BWP 14 Q3 10Q 093014

10-Q 1 bwp14q310q093014.htm 10-Q BWP 14 Q3 10Q 093014

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2014

¨ 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 ý No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o

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 ý 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 ý

As of November 3, 2014, the registrant had 243,223,801 common units outstanding.

TABLE OF CONTENTS

FORM 10-Q

September 30, 2014

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 Comprehensive Income	6
Condensed Consolidated Statements of Cash Flows	7
Condensed Consolidated Statements of Changes in Equity	8
Notes to Condensed Consolidated Financial Statements	9

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	33

Item 3. Quantitative and Qualitative Disclosures About Market Risk	40

Item 4. Controls and Procedures	40

PART II - OTHER INFORMATION

Item 1. Legal Proceedings	41

Item 1A. Risk Factors	41

Item 6. Exhibits	41

Signatures	43

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Millions)

(Unaudited)



ASSETS	September 30, 2014		December 31, 2013
Current Assets:
Cash and cash equivalents	$	6.2	$	28.5
Receivables:
Trade, net	84.4		103.5
Affiliates	—		1.1
Other	10.2		15.7
Gas transportation receivables	8.8		7.8
Costs recoverable from customers	0.3		0.8
Gas and liquids stored underground	4.5		0.7
Prepayments	17.8		12.9
Other current assets	6.3		6.1
Total current assets	138.5		177.1

Property, Plant and Equipment:
Natural gas transmission and other plant	8,698.6		8,548.8
Construction work in progress	325.1		174.5
Property, plant and equipment, gross	9,023.7		8,723.3
Less—accumulated depreciation and amortization	1,692.4		1,489.2
Property, plant and equipment, net	7,331.3		7,234.1

Other Assets:
Goodwill	215.5		215.5
Gas stored underground	93.4		79.7
Investment in unconsolidated affiliates	—		78.6
Other	152.5		129.5
Total other assets	461.4		503.3

Total Assets	$	7,931.2	$	7,914.5

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

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Millions)

(Unaudited)



LIABILITIES AND EQUITY	September 30, 2014			December 31, 2013
Current Liabilities:
Payables:
Trade	$	53.7		$	65.1
Affiliates	0.8			1.2
Other	11.9			5.7
Gas Payables:
Transportation	7.8			8.8
Storage	0.3			0.2
Accrued taxes, other	67.3			46.1
Accrued interest	31.1			45.4
Accrued payroll and employee benefits	24.1			26.4
Deferred income	2.3			9.3
Other current liabilities	40.0			27.8
Total current liabilities	239.3			236.0

Long-term debt and capital lease obligations	3,410.6			3,424.4

Other Liabilities and Deferred Credits:
Pension liability	14.2			17.1
Asset retirement obligation	34.3			39.3
Provision for other asset retirement	59.8			57.6
Payable to affiliate	16.0			16.0
Other	61.9			60.7
Total other liabilities and deferred credits	186.2			190.7

Commitments and Contingencies

Equity:
Partners’ Capital:
Common units – 243.3 million units issued and outstanding as of September 30, 2014, and December 31, 2013	4,083.4			3,963.4
General partner	79.7			77.3
Accumulated other comprehensive loss	(68.3		)	(63.8		)
Total partners’ capital	4,094.8			3,976.9
Noncontrolling interest	0.3			86.5
Total Equity	4,095.1			4,063.4
Total Liabilities and Equity	$	7,931.2		$	7,914.5

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

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Millions)

(Unaudited)



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2014			2013			2014			2013
Operating Revenues:
Transportation	$	238.9		$	233.5		$	788.9		$	759.9
Parking and lending	3.0			4.9			21.4			19.9
Storage	19.2			27.4			70.1			82.9
Other	17.8			9.7			48.8			30.0
Total operating revenues	278.9			275.5			929.2			892.7

Operating Costs and Expenses:
Fuel and transportation	31.9			18.5			94.8			68.6
Operation and maintenance	50.3			47.0			136.9			131.0
Administrative and general	31.8			29.1			89.1			89.4
Depreciation and amortization	72.2			68.7			211.0			202.8
Asset impairment	—			—			8.6			1.2
Net loss (gain) on sale of operating assets	0.1			(13.0		)	(1.1		)	(29.2		)
Taxes other than income taxes	24.1			22.0			72.3			72.9
Total operating costs and expenses	210.4			172.3			611.6			536.7

Operating income	68.5			103.2			317.6			356.0

Other Deductions (Income):
Interest expense	40.0			41.0			121.1			122.2
Interest income	(0.1		)	(0.1		)	(0.4		)	(0.4		)
Equity losses in unconsolidated affiliates	0.3			0.6			86.9			0.6
Miscellaneous other income, net	(0.2		)	—			(0.3		)	(0.2		)
Total other deductions	40.0			41.5			207.3			122.2

Income before income taxes	28.5			61.7			110.3			233.8

Income taxes	0.1			—			0.4			0.3

Net income	28.4			61.7			109.9			233.5
Net loss attributable to noncontrolling interests	(0.8		)	(0.6		)	(86.9		)	(0.7		)
Net income attributable to controlling interests	$	29.2		$	62.3		$	196.8		$	234.2

Net Income per Unit:
Basic net income per unit:
Common units	$	0.12		$	0.27		$	0.79		$	0.96
Class B units	$	—		$	(0.32	)	$	—		$	(0.11	)
Weighted-average number of units outstanding - basic:
Common units	243.3			220.4			243.3			213.5
Class B units	—			22.9			—			22.9
Diluted net income per unit:
Common units	$	0.12		$	0.21		$	0.79		$	0.90
Class B units	$	—		$	—		$	—		$	0.19
Weighted-average number of units outstanding - diluted:
Common units	243.3			243.3			243.3			221.2
Class B units	—			—			—			15.2
Cash distribution declared and paid to common units	$	0.10		$	0.5325		$	0.30		$	1.5975
Cash distribution declared and paid to class B units	$	—		$	0.30		$	—		$	0.90

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

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Millions)

(Unaudited)



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2014			2013			2014			2013
Net income	$	28.4		$	61.7		$	109.9		$	233.5
Other comprehensive income (loss):
Gain (loss) on cash flow hedges	0.2			—			(0.7		)	2.5
Reclassification adjustment transferred to Net Income from cash flow hedges	0.5			(0.6		)	2.1			0.5
Pension and other postretirement benefit costs	(2.0		)	(0.4		)	(5.9		)	(4.0		)
Total Comprehensive Income	27.1			60.7			105.4			232.5
Comprehensive loss attributable to noncontrolling interests	(0.8		)	(0.6		)	(86.9		)	(0.7		)
Comprehensive income attributable to controlling interests	$	27.9		$	61.3		$	192.3		$	233.2

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

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions)

(Unaudited)



	For the Nine Months Ended September 30,
OPERATING ACTIVITIES:	2014			2013
Net income	$	109.9		$	233.5
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization	211.0			202.8
Amortization of deferred costs	4.3			4.0
Asset impairment	8.6			1.2
Net gain on sale of operating assets	(1.1		)	(29.2		)
Equity losses in unconsolidated affiliates	86.9			0.6
Changes in operating assets and liabilities:
Trade and other receivables	24.7			(4.6		)
Other receivables, affiliates	0.9			0.8
Gas receivables and storage assets	(18.4		)	27.3
Costs recoverable from customers	1.7			2.6
Other assets	(3.6		)	(5.6		)
Trade and other payables	0.6			(26.3		)
Other payables, affiliates	(0.5		)	0.2
Gas payables	(6.6		)	(5.8		)
Accrued liabilities	5.9			11.6
Other liabilities	(11.8		)	(11.1		)
Net cash provided by operating activities	412.5			402.0

INVESTING ACTIVITIES:
Capital expenditures	(315.9		)	(204.3		)
Proceeds from sale of operating assets	2.9			48.6
Proceeds from insurance and other recoveries	6.3			1.4
Advances to affiliates	0.1			(2.8		)
Investment in unconsolidated affiliates	(20.5		)	(25.6		)
Distribution from unconsolidated affiliates	10.7			—
Acquisition-related deposit	(29.5		)	—
Net cash used in investing activities	(345.9		)	(182.7		)

FINANCING ACTIVITIES:
Proceeds from borrowings on revolving credit agreement	340.0			813.0
Repayment of borrowings on revolving credit agreement	(330.0		)	(1,030.0		)
Principal payment of capital lease obligation	(0.3		)	(0.1		)
Repayment of borrowings from term loan	(25.0		)	—
Advances from affiliate	0.1			(2.8		)
Distributions paid	(74.4		)	(392.0		)
Capital contributions from noncontrolling interests	8.2			37.2
Distributions paid to noncontrolling interests	(7.5		)	—
Proceeds from sale of common units	—			368.7
Capital contributions from general partner	—			7.8
Net cash used in financing activities	(88.9		)	(198.2		)
(Decrease) increase in cash and cash equivalents	(22.3		)	21.1
Cash and cash equivalents at beginning of period	28.5			3.9
Cash and cash equivalents at end of period	$	6.2		$	25.0

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

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Millions)

(Unaudited)



	Partners' Capital
	Common Units			Class B Units			General Partner			Accumulated Other Comp Loss			Non-controlling Interest			Total Equity
Balance January 1, 2013	$	3,190.3		$	678.3		$	75.8		$	(67.3	)	$	—		$	3,877.1
Add (deduct):
Net income	185.1			19.9			29.2			—			(0.7		)	233.5
Distributions paid	(338.5		)	(20.6		)	(32.9		)	—			—			(392.0		)
Sale of common units, net of related transactions costs	368.7			—			—			—			—			368.7
Capital contributions from general partner	—			—			7.8			—			—			7.8
Capital contributions from noncontrolling interests	—			—			—			—			40.3			40.3
Other comprehensive loss	—			—			—			(1.0		)	—			(1.0		)
Balance September 30, 2013	$	3,405.6		$	677.6		$	79.9		$	(68.3	)	$	39.6		$	4,134.4

Balance January 1, 2014	$	3,963.4		$	—		$	77.3		$	(63.8	)	$	86.5		$	4,063.4
Add (deduct):
Net income (loss)	192.9			—			3.9			—			(86.9		)	109.9
Distributions paid	(72.9		)	—			(1.5		)	—			—			(74.4		)
Capital contributions from noncontrolling interests	—			—			—			—			8.2			8.2
Distributions paid to noncontrolling interests	—			—			—			—			(7.5		)	(7.5		)
Other comprehensive loss	—			—			—			(4.5		)	—			(4.5		)
Balance September 30, 2014	$	4,083.4		$	—		$	79.7		$	(68.3	)	$	0.3		$	4,095.1

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 in 2005 to own and operate the business conducted by its primary subsidiary Boardwalk Pipelines, LP (Boardwalk Pipelines) and its operating subsidiaries and consists of integrated natural gas and natural gas liquids (NGLs) pipeline and storage systems and natural gas gathering and processing.

As of November 3, 2014, Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned subsidiary of Loews Corporation (Loews), owned 125.6 million of the Partnership’s common units, and, through Boardwalk GP, LP (Boardwalk GP), an indirect wholly-owned subsidiary of BPHC, holds the 2% general partner interest and all of the incentive distribution rights (IDRs). As of November 3, 2014, the common units and general partner interest owned by BPHC represent approximately 53% of the Partnership’s equity interests, excluding the IDRs. The Partnership’s common units are traded under the symbol “BWP” on the New York Stock Exchange.

