Edgar Filing: Boardwalk Pipeline Partners, LP

13 Q2 BWP 10Q 6.30.13

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 June 30, 2013

¨ 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 July 30, 2013, the registrant had 220,357,134 common units outstanding and 22,866,667 class B units outstanding.

TABLE OF CONTENTS

FORM 10-Q

June 30, 2013

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	37

Item 3. Quantitative and Qualitative Disclosures About Market Risk	43

Item 4. Controls and Procedures	43

PART II - OTHER INFORMATION

Item 1. Legal Proceedings	44

Item 1A. Risk Factors	44

Item 6. Exhibits	44

Signatures	45

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Millions)

(Unaudited)



ASSETS	June 30, 2013		December 31, 2012
Current Assets:
Cash and cash equivalents	$	9.9	$	3.9
Receivables:
Trade, net	83.0		105.3
Other	11.7		6.9
Gas transportation receivables	6.4		9.0
Costs recoverable from customers	2.7		3.3
Gas and liquids stored underground	1.6		10.8
Prepayments	18.3		15.2
Other current assets	5.6		2.6
Total current assets	139.2		157.0

Property, Plant and Equipment:
Natural gas transmission and other plant	8,351.9		8,165.3
Construction work in progress	170.7		258.0
Property, plant and equipment, gross	8,522.6		8,423.3
Less—accumulated depreciation and amortization	1,345.9		1,234.1
Property, plant and equipment, net	7,176.7		7,189.2

Other Assets:
Goodwill	267.0		267.0
Gas stored underground	103.4		109.7
Investment in unconsolidated affiliates	25.0		—
Other	135.6		139.6
Total other assets	531.0		516.3

Total Assets	$	7,846.9	$	7,862.5

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	June 30, 2013			December 31, 2012
Current Liabilities:
Payables:
Trade	$	33.1		$	69.8
Affiliates	1.0			2.7
Other	15.5			19.2
Gas Payables:
Transportation	9.2			10.4
Storage	0.1			3.5
Accrued taxes, other	47.6			40.5
Accrued interest	47.5			42.5
Accrued payroll and employee benefits	14.2			25.2
Deferred income	6.6			19.9
Other current liabilities	24.1			22.1
Total current liabilities	198.9			255.8

Long–term debt	3,258.3			3,539.2

Other Liabilities and Deferred Credits:
Pension liability	26.9			26.8
Asset retirement obligation	35.4			33.2
Provision for other asset retirement	58.8			57.4
Payable to affiliate	16.0			16.0
Other	63.2			57.0
Total other liabilities and deferred credits	200.3			190.4

Commitments and Contingencies

Equity:
Partners’ Capital:
Common units – 220.4 million units and 207.7 million units issued and outstanding as of June 30, 2013, and December 31, 2012	3,476.5			3,190.3
Class B units – 22.9 million units issued and outstanding as of June 30, 2013, and December 31, 2012	678.3			678.3
General partner	81.6			75.8
Accumulated other comprehensive loss	(67.3		)	(67.3		)
Total partners’ capital	4,169.1			3,877.1
Noncontrolling interest	20.3			—
Total Equity	4,189.4			3,877.1
Total Liabilities and Equity	$	7,846.9		$	7,862.5

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 June 30,						For the Six Months Ended June 30,
	2013			2012			2013			2012
Operating Revenues:
Transportation	$	242.3		$	245.0		$	526.4		$	532.5
Parking and lending	7.1			7.8			15.0			11.8
Storage	27.4			18.9			55.5			38.7
Other	11.9			4.1			20.3			5.7
Total operating revenues	288.7			275.8			617.2			588.7

Operating Costs and Expenses:
Fuel and transportation	27.4			15.0			50.1			33.7
Operation and maintenance	43.8			41.9			84.0			79.5
Administrative and general	28.9			25.2			60.3			59.4
Depreciation and amortization	67.3			60.7			134.1			124.4
Asset impairment	1.1			2.9			1.2			7.1
Net gain on sale of operating assets	(16.2		)	—			(16.2		)	(3.6		)
Taxes other than income taxes	25.3			21.6			50.9			46.1
Total operating costs and expenses	177.6			167.3			364.4			346.6

Operating income	111.1			108.5			252.8			242.1

Other Deductions (Income):
Interest expense	40.7			41.5			81.2			80.5
Interest expense – affiliates	—			2.0			—			4.0
Interest income	(0.1		)	(0.1		)	(0.3		)	(0.2		)
Miscellaneous other income, net	—			(0.1		)	(0.2		)	(0.2		)
Total other deductions	40.6			43.3			80.7			84.1

Income before income taxes	70.5			65.2			172.1			158.0

Income taxes	0.1			0.1			0.3			0.3

Net Income	70.4			65.1			171.8			157.7
Net loss attributable to noncontrolling interests	(0.1		)	—			(0.1		)	—
Net income attributable to controlling interests	$	70.5		$	65.1		$	171.9		$	157.7

Net Income per Unit:
Basic and diluted net income per unit:
Common units	$	0.28		$	0.30		$	0.70		$	0.73
Class B units	$	0.03		$	0.07		$	0.21		$	0.26
Cash distribution declared and paid to common units	$	0.5325		$	0.5325		$	1.065		$	1.0625
Cash distribution declared and paid to class B units	$	0.30		$	0.30		$	0.60		$	0.60
Weighted-average number of units outstanding:
Common units	212.3			184.9			210.0			183.8
Class B units	22.9			22.9			22.9			22.9

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

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Millions)

(Unaudited)



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2013			2012			2013			2012
Net income	$	70.4		$	65.1		$	171.8		$	157.7
Other comprehensive income (loss):
Gain (loss) on cash flow hedges	7.0			(7.2		)	2.5			(6.6		)
Reclassification adjustment transferred to Net Income from cash flow hedges	1.0			0.1			1.1			0.5
Pension and other postretirement benefit costs	(1.9		)	(1.8		)	(3.6		)	(3.5		)
Total Comprehensive Income	76.5			56.2			171.8			148.1
Comprehensive loss attributable to noncontrolling interests	(0.1		)	—			(0.1		)	—
Comprehensive income attributable to controlling interests	$	76.6		$	56.2		$	171.9		$	148.1

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

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions)

(Unaudited)



	For the Six Months Ended June 30,
OPERATING ACTIVITIES:	2013			2012
Net income	$	171.8		$	157.7
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization	134.1			124.4
Amortization of deferred costs	2.7			2.4
Asset impairment	1.2			7.1
Net gain on sale of operating assets	(16.2		)	(3.6		)
Changes in operating assets and liabilities:
Trade and other receivables	(0.5		)	22.4
Other receivables, affiliates	(0.1		)	—
Gas receivables and storage assets	18.2			(5.5		)
Costs recoverable from customers	0.6			3.8
Other assets	11.8			(10.1		)
Trade and other payables	(27.9		)	0.1
Other payables, affiliates	0.7			(3.1		)
Gas payables	0.1			2.7
Accrued liabilities	1.5			(0.6		)
Other liabilities	(12.8		)	(13.4		)
Net cash provided by operating activities	285.2			284.3

INVESTING ACTIVITIES:
Capital expenditures	(132.2		)	(90.9		)
Proceeds from sale of operating assets	21.2			2.4
Proceeds from insurance and other recoveries	1.4			5.4
Investment in unconsolidated affiliates	(21.4		)	—
Net cash used in investing activities	(131.0		)	(83.1		)

FINANCING ACTIVITIES:
Proceeds from long-term debt, net of issuance costs	—			296.5
Proceeds from borrowings on revolving credit agreement	458.0			1,000.0
Repayment of borrowings on revolving credit agreement	(740.0		)	(1,243.5		)
Payments of financing fees related to revolving credit facility	—			(3.8		)
Advances from affiliate	(2.4		)	2.6
Repayment of contribution received related to predecessor equity	—			(284.8		)
Distributions paid	(256.4		)	(228.9		)
Capital contributions from noncontrolling interests	16.1			—
Proceeds from sale of common units	368.7			245.0
Capital contributions from general partner	7.8			5.2
Net cash used in financing activities	(148.2		)	(211.7		)
Increase (decrease) in cash and cash equivalents	6.0			(10.5		)
Cash and cash equivalents at beginning of period	3.9			21.9
Cash and cash equivalents at end of period	$	9.9		$	11.4

