the exception of the derivatives related to certain storage gas volumes related to Phase II of the Western Kentucky storage expansion project and line pack gas purchases referred to above, the derivatives related to the sale or purchase of natural gas, cash for fuel reimbursement and debt issuance generally qualify for cash flow hedge accounting under Statement of Financial Accounting Standards No. 133 and are designated as such. The effective component of related unrealized gains and losses resulting from changes in fair values of the derivatives contracts designated as cash flow hedges are deferred as a component of Accumulated other comprehensive income. The deferred gains and losses are recognized in the Condensed Consolidated Statements of Income when the anticipated transactions affect earnings. Generally, for gas sales and cash for fuel reimbursement, any gains and losses on the related derivatives would be recognized in Operating Revenues. For the sale of gas related to Phase II of the Western Kentucky storage expansion project, any gains and losses on the related derivatives would be recognized in Net gain on disposal of operating assets and related contracts. Any gains and losses on the derivatives related to the line pack gas purchases would be recognized in Miscellaneous other income, net.

We are exposed to credit risk relating to the risk of loss resulting from the nonperformance by a customer of its contractual obligations. Our exposure generally relates to receivables for services provided, as well as volumes owed by customers for imbalances or gas lent by us to them, generally under PAL and no-notice service. We maintain credit policies intended to minimize credit risk and actively monitor these policies. Natural gas price volatility has increased dramatically in recent years, which has materially increased credit risk related to gas loaned to customers. As of March 31, 2008, the amount of gas loaned out by our subsidiaries was approximately 37.8 trillion British thermal units (TBtu) and the amount considered an imbalance was approximately 3.6 TBtu. Assuming an average market price during March 2008 of $9.32 per million British thermal units (MMBtu), the market value of gas loaned out and considered an imbalance at March 31, 2008, would have been approximately $385.2 million. As of December 31, 2007, the amount of gas loaned out by our subsidiaries was approximately 12.7 TBtu and the amount considered an imbalance was approximately 2.5 TBtu. Assuming an average market price during December 2007 of $7.13 per MMBtu, the market value of gas loaned out at December 31, 2007 would have been approximately $108.2 million. If any significant customer of ours should have credit or financial problems resulting in a delay or failure to repay the gas they owe to us, this could have a material adverse effect on our financial condition, results of operations and cash flows.

As of March 31, 2008, our cash and cash equivalents were invested primarily in mutual funds. Due to the short-term nature and type of our investments, a hypothetical 10% increase in interest rates would not have a material effect on the fair market value of our portfolio. Since we have the ability to liquidate this portfolio, we do not expect our earnings or cash flows to be materially impacted by the effect of a sudden change in market interest rates on our investment portfolio.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

We maintain a system of disclosure controls and procedures which is designed to ensure that information required to be disclosed by us in reports that we file or submit under the federal securities laws, including this report is recorded, processed, summarized and reported on a timely basis. These disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by us under the federal securities laws is accumulated and communicated to us on a timely basis to allow decisions regarding required disclosure.

Our principal executive officer (CEO) and principal financial officer (CFO) undertook an evaluation of our disclosure controls and procedures as of the end of the period covered by this report. The CEO and CFO have concluded that our controls and procedures were effective as of March 31, 2008.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the first quarter 2008, that have materially affected or that are reasonably likely to materially affect our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

For a discussion of certain of our current legal proceedings, please read Note 6 of the Notes to Condensed Consolidated Financial Statements in Item 1 of this Report.

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

On March 25, 2008, our general partner purchased 1,500 of our common units in the open market at a price of $23.78 per unit. These units were granted to our independent directors as part of their director compensation.

Item 6. Exhibits

Exhibit Number
Exhibit Number		Description

3.1		Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Boardwalk Pipeline Partners, LP, effective as of January 1, 2007. (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on April 11, 2008).
4.1		Indenture dated March 27, 2008, between Texas Gas Transmission, LLC and the Bank of New York Trust Company, N.A. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on March 27, 2008).
*10.1		Amendment No. 3 to Amended and Restated Revolving Credit Agreement, dated as of March 6, 2008, among the Registrant, Boardwalk Pipelines, LP, Texas Gas Transmission, LLC and Gulf South Pipeline Company, LP, and the agent and lender parties identified therein.
*10.2		Separation Agreement and General Release between H. Dean Jones II and Texas Gas Transmission, LLC, Boardwalk GL, LLC, Boardwalk Pipelines Holding Corp. and Boardwalk Operating GP, LLC.
*31.1		Certification of Rolf A. Gafvert, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a).
*31.2		Certification of Jamie L. Buskill, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a).
*32.1		Certification of Rolf A. Gafvert, Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2		Certification of Jamie L. Buskill, Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith

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: April 29, 2008			By:	/s/ Jamie L. Buskill
				Jamie L. Buskill
				Senior Vice President, Chief Financial Officer and Treasurer