The accompanying unaudited condensed consolidated financial statements of the Partnership were prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) have been condensed or omitted pursuant to such rules and regulations. In the opinion of management, the accompanying condensed consolidated financial statements reflect all adjustments (consisting of only normal recurring accruals) necessary to present fairly the financial position as of September 30, 2014, and December 31, 2013, and the results of operations and comprehensive income for the three and nine months ended September 30, 2014 and 2013, and changes in cash flows and changes in equity for the nine months ended September 30, 2014 and 2013. Reference is made to the Notes to Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2013 (2013 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 2013 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.

Note 2: Investments

Bluegrass Pipeline, Moss Lake Fractionation and Moss Lake LPG Terminal Projects

As discussed in Note 3 to the Partnership’s 2013 Annual Report on Form 10-K, the Partnership and The Williams Companies, Inc. (Williams) formed joint ventures for the development process of the Bluegrass Project. In the third quarter 2014, the Partnership and Williams agreed to dissolve the Bluegrass Project entities, including the dissolution of Bluegrass Pipeline, Moss Lake Fractionation and Moss Lake LPG. In the first quarter 2014, the Bluegrass Project entities expensed the previously capitalized project costs related to the development process due to lack of customer commitments, resulting in a $92.9 million charge, which was reflected in Equity losses in unconsolidated affiliates and Asset impairment on the income statement. Net of noncontrolling interests of $82.9 million associated with the Bluegrass investment, these expenses reduced the Partnership’s Net income attributable to controlling interests by $10.0 million.

At September 30, 2014, Boardwalk Bluegrass and Boardwalk Moss Lake had no remaining investment balance related to the Bluegrass Project entities. As of September 30, 2014, the Partnership included in its Condensed Consolidated Balance Sheet $0.3 million of cash that represent amounts recorded by Boardwalk Bluegrass and Boardwalk Moss Lake. At December 31, 2013, the Partnership had included $15.0 million of cash, $78.6 million of investments in unconsolidated affiliates and $6.8 million of construction work in progress related to amounts recorded by Boardwalk Bluegrass and Boardwalk Moss Lake.

Note 3: Gas and Liquids Stored Underground and Gas and NGLs Receivables and Payables

Subsidiaries of the Partnership provide storage services whereby they store gas or NGLs on behalf of customers and also periodically hold customer gas under parking and lending (PAL) services. Since the customers retain title to the gas held by the Partnership in providing these services, the Partnership does not record the related gas on its balance sheet.

Subsidiaries of the Partnership also periodically lend gas to customers under PAL and no-notice services. As of September 30, 2014, the amount of gas owed to the subsidiaries of the Partnership due to gas imbalances and gas loaned under PAL and no-notice services was approximately 7.2 trillion British thermal units (TBtu). Assuming an average market price during September 2014 of $3.87 per million British thermal unit, the market value of that gas was approximately $27.8 million. As of December 31, 2013, the amount of gas owed to the subsidiaries of the Partnership due to gas imbalances and gas loaned under PAL and no-notice services was approximately 19.6 TBtu. As of September 30, 2014, and December 31, 2013, there were no outstanding NGLs imbalances owed to the operating subsidiaries. If any significant customer should have credit or financial problems resulting in a delay or failure to repay the gas or NGLs owed to the operating subsidiaries, it could have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows.

Note 4: Fair Value Measurements, Derivatives and Other Comprehensive Income (OCI)

The Partnership’s assets that were recorded at fair value on a non-recurring basis as of September 30, 2014, were as follows (in millions):



			Fair Value Measurements at September 30, 2014
	September 30, 2014		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)		Total Gains (losses) for the three months ended September 30, 2014		Total Gains (losses) for the nine months ended September 30, 2014

Non-recurring fair value measurements - Assets
Assets held and used	$	—	$	—	$	—	$	—	$	—	$	(7.1	)	⁽¹⁾
Investment in unconsolidated affiliates	—		—		—		—		—		(85.8		)	⁽¹⁾


(1)	Net of noncontrolling interests of $82.9 million, the amount of the loss to the Partnership was $10.0 million. The impairment charge related to assets held and used represents the carrying amount of the assets. Note 2 contains more information regarding these measurements. Note 5 contains additional information related to asset impairment charges not included in the above table.

There were no liabilities recorded at fair value on a non-recurring basis at September 30, 2014. The Partnership’s assets and liabilities recorded at fair value on a recurring basis as of September 30, 2014, and December 31, 2013, were related to its derivatives.

Derivatives

The Partnership uses futures, swaps and option contracts (collectively, derivatives) to hedge exposure to natural gas commodity price risk related to the future operational sales of natural gas and cash for fuel reimbursement where customers pay cash for the cost of fuel used in providing transportation services as opposed to having fuel retained in kind. This price risk exposure includes approximately $4.2 million and $0.3 million of gas stored underground at September 30, 2014, and December 31, 2013, which the Partnership owns and carries on its balance sheet as current Gas and liquids stored underground. The derivatives qualify for cash flow hedge accounting and are generally designated as such. The Partnership’s natural gas derivatives are reported at fair value based on New York Mercantile Exchange (NYMEX) quotes for natural gas futures and options. The NYMEX quotes are deemed to be observable inputs in an active market for similar assets and liabilities and are considered Level 2 inputs for purposes of fair value disclosures. The fair value of derivatives designated as cash flow hedges existing as of September 30, 2014, included in Other current assets in the Condensed Consolidated Balance Sheets was less than $0.1 million. The fair value of derivatives designated as cash flow hedges existing as of December 31, 2013, included in Other current assets in the Condensed Consolidated Balance Sheets was $0.5 million.

The Partnership had $11.3 million and $12.7 million of Accumulated other comprehensive loss (AOCI) related to cash flow hedges as of September 30, 2014, and December 31, 2013. The Partnership estimates that approximately $2.3 million of net losses from cash flow hedges reported in AOCI as of September 30, 2014, are expected to be reclassified into earnings within the next twelve months and primarily relates to previously settled Treasury rate locks that are being amortized to earnings over the terms of the related interest payments, generally the terms of the related debt.

Other Comprehensive Income (OCI)

The following table shows the components and reclassifications to net income of AOCI which is included in Partners' Capital on the Condensed Consolidated Balance Sheets for the three months ended September 30, 2014 (in millions):



	Cash Flow Hedges			Pension and Other Postretirement Costs			Total
Beginning balance, July 1, 2014	$	(12.0	)	$	(55.0	)	$	(67.0	)
Gain recorded in accumulated other comprehensive loss		0.2			—			0.2
Reclassifications:
Transportation operating revenues		(0.1	)		—			(0.1	)
Interest expense		0.6			—			0.6
Pension and other postretirement benefit costs		—			(2.0	)		(2.0	)

Ending balance, September 30, 2014	$	(11.3	)	$	(57.0	)	$	(68.3	)



	Cash Flow Hedges			Pension and Other Postretirement Costs			Total
Beginning balance, July 1, 2013	$	(11.9	)	$	(55.4	)	$	(67.3	)
Gain (loss) recorded in accumulated other comprehensive loss		—			—			—
Reclassifications:
Disposal of assets		(1.2	)		—			(1.2	)
Interest expense		0.6			—			0.6
Pension and other postretirement benefit costs		—			(0.4	)		(0.4	)

Ending balance, September 30, 2013	$	(12.5	)	$	(55.8	)	$	(68.3	)

The following table shows the components and reclassifications to net income of AOCI which is included in Partners' Capital on the Condensed Consolidated Balance Sheets for the nine months ended September 30, 2014 (in millions):



	Cash Flow Hedges			Pension and Other Postretirement Costs			Total
Beginning balance, January 1, 2014	$	(12.7	)	$	(51.1	)	$	(63.8	)
Loss recorded in accumulated other comprehensive loss		(0.7	)		—			(0.7	)
Reclassifications:
Transportation operating revenues		0.1			—			0.1
Other operating revenues		0.2			—			0.2
Interest expense		1.8			—			1.8
Pension and other postretirement benefit costs		—			(5.9	)		(5.9	)

Ending balance, September 30, 2014	$	(11.3	)	$	(57.0	)	$	(68.3	)

The following table shows the components and reclassifications to net income of AOCI which is included in Partners' Capital on the Condensed Consolidated Balance Sheets for the nine months ended September 30, 2013 (in millions):



	Cash Flow Hedges			Pension and Other Postretirement Costs			Total
Beginning balance, January 1, 2013	$	(15.5	)	$	(51.8	)	$	(67.3	)
Gain recorded in accumulated other comprehensive loss		2.5			—			2.5
Reclassifications:
Transportation operating revenues		0.1			—			0.1
Other operating revenues		(0.1	)		—			(0.1	)
Disposal of assets		(1.2	)		—			(1.2	)
Interest expense		1.7			—			1.7
Pension and other postretirement benefit costs		—			(4.0	)		(4.0	)

Ending balance, September 30, 2013	$	(12.5	)	$	(55.8	)	$	(68.3	)

Financial Assets and Liabilities

The following methods and assumptions were used in estimating the fair value amounts included in the disclosures for financial assets and liabilities, which are consistent with those disclosed in the 2013 Annual Report on Form 10-K:

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

Long-Term Debt: The estimated fair value of the Partnership's publicly traded debt is based on quoted market prices at September 30, 2014, and December 31, 2013. The fair market value of the debt that is not publicly traded is based on market prices of similar debt at September 30, 2014, and December 31, 2013. The carrying amount of the Partnership's variable rate debt approximates fair value because the instruments bear a floating market-based interest rate.

The carrying amount and estimated fair values of the Partnership's financial assets and liabilities which are not recorded at fair value on the Condensed Consolidated Balance Sheets as of September 30, 2014, and December 31, 2013, were as follows (in millions):



As of September 30, 2014				Estimated Fair Value
Financial Assets	Carrying Amount			Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	6.2		$	6.2	$	—	$	—	$	6.2

Financial Liabilities
Long-term debt	$	3,400.9	⁽¹⁾	$	—	$	3,551.1	$	—	$	3,551.1

(1) The carrying amount of long-term debt excludes a $9.7 million capital lease obligation.



As of December 31, 2013				Estimated Fair Value
Financial Assets	Carrying Amount			Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	28.5		$	28.5	$	—	$	—	$	28.5

Financial Liabilities
Long-term debt	$	3,414.4	⁽¹⁾	$	—	$	3,573.8	$	—	$	3,573.8

(1) The carrying amount of long-term debt excludes a $10.0 million capital lease obligation.

Note 5: Property, Plant and Equipment

Gas Sales

For the three and nine months ended September 30, 2013, the Partnership recognized a gain of $12.5 million and $29.5 million from the sale of approximately 9.7 Bcf and 14.7 Bcf of natural gas stored underground with a carrying amount of $23.1 million and $25.7 million. The gas was sold as a result of a change in the storage gas needed to support operations and no-notice services.

Asset Impairments and Dispositions

The Partnership recognized asset impairment charges of $8.6 million and $1.2 million for the nine months ended September 30, 2014 and 2013. There were no asset impairment charges for the three months ended September 30, 2014 and 2013. Most of the 2014 asset impairment charges are related to the Bluegrass Project. Refer to Note 2 for further information. The charges recorded in 2013 resulted from an increase in the estimate of existing asset retirement obligations related to retired assets.