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			Predecessor Equity			Accumulated Other Comp Loss			Non-controlling Interest			Total Equity
Balance January 1, 2012	$	2,514.1		$	678.7		$	62.0		$	281.6		$	(49.4	)	$	—		$	3,487.0
Add (deduct):
Net income	126.7			13.7			17.1			0.2			—			—			157.7
Distributions paid	(196.5		)	(13.7		)	(18.7		)	—			—			—			(228.9		)
Sale of common units, net of related transactions costs	245.0			—			—			—			—			—			245.0
Capital contributions from general partner	—			—			5.2			—			—			—			5.2
Predecessor equity carrying amount of acquired entities	—			—			—			(281.8		)	—			—			(281.8		)
Excess purchase price over net acquired assets	(2.6		)	(0.3		)	(0.1		)	—			—			—			(3.0		)
Other comprehensive loss	—			—			—			—			(9.6		)	—			(9.6		)
Balance June 30, 2012	$	2,686.7		$	678.4		$	65.5		$	—		$	(59.0	)	$	—		3,371.6

Balance January 1, 2013	$	3,190.3		$	678.3		$	75.8		$	—		$	(67.3	)	$	—		$	3,877.1
Add (deduct):
Net income (loss)	138.7			13.7			19.5			—			—			(0.1		)	171.8
Distributions paid	(221.2		)	(13.7		)	(21.5		)	—			—			—			(256.4		)
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	—			—			—			—			—			20.4			20.4
Balance June 30, 2013	$	3,476.5		$	678.3		$	81.6		$	—		$	(67.3	)	$	20.3		$	4,189.4

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 July 30, 2013, Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned subsidiary of Loews Corporation (Loews), owned 102.7 million of the Partnership’s common units, all 22.9 million of the Partnership’s class B units and, through Boardwalk GP, LP (Boardwalk GP), an indirect wholly-owned subsidiary of BPHC, holds the 2% general partner interest and all of the incentive distribution rights (IDRs). As of July 30, 2013, the common units, class B 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 June 30, 2013, and December 31, 2012, and the results of operations and comprehensive income for the three and six months ended June 30, 2013 and 2012, and changes in cash flows and changes in equity for the six months ended June 30, 2013 and 2012. Reference is made to the Notes to Consolidated Financial Statements in the 2012 Annual Report on Form 10-K, which should be read in conjunction with these unaudited condensed consolidated financial statements. The accounting policies described in Note 2 to the Consolidated Financial Statements included in such Annual Report on Form 10-K are the same used in preparing the accompanying unaudited condensed consolidated financial statements except as discussed under Consolidation Policy below. Net income for interim periods may not necessarily be indicative of results for the full year.

Certain amounts reported within Total operating costs and expenses in the Condensed Consolidated Statement of Income for the 2012 period have been reclassified to conform to the current presentation. The effect of the reclassification decreased Operation and maintenance expense and increased Net loss (gain) on sale of operating assets, by $0.6 million and $0.2 million for the three and six months ended June 30, 2012, with no impact on Total operating costs and expenses, Operating income or Net Income.

Consolidation Policy

The Partnership's condensed consolidated financial statements include the Partnership's accounts and those of its wholly-owned subsidiaries after the elimination of intercompany transactions. The Partnership also consolidates variable interest entities (VIEs) in which the Partnership is the primary beneficiary. Third party or affiliate ownership interests in the Partnership's subsidiaries and consolidated VIEs are presented as noncontrolling interests.

The Partnership applies the equity method of accounting for investments in unconsolidated affiliates in which it owns 20 percent to 50 percent of the voting interests or otherwise exercises significant influence, but not control, over operating and financial policies of the investee. Under this method, the carrying amounts of the Partnership's equity investments are increased by a proportionate share of the investee's net income and contributions made, and decreased by a proportionate share of the investee's net losses and distributions received.

Note 2: Investments

Bluegrass Project

In the second quarter 2013, the Partnership executed an agreement with the Williams Companies, Inc (Williams) to continue the development process for the Bluegrass Project - a project that would transport NGLs from the Marcellus and Utica shale plays to the petrochemical and export complex in the U.S. Gulf Coast region, and related fractionation and storage facilities. The proposed project would include constructing a new pipeline, a new large-scale fractionation plant and related liquids storage and transport facilities (collectively, the Bluegrass Project).

In connection with the Bluegrass Project, the Partnership executed agreements with BPHC to form Boardwalk Bluegrass Pipeline, LLC (Boardwalk Bluegrass) and Boardwalk Moss Lake, LLC (Boardwalk Moss Lake). Boardwalk Bluegrass and Boardwalk Moss Lake, together with affiliates of Williams, formed Bluegrass Pipeline Company LLC (Bluegrass Pipeline) and Moss Lake Fractionation LLC (Moss Lake) to pursue and, if approved, develop, own and construct the pipeline and fractionation facilities. Boardwalk Bluegrass and Boardwalk Moss Lake currently own 50% of the equity ownership interests in Bluegrass Pipeline and Moss Lake, respectively, with affiliates of Williams owning the other 50%. The parties have equal voting and participation rights.

Boardwalk Bluegrass and Boardwalk Moss Lake

The Partnership contributed a total of $10.0 million for initial equity ownership interests of 59% and 61% in Boardwalk Bluegrass and Boardwalk Moss Lake, respectively, with BPHC owning the remaining equity ownership interests. BPHC has agreed to contribute up to an aggregate of $100.0 million to these entities to fund certain agreed upon pre-construction development costs, with BPHC contributing all additional required capital until such time as BPHC has a 90% equity ownership interest in each entity. Additional capital required for Boardwalk Bluegrass and Boardwalk Moss Lake to continue to pursue the Bluegrass Project is subject to approval by the Partnership and BPHC. As of June 30, 2013, the Partnership held equity ownership interests of 26% and 61%, respectively, in Boardwalk Bluegrass and Boardwalk Moss Lake.

The Partnership determined that Boardwalk Bluegrass and Boardwalk Moss Lake were VIEs due to disproportionate voting rights held by BPHC. The Partnership is the primary beneficiary of Boardwalk Bluegrass and Boardwalk Moss Lake because the Partnership has the power to direct the significant activities related to each entity's investment decision in Bluegrass Pipeline and Moss Lake.

The financial information of Boardwalk Bluegrass and Boardwalk Moss Lake is measured at historical carrying amounts in accordance with the accounting requirements applicable to transactions between entities under common control. At June 30, 2013, the Partnership included in its Condensed Consolidated Balance Sheet cash of $4.8 million and investments in unconsolidated affiliates of $25.0 million that represent amounts recorded by Boardwalk Bluegrass and Boardwalk Moss Lake.

Bluegrass Pipeline and Moss Lake

Bluegrass Pipeline and Moss Lake were determined to be VIEs, because the entities will require additional funding from each equity owner throughout the development and construction phases of the Bluegrass Project. Boardwalk Bluegrass and Boardwalk Moss Lake are not the primary beneficiaries of Bluegrass Pipeline or Moss Lake, because the power to direct the activities that most significantly impact the entity's economic performance is shared between the equity owners. As a result, Boardwalk Bluegrass and Boardwalk Moss Lake account for the investments in Bluegrass Pipeline and Moss Lake under the equity method of accounting. Boardwalk Bluegrass' and Boardwalk Moss Lake's maximum exposure to loss is limited to the carrying value of its investments in Bluegrass Pipeline and Moss Lake, which was $25.0 million as of June 30, 2013. The Partnership's maximum exposure to loss is limited to the amount of the capital contributions it has made to Boardwalk Bluegrass and Boardwalk Moss Lake, or $10.0 million, as of June 30, 2013.