Note 6: Commitments and Contingencies

Legal Proceedings and Settlements

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

Whistler Junction Matter

The Partnership's Gulf South subsidiary and several other defendants, including Mobile Gas Service Corporation (MGSC), have been named as defendants in nine lawsuits, including one purported class action suit, commenced by multiple plaintiffs in the Circuit Court of Mobile County, Alabama. The plaintiffs seek unspecified damages for personal injury and property damage related to an alleged release of mercaptan at the Whistler Junction facilities in Eight Mile, Alabama. Gulf South delivers natural gas to MGSC, the local distribution company for that region, at Whistler Junction where MGSC odorizes the gas prior to delivery to end user customers by injecting mercaptan into the gas stream, as required by law. The cases are: Parker, et al. v. MGSC, et al. (Case No. CV-12-900711), Crum, et al. v. MGSC, et al. (Case No. CV-12-901057), Austin, et al. v. MGSC, et al. (Case No. CV-12-901133), Moore, et al. v. MGSC, et al. (Case No. CV-12-901471), Davis, et al. v. MGSC, et al. (Case No. CV-12-901490),

Joel G. Reed, et al. v. MGSC, et al. (Case No. CV-2013-922265), The Housing Authority of the City of Prichard, Alabama v. MGSC., et al. (Case No. CV-2013-901002), Robert Evans, et al. v. MGSC, et al. (Case No. CV-2013-902627), and Devin Nobles, et al. v. MGSC, et al. (Case No. CV-2013-902786). Gulf South has denied liability. Gulf South has demanded that MGSC indemnify Gulf South against all liability related to these matters pursuant to a right-of-way agreement between Gulf South and MGSC, and has filed cross-claims against MGSC for any such liability. MGSC has also filed cross-claims against Gulf South seeking indemnity and other relief from Gulf South.

In May 2014, Gulf South and MGSC reached an agreement whereby MGSC fully indemnified Gulf South against all liability related to this matter and the cross-claims between Gulf South and MGSC were settled.

Southeast Louisiana Flood Protection Litigation

On August 13, 2013, the Partnership and its subsidiary, Gulf South, along with approximately 100 other energy companies operating in Southern Louisiana, have been named as defendants in a petition for damages and injunctive relief in state district court for Orleans Parish, Louisiana (Case No. 13-6911) by the Board of Commissioners of the Southeast Louisiana Flood Protection Authority - East (Flood Protection Authority). The case was filed in state court, but was removed to the United States District Court for the Eastern District of New Orleans. The plaintiff has moved for remand back to state court, but the Court denied the remand and the case will remain in Federal Court. The lawsuit claims include negligence, strict liability, public nuisance, private nuisance, breach of contract, and breach of the natural servitude of drain against the defendants, alleging that the defendants’ drilling, dredging, pipeline and industrial operations since the 1930s have caused increased storm surge risk, increased flood protection costs and unspecified damages to the Flood Protection Authority. In addition to attorney fees and unspecified monetary damages, the lawsuit seeks abatement and restoration of the coastal lands, including backfilling and re-vegetating of canals dredged and used by the defendants, and abatement and restoration activities such as wetlands creation, reef creation, land bridge construction, hydrologic restoration, shoreline protection, structural protection, bank stabilization, and ridge restoration.

The outcome of the Southeast Louisiana Flood Protection Litigation case cannot be predicted at this time; however, based on the facts and circumstances presently known, in the opinion of management, this case will not be material to the Partnership's financial condition, results of operations or cash flows.

Environmental and Safety Matters

The operating subsidiaries are subject to federal, state and local environmental laws and regulations in connection with the operation and remediation of various operating sites. As of September 30, 2014, and December 31, 2013, the Partnership had an accrued liability of approximately $6.0 million and $6.5 million related to assessment and/or remediation costs associated with the historical use of polychlorinated biphenyls, petroleum hydrocarbons and mercury, groundwater protection measures and other costs. The liability represents management’s estimate of the undiscounted future obligations based on evaluations and discussions with counsel and operating personnel and the current facts and circumstances related to these matters. The related expenditures are expected to occur over the next eight years. As of September 30, 2014, and December 31, 2013, approximately $1.5 million was recorded in Other current liabilities and approximately $4.5 million and $5.0 million were recorded in Other Liabilities and Deferred Credits.

Commitments for Construction

The Partnership’s future capital commitments are comprised of binding commitments under purchase orders for materials ordered but not received and firm commitments under binding construction service agreements. The commitments as of September 30, 2014, were approximately $85.0 million, all of which are expected to be settled within the next twelve months.

There were no substantial changes to the Partnership’s operating lease commitments, pipeline capacity agreements or capital lease obligation disclosed in Note 5 to the Partnership’s 2013 Annual Report on Form 10-K.

Note 7: Cash Distributions and Net Income per Unit

Cash Distributions

In the third quarter 2014, the Partnership declared and paid quarterly distributions to its common unitholders of record of $0.10 per common unit and an amount to the general partner on behalf of its 2% general partner interest. In the third quarter 2013, the Partnership declared and paid a quarterly distribution to its common unitholders of record of $0.5325 per common unit, $0.30 per class B unit to the holder of the class B units (which converted to common units in October 2013 on a one-for-one basis pursuant to the terms of the partnership agreement) and amounts to the general partner on behalf of its 2% general partner interest

and as holder of the IDRs. In October 2014, the Partnership declared a quarterly cash distribution to unitholders of record of $0.10 per common unit.

Net Income per Unit

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

Under the Partnership’s partnership agreement, for any quarterly period, the IDRs participate in net income only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed net income or losses. Accordingly, undistributed net income is assumed to be allocated to the other ownership interests on a pro rata basis, except that the class B units’ participation in net income is limited to $0.30 per unit per quarter. The Class B units were converted to common units on a one-for-one basis in October 2013. Payments made on account of the Partnership’s various ownership interests are determined in relation to actual declared distributions, and are not based on the assumed allocations required under GAAP. Basic net income per unit is calculated based on the weighted-average number of units outstanding for the period. Diluted net income per unit is calculated assuming that the Class B units converted on the date that they became convertible, or July 1, 2013.

The following table provides a reconciliation of net income and the assumed allocation of net income to the common units for purposes of computing net income per unit for the three months ended September 30, 2014, (in millions, except per unit data):



	Total			Common Units		General Partner and IDRs
Net income	$	28.4
Less: Net loss attributable to noncontrolling interests	(0.8		)
Net income attributable to controlling interests	29.2
Declared distribution	24.8			$	24.3	$	0.5
Assumed allocation of undistributed net income	4.4			4.3		0.1
Assumed allocation of net income attributable to limited partner unitholders and general partner	$	29.2		$	28.6	$	0.6
Weighted-average units outstanding				243.3
Net income per unit				$	0.12

The following table provides a reconciliation of net income and the assumed allocation of net income to the common and class B units for purposes of computing basic and diluted net income per unit for the three months ended September 30, 2013, (in millions, except per unit data):



	Total			Common Units			Class B Units			General Partner and IDRs
Net income	$	61.7
Less: Net loss attributable to noncontrolling interests	(0.6		)
Net income attributable to controlling interests	62.3
Declared distribution	141.9			$	129.5		$	—		$	12.4
Assumed allocation of undistributed net loss - basic	(79.6		)	(70.7		)	(7.3		)	(1.6		)
Assumed allocation of net income attributable to limited partner unitholders and general partner - basic	62.3			58.8			(7.3		)	10.8
Allocation for diluted earnings per unit	—			(7.3		)	7.3			—
Assumed allocation of net income attributable to limited partner unitholders and general partner - diluted	$	62.3		$	51.5		$	—		$	10.8
Weighted-average units outstanding - basic				220.4			22.9
Weighted-average units outstanding - diluted				243.3			—
Net income per unit - basic				$	0.27		$	(0.32	)
Net income per unit - diluted				$	0.21		$	—

The following table provides a reconciliation of net income and the assumed allocation of net income to the common units for purposes of computing net income per unit for the nine months ended September 30, 2014, (in millions, except per unit data):



	Total			Common Units		General Partner and IDRs
Net income	$	109.9
Less: Net loss attributable to noncontrolling interests	(86.9		)
Net income attributable to controlling interests	196.8
Declared distribution	74.5			$	73.0	$	1.5
Assumed allocation of undistributed net income	122.3			119.9		2.4
Assumed allocation of net income attributable to limited partner unitholders and general partner	$	196.8		$	192.9	$	3.9
Weighted-average units outstanding				243.3
Net income per unit				$	0.79

The following table provides a reconciliation of net income and the assumed allocation of net income to the common and class B units for purposes of computing basic and diluted net income per unit for the nine months ended September 30, 2013, (in millions, except per unit data):



	Total			Common Units			Class B Units			General Partner and IDRs
Net income	$	233.5
Less: Net loss attributable to noncontrolling interests	(0.7		)
Net income attributable to controlling interests	234.2
Declared distribution	405.7			$	357.5		$	13.7		$	34.5
Assumed allocation of undistributed net loss - basic	(171.5		)	(151.9		)	(16.2		)	(3.4		)
Assumed allocation of net income attributable to limited partner unitholders and general partner - basic	234.2			205.6			(2.5		)	31.1
Allocation for diluted earnings per unit	—			(5.4		)	5.4			—
Assumed allocation of net income attributable to limited partner unitholders and general partner - diluted	$	234.2		$	200.2		$	2.9		$	31.1
Weighted-average units outstanding - basic				213.5			22.9
Weighted-average units outstanding - diluted				221.2			15.2
Net income per unit - basic				$	0.96		$	(0.11	)
Net income per unit - diluted				$	0.90		$	0.19

Note 8: Financing

Notes and Debentures

As of September 30, 2014, and December 31, 2013, the Partnership had notes and debentures outstanding of $3.0 billion with a weighted-average interest rate of 5.32%, including $275.0 million of notes which mature in February 2015 and $250.0 million of notes which mature in June 2015. The notes which mature in 2015 were included with the other notes and debentures in long-term debt on the Condensed Consolidated Balance Sheets since the Partnership expects to refinance these notes on a long-term basis and there is adequate available capacity under the revolving credit facility to extend the amount that would otherwise come due in less than one year.

The indentures governing the notes and debentures have restrictive covenants which provide that, with certain exceptions, neither the Partnership nor any of its subsidiaries may create, assume or suffer to exist any lien upon any property to secure any indebtedness unless the debentures and notes shall be equally and ratably secured. All debt obligations are unsecured. At September 30, 2014, the Partnership and its subsidiaries were in compliance with their debt covenants.

Revolving Credit Facility

Outstanding borrowings under the Partnership’s revolving credit facility as of September 30, 2014, and December 31, 2013, were $185.0 million and $175.0 million, with a weighted-average borrowing rate of 1.53% and 1.29%. As of November 4, 2014, we had outstanding borrowings under our revolving credit facility of $485.0 million, resulting in available borrowing capacity of $515.0 million.

The credit facility contains various restrictive covenants and other usual and customary terms and conditions, including the incurrence of additional debt, the sale of assets and sale-leaseback transactions. The financial covenants under the credit facility require the Partnership and its subsidiaries to maintain, among other things, a ratio of total consolidated debt to consolidated EBITDA (as defined in the Amended Credit Agreement) measured for the previous twelve months of not more than 5.0 to 1.0, or up to 5.5 to 1.0 for the three quarters following an acquisition. The Partnership and its subsidiaries were in compliance with all covenant requirements under the credit facility as of September 30, 2014.