Note 3: Acquisitions

Boardwalk Louisiana Midstream, LLC

In October 2012, the Partnership acquired Boardwalk Louisiana Midstream, LLC (Louisiana Midstream) from PL Logistics LLC for $620.2 million in cash, after customary adjustments and net of cash acquired. The purchase price was funded through a $225.0 million five-year term loan, borrowings under the Partnership's revolving credit facility and the issuance and sale of common units. In the second quarter 2013 the purchase price allocation for Louisiana Midstream was made final and was adjusted to reflect the amount of ethylene in storage at the purchase date. The December 31, 2012, Condensed Consolidated Balance Sheet was retrospectively adjusted to increase the fair value of Gas and liquids stored underground and reduce Goodwill by $3.8 million.

Boardwalk HP Storage Company, LLC

In February 2012, the Partnership acquired BPHC's 80% equity ownership interest in Boardwalk HP Storage Company, LLC (HP Storage) for $284.8 million in cash, which transaction was accounted for as a transaction between entities under common control. Therefore, the assets and liabilities were recognized at their carrying amounts at the date of transfer and the $3.0 million difference between the purchase price and the $281.8 million carrying amount of the net assets acquired at the date of transfer was recognized as an adjustment to partners' capital.

Note 4: 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. The Partnership held for storage or under PAL agreements approximately 115.4 trillion British thermal units (TBtu) of gas owned by third parties as of June 30, 2013. Assuming an average market price during June 2013 of $3.81 per million British thermal units (MMBtu), the market value of gas held on behalf of others was approximately $439.7 million. The Partnership held for storage approximately 3.6 million barrels (Mmbbls) of NGLs owed by third parties as of June 30, 2013, which had a market value of $125.6 million. As of December 31, 2012, the Partnership held for storage or under PAL agreements approximately 137.4 TBtu of gas and 4.2 Mmbbls of NGLs owned by third parties.

Subsidiaries of the Partnership also periodically lend gas to customers under PAL and no-notice services. As of June 30, 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 16.8 TBtu. Assuming an average market price during June 2013 of $3.81 per MMBtu, the market value of that gas was approximately $64.0 million. As of June 30, 2013, the amount of NGLs owed to the operating subsidiaries due to imbalances was approximately 0.1 MMbbls, which had a market value of approximately $6.7 million. As of December 31, 2012, 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 11.7 TBtu and the amount of NGLs owed to the operating subsidiaries due to imbalances was approximately 0.1 MMbbls. 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 5: Fair Value Measurements, Derivatives and Other Comprehensive Income (OCI)

Fair value refers to an exit price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy has been established that prioritizes the information used to develop fair value measurements giving priority, from highest to lowest, to quoted prices in active markets for identical assets and liabilities (Level 1); observable inputs not included in Level 1, for example, quoted prices for similar assets and liabilities (Level 2); and unobservable data (Level 3), for example, a reporting entity's own internal data based on the best information available in the circumstances. The Partnership considers any transfers between levels within the fair value hierarchy to have occurred at the beginning of a quarterly reporting period. The Partnership did not recognize any transfers between Level 1 and Level 2 of the fair value hierarchy and did not change its valuation techniques or inputs during the six months ended June 30, 2013.

The table below identifies the Partnership's assets and liabilities that were recorded at fair value at June 30, 2013 (in millions):



			Fair Value Measurements at June 30, 2013
	June 30, 2013		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 June 30, 2013	Total Gains (losses) for the six months ended June 30, 2013
Recurring fair value measurements – Assets
Derivatives
Commodity contracts	$	3.2	$	—	$	3.2	$	—

Recurring fair value measurements – Liabilities
Derivatives
Commodity contracts	$	0.9	$	—	$	0.9	$	—

The table below identifies the Partnership's assets and liabilities that were recorded at fair value at December 31, 2012 (in millions):



			Fair Value Measurements at December 31, 2012
	December 31, 2012		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 June 30, 2012				Total Gains (losses) for the six months ended June 30, 2012
Recurring fair value measurements – Assets
Derivatives
Commodity contracts	$	0.1	$	—	$	0.1	$	—

Recurring fair value measurements – Liabilities
Derivatives
Commodity contracts	$	0.1	$	—	$	0.1	$	—

Nonrecurring fair value measurements – Assets
Assets to be abandoned	$	—	$	—	$	—	$	—	$	(1.5	)	⁽¹⁾	$	(2.1	)	⁽¹⁾
Assets held for sale	—		—		—		—		—				(2.8		)	⁽²⁾
	$	—	$	—	$	—	$	—	$	(1.5	)		$	(4.9	)

(1)

In 2012, the Partnership determined that it would retire a number of small-diameter pipeline assets with a carrying value of $2.1 million. As a result, an asset impairment charge of $2.9 million and $4.3 million was recorded for the three and six months ended June 30, 2012, of which $1.4 million and $2.2 million represent amounts related to the asset retirement obligations recorded in the three and six months ended June 30, 2012 for these assets.


(2)	In 2012, the Partnership recognized a $2.8 million impairment charge related to its Owensboro, Kentucky, office building. The office building was sold for an amount that equaled its carrying amount of $3.0 million in the third quarter 2012.

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 $1.4 million and $7.0 million of gas stored underground at June 30, 2013, and December 31, 2012, which the Partnership owns and carries on its balance sheet as current Gas and liquids stored underground. Additionally, at June 30, 2013, the Partnership had 9.7 billion cubic feet (Bcf) of gas with a carrying amount of $22.0 million that had become available for sale as a result of a change in the storage gas needed to support operations and no-notice services. At June 30, 2013, approximately 10.3 Bcf of anticipated future sales of natural gas and cash for fuel reimbursement were hedged with derivatives having settlement dates in 2013 and 2014. The derivatives qualify for cash flow hedge accounting and are 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.

At June 30, 2012, the Partnership had $100.0 million notional amount of interest rate swaps outstanding associated with a $200.0 million term loan (term loan). The swaps were settled prior to their maturity due to the repayment of the term loan in the third quarter 2012. The swaps were not designated as cash flow hedges and changes in the fair value of the swaps were recognized as interest expense in the period that those changes occurred. For the three and six months ended June 30, 2012, the Partnership recognized interest expense of $0.3 million and $0.8 million related to the interest rate swaps.

In the second quarter 2012, the Partnership entered into a Treasury rate lock for a notional amount of $300.0 million of principal to hedge the risk attributable to changes in the risk-free component of forward 10-year interest rates through June 30, 2012. The Treasury rate lock was designated as a cash flow hedge. On June 8, 2012, the Partnership settled the rate lock concurrent with the issuance of 10-year notes described in Note 9 and paid the counterparty approximately $6.8 million. The loss was deferred as a component of Accumulated other comprehensive loss and will be amortized to interest expense over the 10-year term of the notes.

The fair values of derivatives existing as of June 30, 2013, and December 31, 2012, were included in the following captions in the Condensed Consolidated Balance Sheets (in millions):



	Derivative Assets						Derivative Liabilities
	June 30, 2013			December 31, 2012			June 30, 2013			December 31, 2012
	Balance sheet location	Fair Value		Balance sheet location	Fair Value		Balance sheet location	Fair Value		Balance sheet location	Fair Value
Derivatives designated as hedging instruments
Commodity contracts	Other current assets	$	2.7	Other current assets	$	0.1	Other current liabilities	$	0.9	Other current liabilities	$	0.1
	Other non-current assets	$	0.5	Other non-current assets	$	—	Other non-current liabilities	$	—	Other non-current liabilities	$	—

The Partnership estimates that approximately $0.4 million of net losses from cash flow hedges reported in Accumulated other comprehensive income/(loss) (AOCI) as of June 30, 2013, are expected to be reclassified into earnings within the next twelve months. The amount of gains and losses from cash flow hedges recognized in the Condensed Consolidated Statements of Income for the three months ended June 30, 2013, were (in millions):



	Amount of gain/(loss) recognized in AOCI on derivatives (effective portion)		Location of gain/(loss) reclassified from AOCI into income (effective portion)	Amount of gain/(loss) reclassified from AOCI into income (effective portion)			Location of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)	Amount of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)
Derivatives in Cash Flow Hedging Relationship
Commodity contracts	$	7.0	Operating revenues ⁽²⁾	$	(0.4	)	N/A	$	—
Interest rate contracts ⁽¹⁾	—		Interest expense	(0.6		)	N/A	—
	$	7.0		$	(1.0	)		$	—


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


(2)	Losses of $0.1 million were recorded in Transportation revenues and losses of $0.3 million were recorded in Other revenues.

The amount of gains and losses from cash flow hedges recognized in the Condensed Consolidated Statements of Income for the three months ended June 30, 2012, were (in millions):



	Amount of gain/(loss) recognized in AOCI on derivatives (effective portion)			Location of gain/(loss) reclassified from AOCI into income (effective portion)	Amount of gain/(loss) reclassified from AOCI into income (effective portion)			Location of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)	Amount of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)
Derivatives in Cash Flow Hedging Relationship
Commodity contracts	$	(0.4	)	Operating revenues ⁽²⁾	$	0.3		N/A	$	—
Interest rate contracts ⁽¹⁾	(6.8		)	Interest expense	(0.4		)	N/A	—
	$	(7.2	)		$	(0.1	)		$	—


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


(2)	Gains of $0.1 million were recorded in Transportation revenues and gains of $0.2 million were recorded in Other revenues.

The amount of gains and losses from cash flow hedges recognized in the Condensed Consolidated Statements of Income for the six months ended June 30, 2013, were (in millions):



	Amount of gain/(loss) recognized in AOCI on derivatives (effective portion)		Location of gain/(loss) reclassified from AOCI into income (effective portion)	Amount of gain/(loss) reclassified from AOCI into income (effective portion)			Location of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)	Amount of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)
Derivatives in Cash Flow Hedging Relationship
Commodity contracts	$	2.5	Operating revenues ⁽²⁾	$	0.1		N/A	$	—
Interest rate contracts ⁽¹⁾	—		Interest expense	(1.2		)	N/A	—
	$	2.5		$	(1.1	)		$	—


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


(2)	Losses of $0.1 million were recorded in Transportation revenues and gains of $0.2 million were recorded in Other revenues.

The amount of gains and losses from cash flow hedges recognized in the Condensed Consolidated Statements of Income for the six months ended June 30, 2012, were (in millions):



	Amount of gain/(loss) recognized in AOCI on derivatives (effective portion)			Location of gain/(loss) reclassified from AOCI into income (effective portion)	Amount of gain/(loss) reclassified from AOCI into income (effective portion)			Location of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)	Amount of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)
Derivatives in Cash Flow Hedging Relationship
Commodity contracts	$	0.2		Operating revenues ⁽²⁾	$	0.4		N/A	$	—
Interest rate contracts ⁽¹⁾	(6.8		)	Interest expense	(0.9		)	N/A	—
	$	(6.6	)		$	(0.5	)		$	—


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


(2)	Gains of $0.2 million were recorded in Transportation revenues and gains of $0.2 million were recorded in Other revenues.

The Partnership has entered into master netting agreements to manage counterparty credit risk associated with its derivatives, however it does not offset on its balance sheets fair value amounts recorded for derivative instruments under these agreements. At June 30, 2013, the Partnership’s outstanding derivatives were with two counterparties and the Partnership had no requirements to post collateral with the counterparties nor did the Partnership hold any collateral associated with its outstanding derivatives. Net receivable positions with the Partnership's counterparties are $2.3 million as of June 30, 2013.

Nonfinancial Assets and Liabilities

The Partnership evaluates long-lived assets for impairment when, in management's judgment, events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Refer to the fair value measurements table above for more information.

Financial Assets and Liabilities

The following methods and assumptions were used in estimating the fair value disclosure amounts for financial instruments, which are consistent with those disclosed in the 2012 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 June 30, 2013, and December 31, 2012. The fair market value of the debt that is not publicly traded is based on market prices of similar debt at June 30, 2013, and December 31, 2012. The carrying value 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 instruments assets and liabilities which are not recorded at fair value on the Condensed Consolidated Balance Sheets as of June 30, 2013, and December 31, 2012, were as follows (in millions):



As of June 30, 2013			Estimated Fair Value
Financial Assets	Carrying Amount		Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	9.9	$	9.9	$	—	$	—	$	9.9

Financial Liabilities
Long-term debt	$	3,258.3	$	—	$	3,450.6	$	—	$	3,450.6



As of December 31, 2012			Estimated Fair Value
Financial Assets	Carrying Amount		Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	3.9	$	3.9	$	—	$	—	$	3.9

Financial Liabilities
Long-term debt	$	3,539.2	$	—	$	3,841.1	$	—	$	3,841.1

Other Comprehensive Income (OCI)

The following table shows the components and reclassifications to net income of Accumulated other comprehensive loss which is included in Partners' Capital on the Condensed Consolidated Balance Sheets for the three months ended June 30, 2013 (in millions):



	Cash Flow Hedges			Pension and Other Postretirement Costs			Total
Beginning balance, April 1, 2013	$	(19.9	)	$	(53.5	)	$	(73.4	)
Gain (loss) recorded in accumulated other comprehensive loss	7.0			—			7.0
Reclassifications:
Transportation operating revenues	0.1			—			0.1
Other operating revenues	0.3			—			0.3
Interest expense	0.6			—			0.6
Administrative and general expense	—			(1.9		)	(1.9		)

Ending balance, June 30, 2013	$	(11.9	)	$	(55.4	)	$	(67.3	)



	Cash Flow Hedges			Pension and Other Postretirement Costs			Total
Beginning balance, January 1, 2013	$	(15.5	)	$	(51.8	)	$	(67.3	)
Gain (loss) recorded in accumulated other comprehensive loss	2.5			—			2.5
Reclassifications:
Transportation operating revenues	0.1			—			0.1
Other operating revenues	(0.2		)	—			(0.2		)
Interest expense	1.2			—			1.2
Administrative and general expense	—			(3.6		)	(3.6		)

Ending balance, June 30, 2013	$	(11.9	)	$	(55.4	)	$	(67.3	)

Note 6: Property, Plant and Equipment (PPE)

Gas Sales

In the second quarter 2013, the Partnership recognized a gain of $17.0 million from the sale of approximately 5.0 Bcf of natural gas stored underground with a carrying amount of $2.6 million that was sold as a result of a strategy to monetize storage base gas and provide capacity for additional parks of customer gas under PAL service.

Carthage Compressor Station Incident

In the first quarter 2013, the Partnership received $1.7 million in insurance proceeds as final payment for an insurance claim, the majority of which was recorded as a decrease to Operation and maintenance expense, related to a fire which occurred at one of Gulf South Pipeline Company, LP's (Gulf South) compressor stations near Carthage, Texas. In the second quarter 2012, the Partnership received $10.0 million in insurance proceeds as partial payment for the insurance claim and recognized a $1.2 million reduction in Operation and maintenance expense for the three and six months ended June 30, 2012.

Asset Impairments

The Partnership recognized $1.1 million and $1.2 million of asset impairments for the three and six months ended June 30, 2013 and $2.9 million and $7.1 million of asset impairments for the three and six months ended June 30, 2012. Refer to Note 5 for further information.

Note 7: Commitments and Contingencies

Legal Proceedings and Settlements

The Partnership's subsidiaries are parties to various legal actions arising in the normal course of business. Management believes the disposition of these outstanding legal actions will not have a material 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 seven 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. Mobile Gas Service Corp, et al. (Case No. CV-12-900711), Crum, et al. v. Mobile Gas Service Corp, et al. (Case No. CV-12-901057), Austin, et al. v. Mobile Gas Service Corp, et al. (Case No. CV-12-901133), Moore, et al. v. Mobile Gas Service Corp, et al. (Case No. CV-12-901471), Davis, et al. v. Mobile Gas Service Corp, et al. (Case No. CV-12-901490), Joel G. Reed, et al. v. Mobile Gas Service Corp, et al. (Case No. CV-2013-922265) and The Housing Authority of the City of Prichard, Alabama v. Mobile Gas Service Corp., et al. (Case No. CV-2013-901002). 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.