Term Loan

The Partnership has a $225.0 million variable-rate term loan due October 1, 2017 (2017 Term Loan), which bears interest at a rate that is based on the one-month London Interbank Offered Rate (LIBOR) plus an applicable margin. Any amounts repaid under the 2017 Term Loan may not be reborrowed. Outstanding borrowings as of September 30, 2014, and December 31, 2013, were $200.0 million and $225.0 million, with a weighted-average interest rate of 1.90% and 1.92%. No additional borrowing capacity is available under the 2017 Term Loan.

Long-Term Debt - Affiliate

In July 2014, the Partnership entered into a Subordinated Loan Agreement with BPHC under which the Partnership can borrow up to $300.0 million (Subordinated Loan) through December 31, 2015. The Subordinated Loan bears interest at increasing rates, ranging 5.75% to 9.75%, payable semi-annually in June and December, commencing December 2014, and maturing in July 2024. The Subordinated Loan must be prepaid with the net cash proceeds from the issuance of additional equity securities by the Partnership or the incurrence of certain indebtedness by the Partnership or its subsidiaries, although BPHC may waive such prepayment. The Subordinated Loan is subordinated in right of payment to the Partnership’s obligations under its revolving credit facility pursuant to the terms of a Subordination Agreement between BPHC and Wells Fargo, N.A., as representative of the lenders under the revolving credit facility. Through the filing date of this Quarterly Report on Form 10-Q, the Partnership has not borrowed any amounts under the Subordinated Loan.

Common Unit Offering

In May 2013, the Partnership completed a public offering of 12.7 million common units at a price of $30.12 per unit. The Partnership received net proceeds of approximately $376.5 million after deducting underwriting discounts and offering expenses of $12.3 million and including a $7.8 million contribution received from its general partner to maintain its 2% general partner interest. The net proceeds were used to repay borrowings outstanding under the Partnership's credit facility and to create funding for future capital growth projects.

Note 9: Employee Benefits

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

Texas Gas Transmission, LLC (Texas Gas) employees hired prior to November 2006, are covered under a non-contributory, defined benefit pension plan (Pension Plan). The Texas Gas Supplemental Retirement Plan (SRP) provides pension benefits for the portion of an eligible employee’s pension benefit under the Pension Plan that becomes subject to compensation limitations under the Internal Revenue Code. Collectively, the Partnership refers to the Pension Plan and the SRP as Retirement Plans. Texas Gas provides postretirement medical benefits and life insurance to retired employees who were employed full time, hired prior to 1996, and have met certain other requirements.

Components of net periodic benefit cost for both the Retirement Plans and PBOP for the three months ended September 30, 2014 and 2013 were as follows (in millions):



	Retirement Plans						PBOP
	For the Three Months Ended September 30,						For the Three Months Ended September 30,
	2014			2013			2014			2013
Service cost	$	0.9		$	0.8		$	0.1		$	0.1
Interest cost	1.4			1.3			0.5			0.6
Expected return on plan assets	(2.4		)	(2.4		)	(1.1		)	(1.1		)
Amortization of prior service credit	—			—			(1.9		)	(2.0		)
Amortization of unrecognized net loss	0.4			0.6			0.1			—
Settlement charge	—			1.3			—			—
Regulatory asset decrease	0.4			—			—			—
Net periodic benefit cost	$	0.7		$	1.6		$	(2.3	)	$	(2.4	)

Components of net periodic benefit cost for both the Retirement Plans and PBOP for the nine months ended September 30, 2014 and 2013 were as follows (in millions):



	Retirement Plans						PBOP
	For the Nine Months Ended September 30,						For the Nine Months Ended September 30,
	2014			2013			2014			2013
Service cost	$	2.9		$	3.0		$	0.3		$	0.3
Interest cost	4.2			3.7			1.6			1.5
Expected return on plan assets	(7.1		)	(6.9		)	(3.2		)	(3.3		)
Amortization of prior service credit	—			—			(5.8		)	(5.8		)
Amortization of unrecognized net loss	1.0			1.8			0.2			—
Settlement charge	—			1.3			—			—
Regulatory asset decrease	1.3			—			—			—
Net periodic benefit cost	$	2.3		$	2.9		$	(6.9	)	$	(7.3	)

Through the date of this filing, the Partnership has made contributions of $3.0 million to the Pension Plan and does not expect to make additional contributions in 2014.

Defined Contribution Plans

The Partnership’s employees not covered under the Pension Plan are provided retirement benefits under a defined contribution money purchase plan. The Partnership also provides 401(k) plan benefits to its employees. Costs related to the Partnership’s defined contribution plans were $2.2 million for the three months ended September 30, 2014 and 2013, and were $6.6 million for the nine months ended September 30, 2014 and 2013.

Note 10: Related Party Transactions

Loews provides a variety of corporate services to the Partnership under services agreements, including but not limited to, information technology, tax, risk management, internal audit and corporate development services, plus allocated overheads. The Partnership incurred charges related to these services of $2.2 million and $2.1 million for the three months ended September 30, 2014 and 2013 and $6.6 million and $6.3 million for the nine months ended September 30, 2014 and 2013.

Distributions paid related to limited partner units held by BPHC and the 2% general partner interest and IDRs held by Boardwalk GP were $13.0 million and $72.9 million for the three months ended September 30, 2014 and 2013, and $39.0 million and $217.6 million for the nine months ended September 30, 2014 and 2013.

In the third quarter 2014, the Partnership and BPHC entered into a Subordinated Loan agreement whereby the Partnership can borrow up to $300.0 million. Note 8 contains more information related to affiliated long-term debt.

In 2013, the Partnership entered into agreements with BPHC to form Boardwalk Bluegrass and Boardwalk Moss Lake. Through September 30, 2014 and December 31, 2013, the Partnership contributed $12.7 million and $11.9 million and BPHC contributed $97.8 million and $90.0 million of cash and other assets to these entities. In 2014, the Partnership received a $1.9 million distribution from Boardwalk Moss Lake and BPHC received a $7.1 million distribution.

Note 11: Subsequent Event

Acquisition of the Evangeline Pipeline System

On October 8, 2014, the Partnership completed the acquisition of Chevron Petrochemical Pipeline, LLC, which owns the Evangeline ethylene pipeline system, from Chevron Pipe Line Company (Chevron), for $295.0 million in cash, subject to customary adjustments. The purchase price was funded through borrowings under the revolving credit facility. As of September 30, 2014, the Partnership had paid a $29.5 million deposit under the definitive agreement with Chevron and is recorded in Other Noncurrent Assets in its Condensed Consolidated Balance Sheet. The disclosures related to the pro-forma revenue and earnings information for the historical comparable period were not provided because the purchase price allocation, which determines the initial accounting, is not complete.

Note 12: Recently Issued Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09 (ASU 2014-09), Revenue from Contracts with Customers (Topic 606), which will require entities to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. ASU 2014-09 also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenues and cash flows from contracts with customers. ASU 2014-09 is effective for interim and annual reporting periods beginning after December 15, 2016. The Partnership is evaluating the impact, if any, that ASU 2014-09 will have on its financial statements.

Note 13: Supplemental Disclosure of Cash Flow Information (in millions):



	For the Nine Months Ended September 30,
	2014		2013
Cash paid during the period for:
Interest (net of amount capitalized)	$	127.6	$	126.9
Non-cash adjustments:
Capital lease obligations incurred	—		10.5

Note 14: Guarantee of Securities of Subsidiaries

Boardwalk Pipelines (subsidiary issuer) has issued securities which have been fully and unconditionally guaranteed by the Partnership (parent guarantor). The Partnership's subsidiaries have no significant restrictions on their ability to pay distributions or make loans to the Partnership except as noted in the debt covenants and have no restricted assets at September 30, 2014, and December 31, 2013. Note 8 contains additional information regarding the Partnership's debt and related covenants.

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

Condensed Consolidating Balance Sheets as of September 30, 2014

(Millions)



Assets	Parent Guarantor		Subsidiary Issuer		Non-guarantor Subsidiaries		Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Cash and cash equivalents	$	—	$	0.7	$	5.5	$	—		$	6.2
Receivables	—		—		94.7		(0.1		)	94.6
Receivables - affiliate	—		—		6.8		(6.8		)	—
Gas and liquids stored underground	—		—		4.5		—			4.5
Prepayments	0.4		—		17.4		—			17.8
Advances to affiliates	—		2.4		42.1		(44.5		)	—
Other current assets	—		—		22.9		(7.5		)	15.4
Total current assets	0.4		3.1		193.9		(58.9		)	138.5
Investment in consolidated subsidiaries	1,679.8		6,423.1		—		(8,102.9		)	—
Property, plant and equipment, gross	0.6		—		9,023.1		—			9,023.7
Less–accumulated depreciation and amortization	0.6		—		1,691.8		—			1,692.4
Property, plant and equipment, net	—		—		7,331.3		—			7,331.3
Other noncurrent assets	—		3.0		458.5		(0.1		)	461.4
Advances to affiliates – noncurrent	2,431.4		201.2		1,082.4		(3,715.0		)	—
Total other assets	2,431.4		204.2		1,540.9		(3,715.1		)	461.4

Total Assets	$	4,111.6	$	6,630.4	$	9,066.1	$	(11,876.9	)	$	7,931.2



Liabilities and Equity	Parent Guarantor		Subsidiary Issuer		Non-guarantor Subsidiaries		Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Payables	$	—	$	0.1	$	65.4	$	0.1		$	65.6
Payable to affiliates	0.8		—		6.8		(6.8		)	0.8
Advances from affiliates	—		42.1		2.4		(44.5		)	—
Other current liabilities	—		14.0		166.7		(7.8		)	172.9
Total current liabilities	0.8		56.2		241.3		(59.0		)	239.3
Total long-term debt and capital lease obligation	—		1,380.6		2,030.0		—			3,410.6
Payable to affiliate - noncurrent	16.0		—		—		—			16.0
Advances from affiliates - noncurrent	—		3,513.8		201.2		(3,715.0		)	—
Other noncurrent liabilities	—		—		170.2		—			170.2
Total other liabilities and deferred credits	16.0		3,513.8		371.4		(3,715.0		)	186.2
Total partners' capital	4,094.8		1,679.8		6,423.1		(8,102.9		)	4,094.8
Noncontrolling interest	—		—		0.3		—			0.3
Total Equity	4,094.8		1,679.8		6,423.4		(8,102.9		)	4,095.1
Total Liabilities and Equity	$	4,111.6	$	6,630.4	$	9,066.1	$	(11,876.9	)	$	7,931.2

Condensed Consolidating Balance Sheets as of December 31, 2013

(Millions)



Assets	Parent Guarantor		Subsidiary Issuer		Non-guarantor Subsidiaries		Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Cash and cash equivalents	$	0.2	$	9.2	$	19.1	$	—		$	28.5
Receivables	—		—		119.2		—			119.2
Receivables - affiliate	0.1		0.1		14.3		(13.4		)	1.1
Gas and liquids stored underground	—		—		0.7		—			0.7
Prepayments	0.3		—		12.6		—			12.9
Advances to affiliates	—		—		194.4		(194.4		)	—
Other current assets	—		—		23.8		(9.1		)	14.7
Total current assets	0.6		9.3		384.1		(216.9		)	177.1
Investment in consolidated subsidiaries	1,480.8		6,138.3		—		(7,619.1		)	—
Property, plant and equipment, gross	0.6		—		8,722.7		—			8,723.3
Less–accumulated depreciation and amortization	0.6		—		1,488.6		—			1,489.2
Property, plant and equipment, net	—		—		7,234.1		—			7,234.1
Other noncurrent assets	0.3		3.7		420.7		—			424.7
Advances to affiliates – noncurrent	2,512.1		168.7		733.1		(3,413.9		)	—
Investment in unconsolidated affiliates	—		—		78.6		—			78.6
Total other assets	2,512.4		172.4		1,232.4		(3,413.9		)	503.3