The outcome of these cases cannot be predicted at this time; however, based on the facts and circumstances presently known, in the opinion of management, these cases 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 June 30, 2013, and December 31, 2012, the Partnership had an accrued liability of approximately $7.3 million and $7.8 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 nine years. As of June 30, 2013, and December 31, 2012, approximately $2.2 million was recorded in Other current liabilities and approximately $5.1 million and $5.6 million were recorded in Other Liabilities and Deferred Credits.

Clean Air Act

The Partnership’s pipelines are subject to the Clean Air Act, as amended (CAA), and the CAA Amendments of 1990, as amended (Amendments), which added significant provisions to the CAA. The Amendments require the Environmental Protection Agency (EPA) to promulgate new regulations pertaining to mobile sources, air toxics, areas of ozone non-attainment, greenhouse gases and regulations affecting reciprocating engines subject to Maximum Achievable Control Technology (MACT). The operating subsidiaries presently operate two facilities in areas affected by non-attainment requirements for the current ozone standard (8-hour ozone standard). If the EPA designates additional new non-attainment areas or promulgates new air regulations where the Partnership operates, the cost of additions to PPE is expected to increase. The Partnership has assessed the impact of the CAA on its facilities and does not believe compliance with these regulations will have a material impact on its financial condition, results of operations or cash flows.

In 2008, the EPA adopted regulations lowering the 8-hour ozone standard relevant to non-attainment areas. Under the regulations, new non-attainment areas were identified in April 2012. The Partnership identified one facility which could require the installation of additional emission controls for compliance between 2014 and 2019. The 8-hour ozone standard is due for review by the EPA in 2013 with final rulemaking expected to be completed in 2014. Revisions to the regulation could lower the 8-hour ozone standard set in 2008 and include a compliance deadline between 2017 and 2031. The Partnership continues to monitor this regulation relative to potentially impacted facilities.

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

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

Commitments for Construction

The Partnership’s future capital commitments are comprised of binding commitments under purchase orders for materials ordered but not received and firm commitments under binding construction service agreements. The commitments as of June 30, 2013, were approximately $112.8 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 or pipeline capacity agreements disclosed in Note 4 to the Partnership’s 2012 Annual Report on Form 10-K.

Note 8: Cash Distributions and Net Income per Unit

Cash Distributions

In the second quarters 2013 and 2012, the Partnership declared and paid quarterly distributions 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 and amounts to the general partner on behalf of its 2% general partner interest and as holder of the IDRs. In July 2013, the Partnership declared a quarterly cash distribution to unitholders of record of $0.5325 per common unit.

Net Income per Unit

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

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

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



	Total			Common Units			Class B Units			General Partner and IDRs
Net income	$	70.4
Less: Net loss attributable to noncontrolling interests	(0.1		)
Net income attributable to controlling interests	70.5
Declared distribution	135.6			$	117.3		$	6.9		$	11.4
Assumed allocation of undistributed net loss	(65.1		)	(57.6		)	(6.2		)	(1.3		)
Assumed allocation of net income attributable to limited partner unitholders and general partner	$	70.5		$	59.7		$	0.7		$	10.1
Weighted-average units outstanding				212.3			22.9
Net income per unit				$	0.28		$	0.03



	Total			Common Units			Class B Units			General Partner and IDRs
Net income	$	65.1
Declared distribution	114.9			$	98.5		$	6.8		$	9.6
Assumed allocation of undistributed net loss	(49.8		)	(43.5		)	(5.3		)	(1.0		)
Assumed allocation of net income attributable to limited partner unitholders and general partner	$	65.1		$	55.0		$	1.5		$	8.6
Weighted-average units outstanding				184.9			22.9
Net income per unit				$	0.30		$	0.07

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



	Total			Common Units			Class B Units			General Partner and IDRs
Net income	$	171.8
Less: Net loss attributable to noncontrolling interests	(0.1		)
Net income attributable to controlling interests	171.9
Declared distribution	263.8			$	227.9		$	13.7		$	22.2
Assumed allocation of undistributed net loss	(91.9		)	(81.2		)	(8.9		)	(1.8		)
Assumed allocation of net income attributable to limited partner unitholders and general partner	$	171.9		$	146.7		$	4.8		$	20.4
Weighted-average units outstanding				210.0			22.9
Net income per unit				$	0.70		$	0.21

The following table provides a reconciliation of net income and the assumed allocation of net income to the common and class B units for purposes of computing net income per unit for the six months ended June 30, 2012, (in millions, except per unit data):



	Total			Common Units			Class B Units			General Partner and IDRs
Net income	$	157.7
Less: Net income attributable to predecessor equity	0.2
Net income attributable to controlling interests	157.5
Declared distribution	229.8			$	196.9		$	13.7		$	19.2
Assumed allocation of undistributed net loss	(72.3		)	(63.1		)	(7.8		)	(1.4		)
Assumed allocation of net income attributable to limited partner unitholders and general partner	$	157.5		$	133.8		$	5.9		$	17.8
Weighted-average units outstanding				183.8			22.9
Net income per unit				$	0.73		$	0.26

Note 9: Financing

Notes and Debentures

As of June 30, 2013, and December 31, 2012, the Partnership had notes and debentures outstanding of $3.0 billion with a weighted-average interest rate of 5.32%. 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 June 30, 2013, the Partnership and its subsidiaries were in compliance with its debt covenants.

Issuance of Notes

During the six months ended June 30, 2013 and 2012, the Partnership completed the following debt issuance (in millions, except interest rates):



Date of Issuance	Issuing Subsidiary	Amount of Issuance	Purchaser Discounts and Expenses	Net Proceeds			Interest Rate	Maturity Date	Interest Payable
June 2012	Gulf South	$300.0	$3.5		$296.5	⁽¹⁾	4.00%	June 15, 2022	June 15 and December 15

(1) The net proceeds of this offering were used to reduce borrowings under the Partnership's revolving credit facility.

Revolving Credit Facility

Outstanding borrowings under the Partnership’s revolving credit facility as of June 30, 2013, and December 31, 2012, were $20.0 million and $302.0 million, with a weighted-average borrowing rate of 1.32% and 1.34%.

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 June 30, 2013.

Term Loan

The Partnership has a $225.0 million variable-rate term loan due October 1, 2017 (2017 Term Loan), which was entered into to partially finance the acquisition of Louisiana Midstream. The 2017 Term Loan bears interest at a rate that is based on the one-month London Interbank Offered Rate (LIBOR) rate plus an applicable margin. Outstanding borrowings as of June 30, 2013 and December 31, 2012, were $225.0 million, with a weighted-average borrowing interest rate of 1.95% and 1.96%.

Common Unit Offering

For the six months ended June 2013 and 2012, the Partnership completed the following issuances and sales of common units (in millions, except the issuance price):



Month of Offering	Number of Common Units	Issuance Price	Less Underwriting Discounts and Expenses	Net Proceeds (including General Partner Contribution)	Common Units Outstanding After Offering	Common Units Held by the Public After Offering
May 2013 ⁽¹⁾	12.7	$30.12	$12.3	$376.5	220.4	117.6
February 2012 ⁽²⁾	9.2	$27.55	$8.5	$250.2	184.9	82.2

(1) The net proceeds of this offering were used to repay borrowings outstanding under the Partnership's credit facility.

(2) The net proceeds were used to purchase the remaining equity ownership interest in HP Storage from BPHC.

Class B Units

The Class B units are convertible into common units upon demand by the holder on a one-for-one basis at any time after June 30, 2013. The Partnership expects the Class B units to be converted in the third quarter 2013.

Note 10: Employee Benefits

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

Texas Gas Transmission, LLC (Texas Gas) employees hired prior to November 1, 2006, are covered under a non-contributory, defined benefit pension plan (Pension Plan). The Texas Gas Supplemental Retirement Plan (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 January 1, 1996, and have met certain other requirements.

Components of net periodic benefit cost for both the Retirement Plans and PBOP for the three months ended June 30, 2013 and 2012 were as follows (in millions):



	Retirement Plans						PBOP
	For the Three Months Ended June 30,						For the Three Months Ended June 30,
	2013			2012			2013			2012
Service cost	$	1.1		$	1.0		$	0.1		$	0.1
Interest cost	1.2			1.5			0.4			0.6
Expected return on plan assets	(2.3		)	(2.2		)	(1.1		)	(1.0		)
Amortization of prior service credit	—			—			(1.9		)	(2.0		)
Amortization of unrecognized net loss	0.6			0.5			(0.1		)	—
Net periodic benefit cost	$	0.6		$	0.8		$	(2.6	)	$	(2.3	)

Components of net periodic benefit cost for both the Retirement Plans and PBOP for the six months ended June 30, 2013 and 2012 were as follows (in millions):



	Retirement Plans						PBOP
	For the Six Months Ended June 30,						For the Six Months Ended June 30,
	2013			2012			2013			2012
Service cost	$	2.2		$	2.0		$	0.2		$	0.2
Interest cost	2.4			2.9			0.9			1.2
Expected return on plan assets	(4.5		)	(4.3		)	(2.2		)	(2.1		)
Amortization of prior service credit	—			—			(3.8		)	(3.9		)
Amortization of unrecognized net loss	1.2			1.0			—			0.1
Net periodic benefit cost	$	1.3		$	1.6		$	(4.9	)	$	(4.5	)

Through the date of this filing, the Partnership has not contributed to the Pension Plan, but expects to fund $3.0 million to the Pension Plan in 2013.

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 and $2.0 million for the three months ended June 30, 2013 and 2012, and were $4.4 million and $4.1 million for the six months ended June 30, 2013 and 2012.

Note 11: 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 $2.1 million for the three months ended June 30, 2013, and recognized income of $2.2 million for the three months ended June 30, 2012. The Partnership incurred charges related to these services of $4.2 million and $5.9 million for the six months ended June 30, 2013 and 2012.

Distributions paid related to limited partner units held by BPHC and the 2% general partner interest and IDRs held by Boardwalk GP were $72.3 million and $71.2 million during the three months ended June 30, 2013 and 2012 and $144.6 million and $141.6 million for the six months ended June 30, 2013 and 2012.

In the second quarter 2013, the Partnership entered into agreements with BPHC to form Boardwalk Bluegrass and Boardwalk Moss Lake. Refer to Note 2 for further information. For the six months ended June 30, 2013, the Partnership contributed $10.0 million and BPHC contributed $19.7 million to these entities.

Note 12: Supplemental Disclosure of Cash Flow Information (in millions):



	For the Six Months Ended June 30,
	2013		2012
Cash paid during the period for:
Interest (net of amount capitalized)	$	71.7	$	85.2

Note 13: 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 June 30, 2013, and December 31, 2012. Note 9 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 June 30, 2013

(Millions)



Assets	Parent Guarantor		Subsidiary Issuer		Non-guarantor Subsidiaries		Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Cash and cash equivalents	$	—	$	1.2	$	8.7	$	—		$	9.9
Receivables	—		2.4		99.3		(7.0		)	94.7
Gas and liquids stored underground	—		—		1.6		—			1.6
Prepayments	0.2		0.1		18.0		—			18.3
Other current assets	0.2		—		24.2		(9.7		)	14.7
Total current assets	0.4		3.7		151.8		(16.7		)	139.2
Investment in consolidated subsidiaries	1,412.4		6,012.3		—		(7,424.7		)	—
Property, plant and equipment, gross	0.6		—		8,522.0		—			8,522.6
Less–accumulated depreciation and amortization	0.6		—		1,345.3		—			1,345.9
Property, plant and equipment, net	—		—		7,176.7		—			7,176.7
Other noncurrent assets	—		4.3		500.3		1.4			506.0
Advances to affiliates – noncurrent	2,773.9		140.9		573.5		(3,488.3		)	—
Investment in unconsolidated affiliates	—		—		25.0		—			25.0
Total other assets	2,773.9		145.2		1,098.8		(3,486.9		)	531.0

Total Assets	$	4,186.7	$	6,161.2	$	8,427.3	$	(10,928.3	)	$	7,846.9



Liabilities and Equity	Parent Guarantor		Subsidiary Issuer		Non-guarantor Subsidiaries		Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Payables	$	0.3	$	—	$	48.3	$	—		$	48.6
Payable to affiliates	1.0		—		7.0		(7.0		)	1.0
Other current liabilities	0.3		22.0		135.0		(8.0		)	149.3
Total current liabilities	1.6		22.0		190.3		(15.0		)	198.9
Total long-term debt	—		1,379.4		1,878.9		—			3,258.3
Payable to affiliate	16.0		3,347.4		140.9		(3,488.3		)	16.0
Other noncurrent liabilities	—		—		184.6		(0.3		)	184.3
Total other liabilities and deferred credits	16.0		3,347.4		325.5		(3,488.6		)	200.3
Total partners’ capital/member’s equity	4,169.1		1,412.4		6,012.3		(7,424.7		)	4,169.1
Noncontrolling interest	—		—		20.3		—			20.3
Total Equity	4,169.1		1,412.4		6,032.6		(7,424.7		)	4,189.4
Total Liabilities and Equity	$	4,186.7	$	6,161.2	$	8,427.3	$	(10,928.3	)	$	7,846.9

Condensed Consolidating Balance Sheets as of December 31, 2012

(Millions)



Assets	Parent Guarantor		Subsidiary Issuer		Non-guarantor Subsidiaries		Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Cash and cash equivalents	$	0.1	$	1.0	$	2.8	$	—		$	3.9
Receivables	—		—		119.5		(7.3		)	112.2
Gas and liquids stored underground	—		—		10.8		—			10.8
Prepayments	—		—		15.2		—			15.2
Advances to affiliates	—		—		2.0		(2.0		)	—
Other current assets	0.4		—		18.1		(3.6		)	14.9
Total current assets	0.5		1.0		168.4		(12.9		)	157.0
Investment in consolidated subsidiaries	1,257.0		5,785.7		—		(7,042.7		)	—
Property, plant and equipment, gross	0.6		—		8,422.7		—			8,423.3
Less–accumulated depreciation and amortization	0.6		—		1,233.5		—			1,234.1
Property, plant and equipment, net	—		—		7,189.2		—			7,189.2
Other noncurrent assets	0.1		4.8		511.4		—			516.3
Advances to affiliates – noncurrent	2,638.5		84.4		582.6		(3,305.5		)	—
Total other assets	2,638.6		89.2		1,094.0		(3,305.5		)	516.3

Total Assets	$	3,896.1	$	5,875.9	$	8,451.6	$	(10,361.1	)	$	7,862.5



Liabilities & Equity	Parent Guarantor		Subsidiary Issuer		Non-guarantor Subsidiaries		Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Payables	$	0.1	$	—	$	96.2	$	(7.3	)	$	89.0
Payable to affiliates	2.7		2.0		—		(2.0		)	2.7
Other current liabilities	0.2		16.9		150.4		(3.4		)	164.1
Total current liabilities	3.0		18.9		246.6		(12.7		)	255.8
Total long-term debt	—		1,378.9		2,160.3		—			3,539.2
Payable to affiliate	16.0		3,221.1		84.4		(3,305.5		)	16.0
Other noncurrent liabilities	—		—		174.6		(0.2		)	174.4
Total other liabilities and deferred credits	16.0		3,221.1		259.0		(3,305.7		)	190.4
Total partners’ capital/member’s equity	3,877.1		1,257.0		5,785.7		(7,042.7		)	3,877.1
Noncontrolling interest	—		—		—		—			—
Total Equity	3,877.1		1,257.0		5,785.7		(7,042.7		)	3,877.1
Total Liabilities and Equity	$	3,896.1	$	5,875.9	$	8,451.6	$	(10,361.1	)	$	7,862.5

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

(Millions)



	Parent Guarantor			Subsidiary Issuer			Non-guarantor Subsidiaries			Eliminations				Consolidated Boardwalk Pipeline Partners, LP
Operating Revenues:
Transportation	$	—		$	—		$	264.6		$	(22.3	)		$	242.3
Parking and lending	—			—			7.1			—				7.1
Storage	—			—			27.4			—				27.4
Other	—			—			11.9			—				11.9
Total operating revenues	—			—			311.0			(22.3		)		288.7