Total Assets	$	3,993.8	$	6,320.0	$	8,850.6	$	(11,249.9	)	$	7,914.5



Liabilities & Equity	Parent Guarantor		Subsidiary Issuer		Non-guarantor Subsidiaries		Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Payables	$	0.2	$	—	$	70.6	$	—		$	70.8
Payable to affiliates	0.7		—		13.9		(13.4		)	1.2
Advances from affiliates	—		194.4		—		(194.4		)	—
Other current liabilities	—		19.7		153.3		(9.0		)	164.0
Total current liabilities	0.9		214.1		237.8		(216.8		)	236.0
Total long-term debt and capital lease obligation	—		1,379.9		2,044.5		—			3,424.4
Payable to affiliate - noncurrent	16.0		—		—		—			16.0
Advances from affiliates - noncurrent	—		3,245.2		168.7		(3,413.9		)	—
Other noncurrent liabilities	—		—		174.8		(0.1		)	174.7
Total other liabilities and deferred credits	16.0		3,245.2		343.5		(3,414.0		)	190.7
Total partners' capital	3,976.9		1,480.8		6,138.3		(7,619.1		)	3,976.9
Noncontrolling interest	—		—		86.5		—			86.5
Total Equity	3,976.9		1,480.8		6,224.8		(7,619.1		)	4,063.4
Total Liabilities and Equity	$	3,993.8	$	6,320.0	$	8,850.6	$	(11,249.9	)	$	7,914.5

Condensed Consolidating Statements of Income for the Three Months Ended September 30, 2014

(Millions)



	Parent Guarantor			Subsidiary Issuer			Non-guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Operating Revenues:
Transportation	$	—		$	—		$	261.3		$	(22.4	)	$	238.9
Parking and lending	—			—			3.0			—			3.0
Storage	—			—			19.6			(0.4		)	19.2
Other	—			—			17.8			—			17.8
Total operating revenues	—			—			301.7			(22.8		)	278.9

Operating Cost and Expenses:
Fuel and transportation	—			—			54.7			(22.8		)	31.9
Operation and maintenance	—			—			50.3			—			50.3
Administrative and general	0.2			—			31.6			—			31.8
Other operating costs and expenses	0.2			—			96.2			—			96.4
Total operating costs and expenses	0.4			—			232.8			(22.8		)	210.4
Operating (loss) income	(0.4		)	—			68.9			—			68.5

Other Deductions (Income):
Interest expense	—			18.7			21.3			—			40.0
Interest (income) expense - affiliates, net	(7.8		)	10.6			(2.8		)	—			—
Interest income	—			—			(0.1		)	—			(0.1		)
Equity in earnings of subsidiaries	(21.8		)	(51.1		)	—			72.9			—
Equity losses in unconsolidated affiliates	—			—			0.3			—			0.3
Miscellaneous other income, net	—			—			(0.2		)	—			(0.2		)
Total other (income) deductions	(29.6		)	(21.8		)	18.5			72.9			40.0

Income (loss) before income taxes	29.2			21.8			50.4			(72.9		)	28.5
Income taxes	—			—			0.1			—			0.1
Net income (loss)	29.2			21.8			50.3			(72.9		)	28.4
Net loss attributable to noncontrolling interests	—			—			(0.8		)	—			(0.8		)
Net income (loss) attributable to controlling interests	$	29.2		$	21.8		$	51.1		$	(72.9	)	$	29.2

Condensed Consolidating Statements of Income for the Three Months Ended September 30, 2013

(Millions)



	Parent Guarantor			Subsidiary Issuer			Non-guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Operating Revenues:
Transportation	$	—		$	—		$	255.8		$	(22.3	)	$	233.5
Parking and lending	—			—			4.9			—			4.9
Storage	—			—			27.4			—			27.4
Other	—			—			9.7			—			9.7
Total operating revenues	—			—			297.8			(22.3		)	275.5

Operating Cost and Expenses:
Fuel and transportation	—			—			40.8			(22.3		)	18.5
Operation and maintenance	—			—			47.0			—			47.0
Administrative and general	—			—			29.1			—			29.1
Other operating costs and expenses	0.2			—			77.5			—			77.7
Total operating costs and expenses	0.2			—			194.4			(22.3		)	172.3
Operating (loss) income	(0.2		)	—			103.4			—			103.2

Other Deductions (Income):
Interest expense	—			18.7			22.3			—			41.0
Interest (income) expense - affiliates net	(8.8		)	10.4			(1.6		)	—			—
Interest income	—			—			(0.1		)	—			(0.1		)
Equity in earnings of subsidiaries	(53.7		)	(82.8		)	—			136.5			—
Equity losses in unconsolidated affiliates	—			—			0.6			—			0.6
Total other (income) deductions	(62.5		)	(53.7		)	21.2			136.5			41.5

Income (loss) before income taxes	62.3			53.7			82.2			(136.5		)	61.7
Income taxes	—			—			—			—			—
Net income (loss)	62.3			53.7			82.2			(136.5		)	61.7
Net loss attributable to noncontrolling interests	—			—			(0.6		)	—			(0.6		)
Net income (loss) attributable to controlling interests	$	62.3		$	53.7		$	82.8		$	(136.5	)	$	62.3

Condensed Consolidating Statements of Income for the Nine Months Ended September 30, 2014

(Millions)



	Parent Guarantor			Subsidiary Issuer			Non-guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Operating Revenues:
Transportation	$	—		$	—		$	856.9		$	(68.0	)	$	788.9
Parking and lending	—			—			21.4			—			21.4
Storage	—			—			70.6			(0.5		)	70.1
Other	—			—			48.8			—			48.8
Total operating revenues	—			—			997.7			(68.5		)	929.2

Operating Cost and Expenses:
Fuel and transportation	—			—			163.3			(68.5		)	94.8
Operation and maintenance	—			—			136.9			—			136.9
Administrative and general	0.1			—			89.0			—			89.1
Other operating costs and expenses	0.3			—			290.5			—			290.8
Total operating costs and expenses	0.4			—			679.7			(68.5		)	611.6
Operating (loss) income	(0.4		)	—			318.0			—			317.6

Other Deductions (Income):
Interest expense	—			56.1			65.0			—			121.1
Interest (income) expense - affiliates, net	(23.2		)	31.0			(7.8		)	—			—
Interest income	—			—			(0.4		)	—			(0.4		)
Equity in earnings of subsidiaries	(174.0		)	(261.1		)	—			435.1			—
Equity losses in unconsolidated affiliates	—			—			86.9			—			86.9
Miscellaneous other income, net	—			—			(0.3		)	—			(0.3		)
Total other (income) deductions	(197.2		)	(174.0		)	143.4			435.1			207.3

Income (loss) before income taxes	196.8			174.0			174.6			(435.1		)	110.3
Income taxes	—			—			0.4			—			0.4
Net income (loss)	196.8			174.0			174.2			(435.1		)	109.9
Net loss attributable to noncontrolling interests	—			—			(86.9		)	—			(86.9		)
Net income (loss) attributable to controlling interests	$	196.8		$	174.0		$	261.1		$	(435.1	)	$	196.8

Condensed Consolidating Statements of Income for the Nine Months Ended September 30, 2013

(Millions)



	Parent Guarantor			Subsidiary Issuer			Non-guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Operating Revenues:
Transportation	$	—		$	—		$	826.2		$	(66.3	)	$	759.9
Parking and lending	—			—			19.9			—			19.9
Storage	—			—			83.0			(0.1		)	82.9
Other	—			—			30.0			—			30.0
Total operating revenues	—			—			959.1			(66.4		)	892.7

Operating Cost and Expenses:
Fuel and transportation	—			—			135.0			(66.4		)	68.6
Operation and maintenance	—			0.3			130.7			—			131.0
Administrative and general	—			0.8			88.6			—			89.4
Other operating costs and expenses	0.3			0.1			247.3			—			247.7
Total operating costs and expenses	0.3			1.2			601.6			(66.4		)	536.7
Operating (loss) income	(0.3		)	(1.2		)	357.5			—			356.0

Other Deductions (Income):
Interest expense	—			53.9			68.3			—			122.2
Interest (income) expense - affiliates net	(25.4		)	30.9			(5.5		)	—			—
Interest income	—			—			(0.4		)	—			(0.4		)
Equity in earnings of subsidiaries	(209.1		)	(295.1		)	—			504.2			—
Equity losses in unconsolidated affiliates	—			—			0.6			—			0.6
Miscellaneous other income, net	—			—			(0.2		)	—			(0.2		)
Total other (income) deductions	(234.5		)	(210.3		)	62.8			504.2			122.2

Income (loss) before income taxes	234.2			209.1			294.7			(504.2		)	233.8
Income taxes	—			—			0.3			—			0.3
Net income (loss)	234.2			209.1			294.4			(504.2		)	233.5
Net loss attributable to noncontrolling interests	—			—			(0.7		)	—			(0.7		)
Net income (loss) attributable to controlling interests	$	234.2		$	209.1		$	295.1		$	(504.2	)	$	234.2

Condensed Consolidating Statements of Comprehensive Income for the Three Months Ended September 30, 2014

(Millions)



	Parent Guarantor			Subsidiary Issuer			Non-guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Net income (loss)	$	29.2		$	21.8		$	50.3		$	(72.9	)	$	28.4
Other comprehensive income (loss):
Gain (loss) on cash flow hedges	0.2			0.2			0.2			(0.4		)	0.2
Reclassification adjustment transferred to Net Income from cash flow hedges	0.5			0.5			0.1			(0.6		)	0.5
Pension and other postretirement benefit costs	(2.0		)	(2.0		)	(2.0		)	4.0			(2.0		)
Total Comprehensive Income (Loss)	27.9			20.5			48.6			(69.9		)	27.1
Comprehensive loss attributable to noncontrolling interests	—			—			(0.8		)	—			(0.8		)
Comprehensive income (loss) attributable to controlling interests	$	27.9		$	20.5		$	49.4		$	(69.9	)	$	27.9

Condensed Consolidating Statements of Comprehensive Income for the Three Months Ended September 30, 2013

(Millions)



	Parent Guarantor			Subsidiary Issuer			Non-guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Net income (loss)	$	62.3		$	53.7		$	82.2		$	(136.5	)	$	61.7
Other comprehensive income (loss):
Reclassification adjustment transferred to Net Income from cash flow hedges	(0.6		)	(0.6		)	(1.0		)	1.6			(0.6		)
Pension and other postretirement benefit costs	(0.4		)	(0.4		)	(0.4		)	0.8			(0.4		)
Total Comprehensive Income (Loss)	61.3			52.7			80.8			(134.1		)	60.7
Comprehensive loss attributable to noncontrolling interests	—			—			(0.6		)	—			(0.6		)
Comprehensive income (loss) attributable to controlling interests	$	61.3		$	52.7		$	81.4		$	(134.1	)	$	61.3

Condensed Consolidating Statements of Comprehensive Income for the Nine Months Ended September 30, 2014

(Millions)



	Parent Guarantor			Subsidiary Issuer			Non-guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Net income (loss)	$	196.8		$	174.0		$	174.2		$	(435.1	)	$	109.9
Other comprehensive income (loss):
(Loss) gain on cash flow hedges	(0.7		)	(0.7		)	(0.7		)	1.4			(0.7		)
Reclassification adjustment transferred to Net Income from cash flow hedges	2.1			2.1			0.8			(2.9		)	2.1
Pension and other postretirement benefit costs	(5.9		)	(5.9		)	(5.9		)	11.8			(5.9		)
Total Comprehensive Income (Loss)	192.3			169.5			168.4			(424.8		)	105.4
Comprehensive loss attributable to noncontrolling interests	—			—			(86.9		)	—			(86.9		)
Comprehensive income (loss) attributable to controlling interests	$	192.3		$	169.5		$	255.3		$	(424.8	)	$	192.3

Condensed Consolidating Statements of Comprehensive Income for the Nine Months Ended September 30, 2013

(Millions)



	Parent Guarantor			Subsidiary Issuer			Non-guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Net income (loss)	$	234.2		$	209.1		$	294.4		$	(504.2	)	$	233.5
Other comprehensive income (loss):
Gain (loss) on cash flow hedges	2.5			2.5			2.5			(5.0		)	2.5
Reclassification adjustment transferred to Net Income from cash flow hedges	0.5			0.5			(0.8		)	0.3			0.5
Pension and other postretirement benefit costs	(4.0		)	(4.0		)	(4.0		)	8.0			(4.0		)
Total Comprehensive Income (Loss)	233.2			208.1			292.1			(500.9		)	232.5
Comprehensive loss attributable to noncontrolling interests	—			—			(0.7		)	—			(0.7		)
Comprehensive income (loss) attributable to controlling interests	$	233.2		$	208.1		$	292.8		$	(500.9	)	$	233.2

Condensed Consolidating Statements of Cash Flow for the Nine Months Ended September 30, 2014

(Millions)



	Parent Guarantor			Subsidiary Issuer			Non-guarantor Subsidiaries			Eliminations				Consolidated Boardwalk Pipeline Partners, LP
Net cash provided by (used in) operating activities	$	22.8		$	(89.9	)	$	479.6		$	—			$	412.5

INVESTING ACTIVITIES:
Capital expenditures	—			—			(315.9		)	—				(315.9		)
Proceeds from sale of operating assets	—			—			2.9			—				2.9
Proceeds from insurance and other recoveries	—			—			6.3			—				6.3
Advances to affiliates, net	80.8			(34.9		)	(197.0		)	151.2				0.1
Investment in unconsolidated affiliates	—			—			(20.5		)	—				(20.5		)
Distribution from unconsolidated affiliates	—			—			10.7			—				10.7
Acquisition-related deposit	(29.5		)	—			—			—				(29.5		)
Net cash provided by (used in) investing activities	51.3			(34.9		)	(513.5		)	151.2				(345.9		)

FINANCING ACTIVITIES:
Proceeds from borrowings on revolving credit agreement	—			—			340.0			—				340.0
Repayment of borrowings on revolving credit agreement	—			—			(330.0		)	—				(330.0		)
Principal payment of capital lease obligation	—			—			(0.3		)	—				(0.3		)
Repayment of borrowings from term loan	—			—			(25.0		)	—				(25.0		)
Advances from affiliates, net	0.1			116.3			34.9			(151.2		)		0.1
Distributions paid	(74.4		)	—			—			—				(74.4		)
Capital contributions from noncontrolling interests	—			—			8.2			—			—	8.2
Distributions paid to noncontrolling interests	—			—			(7.5		)	—				(7.5		)
Net cash (used in) provided by financing activities	(74.3		)	116.3			20.3			(151.2		)		(88.9		)

Decrease in cash and cash equivalents	(0.2		)	(8.5		)	(13.6		)	—				(22.3		)
Cash and cash equivalents at beginning of period	0.2			9.2			19.1			—				28.5
Cash and cash equivalents at end of period	$	—		$	0.7		$	5.5		$	—			$	6.2

Condensed Consolidating Statements of Cash Flow for the Nine Months Ended September 30, 2013

(Millions)



	Parent Guarantor			Subsidiary Issuer			Non-guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Net cash provided by (used in) operating activities	$	26.0		$	(86.3	)	$	462.3		$	—		$	402.0

INVESTING ACTIVITIES:
Capital expenditures	—			—			(204.3		)	—			(204.3		)
Proceeds from sale of operating assets	—			—			48.6			—			48.6
Proceeds from insurance and other recoveries	—			—			1.4			—			1.4
Advances to affiliates, net	(7.6		)	(71.0		)	(168.7		)	244.5			(2.8		)
Investment in consolidated subsidiary	—			(15.1		)	—			15.1			—
Investment in unconsolidated affiliates	—			—			(25.6		)	—			(25.6		)
Net cash (used in) provided by investing activities	(7.6		)	(86.1		)	(348.6		)	259.6			(182.7		)

FINANCING ACTIVITIES:
Proceeds from borrowings on revolving credit agreement	—			—			813.0			—			813.0
Repayment of borrowings on revolving credit agreement	—			—			(1,030.0		)	—			(1,030.0		)
Contribution from parent	—			—			15.1			(15.1		)	—
Principal payment of capital lease obligation	—			—			(0.1		)	—			(0.1		)
Advances from affiliates, net	(2.8		)	173.5			71.0			(244.5		)	(2.8		)
Distributions paid	(392.0		)	—			—			—			(392.0		)
Capital contribution from noncontrolling interests	—			—			37.2			—			37.2
Proceeds from sale of common units	368.7			—			—			—			368.7
Capital contributions from general partner	7.8			—			—			—			7.8
Net cash (used in) provided by financing activities	(18.3		)	173.5			(93.8		)	(259.6		)	(198.2		)

Increase in cash and cash equivalents	0.1			1.1			19.9			—			21.1
Cash and cash equivalents at beginning of period	0.1			1.0			2.8			—			3.9
Cash and cash equivalents at end of period	$	0.2		$	2.1		$	22.7		$	—		$	25.0

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, 2013 (2013 Annual Report on Form 10-K).

Overview

Our transportation services consist of firm natural gas transportation, whereby the customer pays a capacity reservation charge to reserve pipeline capacity at receipt and delivery points along our pipeline systems, plus a commodity and fuel charge on the volume of natural gas actually transported, and interruptible natural gas transportation, whereby the customer pays to transport gas only when capacity is available and used. We offer firm natural gas 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. We also transport and store natural gas liquids (NGLs). Our NGLs contracts are generally fee-based and are dependent on actual volumes transported or stored, although in some cases minimum volume requirements apply. Our NGLs storage rates are market-based and contracts are typically fixed-price arrangements with escalation clauses. We are not in the business of buying and selling natural gas other than for system management purposes, but changes in the level of natural gas prices may impact the volumes of gas transported and stored on our pipeline systems. Our operating costs and expenses typically do not vary significantly based upon the amount of products transported, with the exception of fuel consumed at our compressor stations, which is included in Fuel and transportation expenses on our Condensed Consolidated Statements of Income.

Recent Developments

Market Conditions and Contract Renewals

Transportation rates we are able to charge customers are heavily influenced by longer-term trends in, for example, the amount and geographical location of natural gas production and demand for gas by end-users such as power plants, petrochemical facilities and liquefied natural gas (LNG) export facilities. As a result of changes in longer-term trends such as the development of gas production from the Marcellus and Utica areas located in the Northeastern United States and changes to related pipeline infrastructure, basis differentials corresponding to traditional flow patterns on our pipeline systems (generally south to north and west to east) have narrowed significantly in recent years, reducing the transportation rates and adversely impacting other contract terms we can negotiate with our customers for available transportation capacity and for contracts due for renewal for our transportation services. These conditions have and we expect will continue to materially adversely affect our revenues, earnings before interest, taxes, depreciation and amortization (EBITDA) and distributable cash flows.

A substantial portion of our transportation capacity is contracted for under firm transportation agreements. The following table sets forth the approximate projected revenues from capacity reservation and minimum bill charges under committed firm transportation agreements in place as of September 30, 2014, for each of the full years from 2014 to 2016 (in millions). A portion of the revenues reflected in the table below are anticipated under executed precedent transportation agreements for projects that are subject to customer board approval and/or regulatory approval to commence construction, as follows: 2015 - $4.0 million and 2016 - $30.0 million. The table does not include additional revenues we have recognized and we may receive under firm transportation agreements based on actual utilization of the contracted pipeline facilities or any expected revenues for periods after the expiration dates of the existing agreements.



As of September 30, 2014
2014	⁽¹⁾	$	875.0
2015		875.0
2016		825.0


(1)	The 2014 period includes actual revenues recognized for reservation and minimum bill charges of $645.0 million for the nine months ended September 30, 2014 and $230.0 million of expected revenues for the three months ending December 31, 2014.

Each year a portion of our firm transportation agreements expire and need to be renewed or replaced. Due to the factors noted above and discussed further in our 2013 Annual Report on Form 10-K, in recent periods we have generally seen the renewal of expiring transportation contracts at lower rates and for shorter terms than in the past which has materially adversely impacted our firm and interruptible transportation revenues. Capacity not renewed and available for sale on a short-term basis has been and continues to be sold at rates reflective of basis spreads, which generally have been lower than historical rates, under short-term firm or interruptible contracts, or in some cases not sold at all. Rates for short-term and interruptible transportation services are influenced by the factors discussed above but can be more heavily affected by shorter-term conditions such as current and forecasted weather. For a discussion of additional risks associated with our revenues, please see Item 1A. Risk Factors in our 2013 Annual Report on Form 10-K - We may not be able to replace expiring gas transportation and storage contracts at attractive rates or on a long-term basis and may not be able to sell short-term services at attractive rates or at all due to narrower basis differentials which adversely affect the value of our transportation services and narrowing of price spreads between time periods and reduced volatility which adversely affect our storage services.

We are beginning to experience an increase in demand to transport gas from north to south instead of south to north as we have traditionally experienced. This demand is being driven by increases in gas production from primarily the Marcellus and Utica areas and growing demand for natural gas primarily in the Gulf Coast area from new and planned power plants, petrochemical facilities and LNG export facilities. This new flow pattern is resulting in growth projects for us that require significant capital expenditures, among other things, to make parts of our system bi-directional, and in many instances, will utilize pipeline capacity that has been turned back to us by customers that have not renewed expiring contracts. As discussed under Growth Projects, these projects have lengthy planning and construction periods and as a result will not contribute to our earnings and cash flows until they are placed into service over the next several years. In some instances the projects remain subject to customer, board or regulatory approval to commence construction, and these projects are subject to the risk that they may not be completed, may be impacted by significant cost overruns or may be materially changed prior to completion as a result of future developments or circumstances that we are not aware of at this time.

The value of our storage and PAL services (comprised of parking gas for customers and/or lending gas to customers) is affected by natural gas price differentials between time periods, such as winter to summer (time period price spreads), the price volatility of natural gas and other factors. Our storage and parking services have greater value when the natural gas futures market is in contango (a positive time period price spread), while our lending service has greater value when the futures market is backwardated (a negative time period price spread, meaning that gas prices are projected to be higher in the near-term than in the future). We have seen the value of our storage and PAL services adversely impacted by some of the market factors discussed above which have contributed to a narrowing of time period price spreads. The narrowing of spreads has reduced the rates we can charge and the capacity we can sell under our storage and PAL services. Although during the first half 2014, the futures market was significantly backwardated partly reflecting the harsh weather conditions in late 2013 and early 2014, and we earned revenues from lending gas to customers under our PAL services, the favorable price spreads have since lessened. Storage market fundamentals can be volatile in a relative short period of time. Based on the current narrowing of time period price spreads and fewer market participants we are currently experiencing weakened demand for our storage and PAL services.