Operating Cost and Expenses:
Fuel and transportation	—			—			49.7			(22.3		)		27.4
Operation and maintenance	—			0.3			43.5			—				43.8
Administrative and general	—			0.8			28.1			—				28.9
Other operating costs and expenses	0.1			0.1			77.3			—				77.5
Total operating costs and expenses	0.1			1.2			198.6			(22.3		)		177.6
Operating (loss) income	(0.1		)	(1.2		)	112.4			—				111.1

Other Deductions (Income):
Interest expense	—			18.0			22.7			—				40.7
Interest (income) expense, affiliate, net	(8.2		)	10.2			(2.0		)	—				—
Interest income	—			—			(0.1		)	—				(0.1		)
Equity in earnings of subsidiaries	(62.4		)	(91.8		)	—			154.2				—
Total other (income) deductions	(70.6		)	(63.6		)	20.6			154.2				40.6

Income before income taxes	70.5			62.4			91.8			(154.2		)		70.5
Income taxes	—			—			0.1			—			—	0.1

Net Income	70.5			62.4			91.7			(154.2		)		70.4
Net loss attributable to noncontrolling interests	—			—			(0.1		)	—				(0.1		)
Net income attributable to controlling interests	$	70.5		$	62.4		$	91.8		$	(154.2	)		$	70.5

Condensed Consolidating Statements of Income for the Three Months Ended June 30, 2012

(Millions)



	Parent Guarantor			Subsidiary Issuer			Non-guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Operating Revenues:
Transportation	$	—		$	—		$	266.6		$	(21.6	)	$	245.0
Parking and lending	—			—			7.8			—			7.8
Storage	—			—			19.0			(0.1		)	18.9
Other	—			—			4.1			—			4.1
Total operating revenues	—			—			297.5			(21.7		)	275.8

Operating Cost and Expenses:
Fuel and transportation	—			—			36.7			(21.7		)	15.0
Operation and maintenance	—			—			41.9			—			41.9
Administrative and general	(0.1		)	—			25.3			—			25.2
Other operating costs and expenses	0.1			—			85.1			—			85.2
Total operating costs and expenses	—			—			189.0			(21.7		)	167.3
Operating income	—			—			108.5			—			108.5

Other Deductions (Income):
Interest expense	—			15.8			25.7			—			41.5
Interest (income) expense, affiliate, net	(8.6		)	13.8			(3.2		)	—			2.0
Interest income	—			—			(0.1		)	—			(0.1		)
Equity in earnings of subsidiaries	(56.5		)	(86.1		)	—			142.6			—
Miscellaneous other income, net	—			—			(0.1		)	—			(0.1		)
Total other (income) deductions	(65.1		)	(56.5		)	22.3			142.6			43.3

Income before income taxes	65.1			56.5			86.2			(142.6		)	65.2
Income taxes	—			—			0.1			—			0.1

Net Income	$	65.1		$	56.5		$	86.1		$	(142.6	)	$	65.1

Condensed Consolidating Statements of Income for the Six Months Ended June 30, 2013

(Millions)



	Parent Guarantor			Subsidiary Issuer			Non-guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Operating Revenues:
Transportation	$	—		$	—		$	570.4		$	(44.0	)	$	526.4
Parking and lending	—			—			15.0			—			15.0
Storage	—			—			55.6			(0.1		)	55.5
Other	—			—			20.3			—			20.3
Total operating revenues	—			—			661.3			(44.1		)	617.2

Operating Cost and Expenses:
Fuel and transportation	—			—			94.2			(44.1		)	50.1
Operation and maintenance	—			0.3			83.7			—			84.0
Administrative and general	—			0.8			59.5			—			60.3
Other operating costs and expenses	0.1			0.1			169.8			—			170.0
Total operating costs and expenses	0.1			1.2			407.2			(44.1		)	364.4
Operating (loss) income	(0.1		)	(1.2		)	254.1			—			252.8

Other Deductions (Income):
Interest expense	—			35.2			46.0			—			81.2
Interest (income) expense, affiliate, net	(16.6		)	20.5			(3.9		)	—			—
Interest income	—			—			(0.3		)	—			(0.3		)
Equity in earnings of subsidiaries	(155.4		)	(212.3		)	—			367.7			—
Miscellaneous other income, net	—			—			(0.2		)	—			(0.2		)
Total other (income) deductions	(172.0		)	(156.6		)	41.6			367.7			80.7

Income before income taxes	171.9			155.4			212.5			(367.7		)	172.1
Income taxes	—			—			0.3			—			0.3

Net Income	171.9			155.4			212.2			(367.7		)	171.8
Net loss attributable to noncontrolling interests	—			—			(0.1		)	—			(0.1		)
Net income attributable to controlling interests	$	171.9		$	155.4		$	212.3		$	(367.7	)	$	171.9

Condensed Consolidating Statements of Income for the Six Months Ended June 30, 2012

(Millions)



	Parent Guarantor			Subsidiary Issuer			Non-guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Operating Revenues:
Transportation	$	—		$	—		$	575.9		$	(43.4	)	$	532.5
Parking and lending	—			—			11.8			—			11.8
Storage	—			—			38.8			(0.1		)	38.7
Other	—			—			5.7			—			5.7
Total operating revenues	—			—			632.2			(43.5		)	588.7

Operating Cost and Expenses:
Fuel and transportation	—			—			77.2			(43.5		)	33.7
Operation and maintenance	—			—			79.5			—			79.5
Administrative and general	(0.1		)	—			59.5			—			59.4
Other operating costs and expenses	0.1			—			173.9			—			174.0
Total operating costs and expenses	—			—			390.1			(43.5		)	346.6
Operating income	—			—			242.1			—			242.1

Other Deductions (Income):
Interest expense	—			31.7			48.8			—			80.5
Interest (income) expense, affiliate, net	(17.8		)	27.4			(5.6		)	—			4.0
Interest income	—			—			(0.2		)	—			(0.2		)
Equity in earnings of subsidiaries	(139.9		)	(199.0		)	—			338.9			—
Miscellaneous other income, net	—			—			(0.2		)	—			(0.2		)
Total other (income) deductions	(157.7		)	(139.9		)	42.8			338.9			84.1

Income before income taxes	157.7			139.9			199.3			(338.9		)	158.0
Income taxes	—			—			0.3			—			0.3

Net Income	$	157.7		$	139.9		$	199.0		$	(338.9	)	$	157.7

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

(Millions)



	Parent Guarantor			Subsidiary Issuer			Non-guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Net Income	$	70.5		$	62.4		$	91.7		$	(154.2	)	$	70.4
Other comprehensive income (loss):
Gain (loss) on cash flow hedges	7.0			7.0			7.0			(14.0		)	7.0
Reclassification adjustment transferred to Net Income from ash flow hedges	1.0			0.4			0.6			(1.0		)	1.0
Pension and other postretirement benefit costs	(1.9		)	(1.9		)	(1.9		)	3.8			(1.9		)
Total Comprehensive Income	76.6			67.9			97.4			(165.4		)	76.5
Comprehensive loss attributable to noncontrolling interests	—			—			(0.1		)	—			(0.1		)
Comprehensive income attributable to controlling interests	$	76.6		$	67.9		$	97.5		$	(165.4	)	$	76.6

Condensed Consolidating Statements of Comprehensive Income for the Three Months Ended June 30, 2012

(Millions)



	Parent Guarantor			Subsidiary Issuer			Non-guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Net Income	$	65.1		$	56.5		$	86.1		$	(142.6	)	$	65.1
Other comprehensive income (loss):
(Loss) gain on cash flow hedges	(7.2		)	(7.2		)	(7.2		)	14.4			(7.2		)
Reclassification adjustment transferred to Net Income from cash flow hedges	0.1			0.4			(0.3		)	(0.1		)	0.1
Pension and other postretirement benefit costs	(1.8		)	(1.8		)	(1.8		)	3.6			(1.8		)
Total Comprehensive Income	$	56.2		$	47.9		$	76.8		$	(124.7	)	$	56.2