Acquisition of the Evangeline Pipeline System

On October 8, 2014, we acquired Chevron Petrochemical Pipeline, LLC, which owns the Evangeline ethylene pipeline system (Evangeline) for $295.0 million in cash, subject to customary adjustments. The purchase price was funded through borrowings under the revolving credit facility. The Evangeline system is a 176-mile interstate pipeline capable of transporting approximately 2.6 billion pounds of ethylene per year between Port Neches, Texas, and Baton Rouge, Louisiana, and is supported by long-term, fee-based contracts.

Gulf South Rate Case

In October 2014, Gulf South filed a rate case (RP15-65) with the Federal Energy Regulatory Commission (FERC), in which Gulf South is requesting a change in its tariff rates among other things. The new tariff rates are expected to become effective May 1, 2015, subject to refund. Since the rate case is in the initial stages, the ultimate outcome and impacts on our EBITDA and distributable cash flow for 2015 and beyond cannot be predicted at this time.

Bluegrass Pipeline

As discussed in our 2013 Annual Report on Form 10-K, we and Boardwalk Pipelines Holding Corp. (BPHC) are parties to joint ventures with The Williams Companies, Inc. (Williams) in the development process for the Bluegrass Project. In the third quarter 2014, we and Williams agreed to dissolve the Bluegrass Project entities, including the dissolution of Bluegrass Pipeline,

Moss Lake Fractionation and Moss Lake LPG. In the first quarter 2014, the Bluegrass entities expensed the previously capitalized project costs that had been incurred related to the development process due to lack of customer commitments, resulting in a decrease to our net income attributable to controlling interests by $10.0 million.

Growth Projects

We are currently engaged in several growth projects, which are discussed below. The financing of the expenditures to be made in 2014 is discussed in Liquidity and Capital Resources. We expect the estimated total costs of these projects to be approximately as follows (in millions):



	Estimated Total Cost		Cash Invested Through September 30, 2014
Southeast Market Expansion	$	300.0	$	241.6
Sulphur Storage and Pipeline Expansion	145.0		2.3
Ohio to Louisiana Access	115.0		2.4
Southern Indiana Market Lateral	95.0		0.8
Western Kentucky Market Lateral	80.0		1.1
Northern Supply Access	250.0		—
Coastal Bend Header	720.0		0.3
Total	$	1,705.0	$	248.5

Southeast Market Expansion: Our Southeast Market Expansion project was placed in service in October 2014. The project consists of a new interconnection between our Gulf South and Petal pipelines, adding additional compression facilities and approximately 70 miles of new 24-inch and 30-inch pipeline in southeastern Mississippi. The project has added approximately 0.5 Bcf per day of peak-day transmission capacity to our Gulf South system from multiple locations in Texas and Louisiana to Mississippi, Alabama and Florida and is fully contracted with a weighted-average contract life of approximately 10 years.

Sulphur Storage and Pipeline Expansion Project: In 2014, we executed a long-term agreement to provide transportation and storage services to support the development of a new ethane cracker plant in the Lake Charles, Louisiana area. The project would involve significant storage and infrastructure development to serve petrochemical customers near our Sulphur Hub. The project has an anticipated in-service date in the second half 2017.

Ohio to Louisiana Access Project: Our Ohio to Louisiana Access Project would provide long-term-firm natural gas transportation primarily from the Marcellus and Utica production areas to Louisiana. This project does not add additional capacity to our natural gas pipeline systems, but will require us to make a portion of our Texas Gas Transmission, LLC (Texas Gas) system bi-directional. The project is supported by firm transportation contracts with producers and end-users, of which a portion of the capacity will deliver into our Southern Indiana Market Lateral project, with a weighted-average contract life of approximately 13 years. The project is expected to be placed into service in the first half 2016, subject to FERC approval.

Southern Indiana Market Lateral Project: Our Southern Indiana Market Lateral project would consist of the construction of approximately 30 miles of 20 inch pipeline originating from our pipeline in Mt. Vernon, Indiana to Henderson County, Kentucky. The project will add approximately 0.2 Bcf per day of peak-day transmission capacity to our Texas Gas system and is supported by firm transportation contracts with a weighted-average contract life of 20 years. This project, which is subject to FERC and the customer's final board approvals, is expected to be placed into service in the second half 2016.

Western Kentucky Market Lateral Project: Our Western Kentucky Market Lateral project consists of the construction of a pipeline lateral to provide deliveries to a proposed new power plant in Western Kentucky. The pipeline lateral will originate at our compressor station in Muhlenberg County, Kentucky, and extend eastward approximately 19 miles to the proposed plant site. The project will add approximately 0.2 Bcf per day of peak-day transmission capacity to our Texas Gas system and is supported by firm transportation contracts with a weighted-average contract life of 20 years. This project, which is subject to FERC approval, is expected to be placed into service in the second half 2016.

Northern Supply Access Project: Our Northern Supply Access project will increase the peak-day transmission capacity on our Texas Gas system by the addition of compression facilities and other system modifications to make this portion of the system bi-directional. This project is supported by precedent agreements for 0.3 Bcf per day of peak-day transmission capacity

with a weighted-average contract life of approximately 16 years. This project, which is subject to FERC approval, is expected to be placed into service in 2017.

Coastal Bend Header Project: In the third quarter 2014, we executed precedent agreements with foundation shippers to transport approximately 1.4 Bcf per day of natural gas to serve a planned liquefaction terminal in Freeport, Texas. The project will consist of an approximately 65-mile pipeline supply header to serve the terminal as well as expansion and modifications to our existing Gulf South pipeline facilities that will provide access to additional supply sources. This project, which is subject to FERC and customer final board approvals, is expected to be placed into service in 2018.

Results of Operations for the Three Months Ended September 30, 2014 and 2013

Our net income attributable to controlling interests for the three months ended September 30, 2014, decreased $33.1 million, or 53%, to $29.2 million compared to $62.3 million for the three months ended September 30, 2013, due to the factors discussed below.

Operating revenues for the three months ended September 30, 2014, increased $3.4 million, or 1%, to $278.9 million, compared to $275.5 million for the three months ended September 30, 2013. The increase was primarily due to higher transportation revenues of $5.4 million from higher NGL transportation volumes and fuel, and revenues of $10.2 million from gas sales associated with our Flag City processing plant, which were offset by gas purchases recorded in Fuel and transportation expense. These increases were offset by lower storage and PAL revenues of $10.1 million as a result of the effects of unfavorable market conditions on time period price spreads, discussed above in Market Conditions and Contract Renewals.

Operating costs and expenses for the three months ended September 30, 2014, increased $38.1 million, or 22%, to $210.4 million, compared to $172.3 million for the three months ended September 30, 2013. The increase in operating expenses was driven by an increase of $13.4 million in Fuel and transportation expenses driven by gas purchases for the Flag City processing plant which were offset in revenues, increases in our operations and maintenance and administrative and general expenses of $6.0 million from increased maintenance project spending, outside services and employee-related costs, a $3.5 million increase in depreciation expense primarily due to a higher depreciable asset base and $2.1 million related to the timing of final property tax assessments for 2014. The 2013 period was favorably impacted by a $12.5 million gain from the sale of storage gas.

Total other deductions for the three months ended September 30, 2014, decreased by $1.5 million to $40.0 million from $41.5 million for the 2013 period primarily due to an increase in capitalized interest as a result of increased capital project spending.

Results of Operations for the Nine Months Ended September 30, 2014 and 2013

Our net income attributable to controlling interests for the nine months ended September 30, 2014, decreased $37.4 million, or 16%, to $196.8 million compared to $234.2 million for the nine months ended September 30, 2013. Although revenues were higher in the 2014 period as compared to the 2013 period due to extremely cold winter weather in our market areas, net income decreased overall primarily as a result of a $29.5 million gain from the sale of storage gas which impacted the 2013 period and a $10.0 million charge recognized in the 2014 period for previously capitalized costs associated with the Bluegrass Project.

Operating revenues for the nine months ended September 30, 2014, increased $36.5 million, or 4%, to $929.2 million, compared to $892.7 million for the nine months ended September 30, 2013. The increase was primarily due to a $25.8 million increase in transportation and other revenues generally due to the colder than normal winter weather in our market areas and growth projects which were recently placed into service, partly offset by lower firm transportation revenues due to the effects of the market and contract renewal conditions which are discussed above in Market Conditions and Contract Renewals. Additionally, revenues increased $12.6 million from fuel retained due to higher natural gas prices and an additional $17.3 million from gas sales associated with our Flag City processing plant, which were offset by gas purchases recorded in Fuel and transportation expense. Storage revenues were lower by $17.6 million as a result of the effects of unfavorable market conditions on time period price spreads.

Operating costs and expenses for the nine months ended September 30, 2014, increased $74.9 million, or 14%, to $611.6 million, compared to $536.7 million for the nine months ended September 30, 2013. The increase in operating expenses was driven by an increase of $26.2 million in Fuel and transportation expenses mainly driven by gas purchases for the Flag City processing plant which were offset in revenues and higher natural gas prices, a $7.1 million impairment charge associated with the Bluegrass Project, and an $8.2 million increase in depreciation expense primarily due to an increase in our asset base. The 2013 period was favorably impacted by a $29.5 million gain on the sale of storage gas.

Total other deductions for the nine months ended September 30, 2014 increased by $85.1 million, or 70%, to $207.3 million compared to $122.2 million for the 2013 period. The increase was driven by equity losses in unconsolidated affiliates of $86.9 million resulting from previously capitalized costs associated with the Bluegrass Project that were expensed in the first quarter 2014, which losses were mostly offset by noncontrolling interests related to that project.

Liquidity and Capital Resources

We are a partnership holding company and derive all of our operating cash flow from our operating subsidiaries. Our principal sources of liquidity include cash generated from operating activities, our revolving credit facility, debt issuances and sales of limited partner units. Our operating subsidiaries use cash from their respective operations to fund their operating activities and maintenance capital requirements, service their indebtedness and make advances or distributions to Boardwalk Pipelines. Boardwalk Pipelines uses cash provided from the operating subsidiaries and, as needed, borrowings under our revolving credit facility to service outstanding indebtedness and make distributions or advances to us to fund our distributions to unitholders. We have no material guarantees of debt or other similar commitments to unaffiliated parties. As of September 30, 2014, we had $525.0 million of debt maturing in the next twelve months which we expect to refinance.

Capital Expenditures

Maintenance capital expenditures for the nine months ended September 30, 2014 and 2013 were $63.9 million and $36.9 million. Our maintenance capital spending increased in 2014 from the comparable period in 2013 due to increased integrity management spending. Growth capital expenditures were $237.3 million and $167.4 million for the nine months ended September 30, 2014 and 2013. The 2014 growth capital expenditures primarily relate to our Southeast Market Expansion project. In the third quarter 2014, we purchased $14.7 million of natural gas to be used as base gas for our transmission system. We expect total capital expenditures to be approximately $420.0 million in 2014, including approximately $90.0 million to $100.0 million for maintenance capital. We expect to finance our 2014 growth capital expenditures through cash generated from operations, borrowings under our revolving credit facility and borrowings under our subordinated debt agreement with BPHC, which is further discussed below under Long-Term Debt Affiliate.

Revolving Credit Facility

As of September 30, 2014, and December 31, 2013, we had $185.0 million and $175.0 million of loans outstanding under our revolving credit facility with a weighted-average interest rate of 1.53% and 1.29% and no letters of credit issued thereunder. As of November 4, 2014, we had outstanding borrowings under our revolving credit facility of $485.0 million, resulting in available borrowing capacity of $515.0 million. For further information on our revolving credit facility, refer to Note 8 in Part I, Item 1 of this report.

Term Loan

As of September 30, 2014, and December 31, 2013, we had outstanding borrowings under our 2017 Term Loan of $200.0 million and $225.0 million, with a weighted-average interest rate of 1.90% and 1.92%. No additional borrowing capacity is available under the 2017 Term Loan. For further information on our term loan, refer to Note 8 in Part I, Item 1 of this report.

Long-Term Debt Affiliate

In July 2014, we entered into a Subordinated Loan Agreement with BPHC under which we can borrow up to $300.0 million (Subordinated Loan) through December 31, 2015. The Subordinated Loan bears interest at increasing rates, ranging 5.75% to 9.75%, payable semi-annually in June and December, commencing December 2014, and maturing in July 2024. The Subordinated Loan must be prepaid with the net cash proceeds from the issuance of additional equity securities by us or the incurrence of certain indebtedness by us or our subsidiaries, although BPHC may waive such prepayment. The Subordinated Loan is subordinated in right of payment to our obligations under our revolving credit facility pursuant to the terms of a Subordination Agreement between BPHC and Wells Fargo, N.A., as representative of the lenders under the revolving credit facility. Through the filing date of this Quarterly Report on Form 10-Q, we have not borrowed any amounts under the Subordinated Loan.

Distributions

For the nine months ended September 30, 2014 and 2013, we paid distributions of $74.4 million and $392.0 million to our partners. Note 7 in Part I, Item I of this report contains further discussion regarding our distributions.

Our cash distribution policy is consistent with the terms of our partnership agreement which requires us to distribute our "available cash," as defined in our partnership agreement, on a quarterly basis. Our distributions are determined by the board of directors of our general partner based on our financial position, earnings, cash flow and other relevant factors. There is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy may be changed at any time and is subject to certain restrictions or limitations. Refer to Part II, Item 5 of our 2013 Annual Report on Form 10-K, for our full distribution policy and risks associated with it.

Changes in cash flow from operating activities

Net cash provided by operating activities increased $10.5 million to $412.5 million for the nine months ended September 30, 2014, compared to $402.0 million for the comparable 2013 period primarily due to the change in net income, excluding the effects of depreciation and amortization, asset impairment, equity losses in unconsolidated affiliates and the net gain on sale of operating assets.

Changes in cash flow from investing activities

Net cash used in investing activities increased $163.2 million to $345.9 million for the nine months ended September 30, 2014, compared to $182.7 million for the comparable 2013 period. The increase was primarily driven by an increase in capital expenditures of $111.6 million and a $29.5 million deposit that was paid related to the Evangeline acquisition, partially offset from a decrease in proceeds from the sale of operating assets of $45.7 million and a decrease in our net investment in the Bluegrass Project of $15.8 million.

Changes in cash flow from financing activities

Net cash used in financing activities decreased $109.3 million to $88.9 million for the nine months ended September 30, 2014, compared to $198.2 million for the comparable 2013 period. The decrease in cash used in financing activities resulted primarily from a decrease in distributions of $317.6 million and a decrease in net repayments of borrowings of $202.0 million. The 2013 period included proceeds received from the sale of common units of $376.5 million, including related general partner contributions.

Contractual Obligations

The following table summarizes significant contractual cash payment obligations under firm commitments as of September 30, 2014, by period (in millions):



	Total		Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years
Principal payments on long-term debt ⁽¹⁾	$	3,410.0	$	525.0	$	1,010.0	$	735.0	$	1,140.0
Interest on long-term debt ⁽²⁾	693.0		146.0		239.6		148.2		159.2
Capital commitments ⁽³⁾	85.0		85.0		—		—		—
Total	$	4,188.0	$	756.0	$	1,249.6	$	883.2	$	1,299.2

(1)

Includes our senior unsecured notes, having maturity dates from 2015 to 2027, $185.0 million of loans outstanding under our revolving credit facility, having a maturity date of April 27, 2017, and $200.0 million loans outstanding under our Term Loan, having a maturity date of October 1, 2017. The $525.0 million principal amount of Senior Notes due 2015 that are included in the column Less than 1 Year are included in long-term debt on our balance sheet because we expect to refinance these notes on a long-term basis and we have sufficient available capacity under our revolving credit facility to extend the amount that would otherwise come due in less than one year.


(2)	Interest obligations represent interest due on our senior unsecured notes at fixed rates. Future interest obligations under our revolving credit facility are uncertain, due to the variable interest rate and fluctuating balances. Based on a 1.53%

weighted-average interest rate and an unused commitment fee of 0.20% as of September 30, 2014, $4.5 million and $7.1 million would be due in less than one year and 1-3 years. Based on a 1.90% weighted-average interest rate on amounts outstanding under the Term Loan as of September 30, 2014, $3.8 million and $7.6 million would be due in less than one year and 1-3 years.


(3)	Capital commitments represent binding commitments under purchase orders for materials ordered but not received and firm commitments under binding construction service agreements existing at September 30, 2014.

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. Through the date of this filing, we have contributed $3.0 million to the Texas Gas pension plan and do not expect to contribute additional amounts in 2014.

Off-Balance Sheet Arrangements

At September 30, 2014, we had no guarantees of off-balance sheet debt to third parties, no debt obligations that contain provisions requiring accelerated payment of the related obligations in the event of specified levels of declines in credit ratings, and no other off-balance sheet arrangements.

Critical Accounting Policies

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

During 2014, there have been no significant changes to our critical accounting policies, judgments or estimates disclosed in our 2013 Annual Report on Form 10-K.

Forward-Looking Statements

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

Forward-looking statements are based on current expectations and projections about future events and their potential impact on us. While management believes that these forward-looking statements are reasonable as and when made, there is no assurance that future events affecting us will be those that we anticipate. All forward-looking statements 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:


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


•	our ability to contract to transport gas north to south;


•	the impact to our business of our declaring a lower distribution rate on our common units;


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


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


•	volatility or disruptions in the capital or financial markets;


•	the impact of FERC's rate-making policies and actions on the services we offer and the rates we are proposing to charge or are charging and our ability to recover the full cost of operating our pipeline, including earning a reasonable return on equity;


•	the successful negotiation, consummation and completion of contemplated transactions, projects and agreements, including obtaining all necessary regulatory and customer approvals, or the timing, cost, scope and financial performance of our recent, current and future acquisitions and growth projects;


•	the impact of changes to laws and regulations, such as the proposed greenhouse gas and methane legislation and other changes in environmental legislations, the pipeline safety bill, and regulatory changes that result from that legislation applicable to interstate pipelines, on our business, including our costs, liabilities and revenues;


•	the success of our strategy to grow and diversify our business, including expansion into new product lines and geographic areas;


•	our ability to access the bank and capital markets on acceptable terms to refinance our outstanding indebtedness and to fund our capital needs;


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


•	the future cost of insuring our assets;


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


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


•	the additional risks and uncertainties as described in Part I, Item 1A, Risk Factors of our 2013 Annual Report on Form 10-K.

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

Refer to Part II, Item 7A in our 2013 Annual Report on Form 10-K, for discussion of our market risk.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Commission. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of September 30, 2014.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended September 30, 2014, 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 see Note 6 in Part 1, Item 1 of this report.

Item 1A. Risk Factors

There have been no material changes to the Risk Factors disclosed in Part I, Item 1A, Risk Factors of our 2013 Annual Report on Form 10-K.

Item 6. Exhibits

The following documents are included as exhibits to this report:



Exhibit Number		Description

3.1		Certificate of Limited Partnership of Boardwalk Pipeline Partners, LP (Incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-127578, filed on August 16, 2005).
3.2		Third Amended and Restated Agreement of Limited Partnership of Boardwalk Pipeline Partners, LP dated as of June 17, 2008, (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on June 18, 2008).
3.3		Certificate of Limited Partnership of Boardwalk GP, LP (Incorporated by reference to Exhibit 3.3 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-127578, filed on August 16, 2005).
3.4		Agreement of Limited Partnership of Boardwalk GP, LP (Incorporated by reference to Exhibit 3.4 to Amendment No. 1 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-127578, filed on September 22, 2005).
3.5		Certificate of Formation of Boardwalk GP, LLC (Incorporated by reference to Exhibit 3.5 to the Registrant’s Registration Statement on Form S-1, Registration No. 333-127578, filed on August 16, 2005).
3.6		Amended and Restated Limited Liability Company Agreement of Boardwalk GP, LLC (Incorporated by reference to Exhibit 3.6 to Amendment No. 4 to Registrant’s Registration Statement on Form S-1, Registration No. 333-127578, filed on October 31, 2005).
3.7		Amendment No. 1 to the Third Amended and Restated Agreement of Limited Partnership of Boardwalk Pipeline Partners, LP, dated as of October 31, 2011 (Incorporated by reference to Exhibit 3.7 to the Registrant’s Quarterly Report on Form 10-Q filed on November 1, 2011).
3.8		Amendment No. 2 to the Third Amended and Restated Agreement of Limited Partnership of Boardwalk Pipeline Partners, LP, dated as of October 25, 2012 (Incorporated by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K filed on October 30, 2012).
3.9		Amendment No. 3 to the Third Amended and Restated Agreement of Limited Partnership of Boardwalk Pipeline Partners, LP, dated as of October 7, 2013 (Incorporated by reference to Exhibit 3.1 to the Registrant's Current report on Form 8-K filed on October 8, 2013).
4.1		Subordination Agreement, dated as of July 31, 2014, among Boardwalk Pipelines Holding Corp., as Subordinated Creditor, Wells Fargo Bank, N.A., as Senior Creditor Representative, and Boardwalk Pipelines, LP, as Borrower (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on August 5, 2014).
10.1		Subordinated Loan Agreement dated as of July 31, 2014, between Boardwalk Pipelines, LP, as Borrower, and Boardwalk Pipelines Holding Corp., as Lender (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on August 5, 2014).
*31.1		Certification of Stanley C. Horton, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a).
*31.2		Certification of Jamie L. Buskill, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a).
**32.1		Certification of Stanley C. Horton, Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
**32.2		Certification of Jamie L. Buskill, Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101.INS		XBRL Instance Document
*101.SCH		XBRL Taxonomy Extension Schema Document
*101.CAL		XBRL Taxonomy Calculation Linkbase Document
*101.DEF		XBRL Taxonomy Extension Definitions Document
*101.LAB		XBRL Taxonomy Label Linkbase Document
*101.PRE		XBRL Taxonomy Presentation Linkbase Document
* Filed herewith
** Furnished herewith

SIGNATURE

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



	Boardwalk Pipeline Partners, LP
	By: Boardwalk GP, LP its general partner
	By: Boardwalk GP, LLC its general partner
November 3, 2014	By:	/s/ Jamie L. Buskill
		Jamie L. Buskill Senior Vice President, Chief Financial and Administrative Officer and Treasurer