Condensed Consolidating Statements of Comprehensive Income for the Six Months Ended June 30, 2013

(Millions)



	Parent Guarantor			Subsidiary Issuer			Non-guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Net Income	$	171.9		$	155.4		$	212.2		$	(367.7	)	$	171.8
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	1.1			0.9			0.2			(1.1		)	1.1
Pension and other postretirement benefit costs	(3.6		)	(3.6		)	(3.6		)	7.2			(3.6		)
Total Comprehensive Income	171.9			155.2			211.3			(366.6		)	171.8
Comprehensive loss attributable to noncontrolling interests	—			—			(0.1		)	—			(0.1		)
Comprehensive income attributable to controlling interests	$	171.9		$	155.2		$	211.4		$	(366.6	)	$	171.9

Condensed Consolidating Statements of Comprehensive Income for the Six Months Ended June 30, 2012

(Millions)



	Parent Guarantor			Subsidiary Issuer			Non-guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Net Income	$	157.7		$	139.9		$	199.0		$	(338.9	)	$	157.7
Other comprehensive income (loss):
(Loss) gain on cash flow hedges	(6.6		)	(6.6		)	(6.6		)	13.2			(6.6		)
Reclassification adjustment transferred to Net Income from cash flow hedges	0.5			0.8			(0.3		)	(0.5		)	0.5
Pension and other postretirement benefit costs	(3.5		)	(3.5		)	(3.5		)	7.0			(3.5		)
Total Comprehensive Income	$	148.1		$	130.6		$	188.6		$	(319.2	)	$	148.1

Condensed Consolidating Statements of Cash Flow for the Six Months Ended June 30, 2013

(Millions)



	Parent Guarantor			Subsidiary Issuer			Non-guarantor Subsidiaries			Eliminations				Consolidated Boardwalk Pipeline Partners, LP
Net Cash Provided by (Used In) Operating Activities	$	17.6		$	(52.5	)	$	320.1		$	—			$	285.2

Investing Activities:
Capital expenditures	—			—			(132.2		)	—				(132.2		)
Proceeds from sale of operating assets	—			—			21.2			—				21.2
Proceeds from insurance and other recoveries	—			—			1.4			—				1.4
Advances to affiliates, net	(135.4		)	(56.5		)	11.1			180.8				—
Investment in consolidated subsidiary	—			(15.1		)	—			15.1				—
Investment in unconsolidated affiliate	—			—			(21.4		)	—				(21.4		)
Net Cash (Used in) Provided by Investing Activities	(135.4		)	(71.6		)	(119.9		)	195.9				(131.0		)

Financing Activities:
Proceeds from borrowings on revolving credit agreement	—			—			458.0			—				458.0
Repayment of borrowings on revolving credit agreement	—			—			(740.0		)	—				(740.0		)
Contribution from parent	—			—			15.1			(15.1		)		—
Advances from affiliates, net	(2.4		)	124.3			56.5			(180.8		)		(2.4		)
Distributions paid	(256.4		)	—			—			—				(256.4		)
Capital contribution from noncontrolling interests	—			—			16.1			—			—	16.1
Proceeds from sale of common units	368.7			—			—			—				368.7
Capital contribution from general partner	7.8			—			—			—				7.8
Net Cash Provided by (Used in) Financing Activities	117.7			124.3			(194.3		)	(195.9		)		(148.2		)

(Decrease) increase in Cash and Cash Equivalents	(0.1		)	0.2			5.9			—				6.0
Cash and Cash Equivalents at Beginning of Period	0.1			1.0			2.8			—				3.9
Cash and Cash Equivalents at End of Period	$	—		$	1.2		$	8.7		$	—			$	9.9

Condensed Consolidating Statements of Cash Flow for the Six Months Ended June 30, 2012

(Millions)



	Parent Guarantor			Subsidiary Issuer			Non-guarantor Subsidiaries			Eliminations			Consolidated Boardwalk Pipeline Partners, LP
Net Cash Provided by (Used In) Operating Activities	$	(4.1	)	$	53.4		$	329.1		$	(94.1	)	$	284.3

Investing Activities:
Capital expenditures	—			—			(90.9		)	—			(90.9		)
Proceeds from sale of operating assets	—			—			2.4			—			2.4
Proceeds from insurance and other recoveries	—			—			5.4			—			5.4
Advances to affiliates, net	(20.3		)	(36.9		)	(370.7		)	427.9			—
Investment in consolidated subsidiary	—			(26.1		)	—			26.1			—
Net Cash Provided by (Used in) Investing Activities	(20.3		)	(63.0		)	(453.8		)	454.0			(83.1		)

Financing Activities:
Proceeds from long-term debt, net of issuance costs	—			—			296.5			—			296.5
Proceeds from borrowings on revolving credit agreement	—			270.0			730.0			—			1,000.0
Repayment of borrowings on revolving credit agreement	—			(370.0		)	(873.5		)	—			(1,243.5		)
Payments of financing fees related to revolving credit facility	—			(3.8		)	—			—			(3.8		)
Contribution from parent	—			—			26.1			(26.1		)	—
Advances from affiliates, net	2.6			390.6			37.4			(428.0		)	2.6
Repayment of contribution received related to predecessor equity	—			(284.8		)	—			—			(284.8		)
Distributions paid	(228.9		)	—			(94.2		)	94.2			(228.9		)
Proceeds from sale of common units	245.0			—			—			—			245.0
Capital contribution from general partner	5.2			—			—			—			5.2
Net Cash (Used in) Provided by Financing Activities	23.9			2.0			122.3			(359.9		)	(211.7		)

Decrease in Cash and Cash Equivalents	(0.5		)	(7.6		)	(2.4		)	—			(10.5		)
Cash and Cash Equivalents at Beginning of Period	0.5			10.7			10.7			—			21.9
Cash and Cash Equivalents at End of Period	$	—		$	3.1		$	8.3		$	—		$	11.4

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, 2012.

Overview

Our transportation services consist of firm natural gas transportation, where the customer pays a capacity reservation charge to reserve pipeline capacity at certain receipt and delivery points along our pipeline systems, plus a commodity and fuel charge on the volume of natural gas actually transported, and interruptible natural gas transportation, where the customer pays to transport gas only when capacity is available and used. We also offer firm natural gas storage services where the customer reserves and pays for a specific amount of storage capacity, including injection and withdrawal rights, and interruptible storage and parking and lending (PAL) services where the customer receives and pays for capacity only when it is available and used. Some PAL agreements are paid for at inception of the service and revenues for these agreements are recognized as service is provided over the term of the agreement. Our natural gas liquids (NGLs) contracts are generally fee-based and are dependent on actual volumes transported or stored, although in some cases minimum volume requirements apply. We are not in the business of buying and selling natural gas and NGLs other than for system management purposes, but changes in the level of natural gas and NGLs 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

Bluegrass Project

In the second quarter 2013, we executed an agreement with the Williams Companies, Inc. (Williams) to continue the development process for the Bluegrass Project - a project that would transport NGLs from the Marcellus and Utica shale plays to the rapidly expanding petrochemical and export complex on the U.S. Gulf Coast, and related fractionation and storage facilities.

The proposed project would include constructing a new pipeline that would initially provide producers with 200,000 barrels per day of mixed NGLs take-away capacity in Ohio, West Virginia and Pennsylvania to an interconnect with our Texas Gas Transmission, LLC (Texas Gas) pipeline in Hardinsburg, Kentucky. Capacity could be increased to 400,000 barrels per day to meet market demand, primarily by adding additional liquids pumping capacity. From the interconnect with Texas Gas to Eunice, La., a portion of the Texas Gas pipeline (Texas Gas Loop Line) would be converted from natural gas service to NGL service. The joint venture would also construct a new large-scale fractionation plant, expand natural gas liquids storage facilities in Louisiana and construct a new pipeline connecting these facilities to the converted Texas Gas Loop Line. The joint venture is also exploring development of a new export liquefied petroleum gas terminal and related facilities on the Gulf Coast to provide customers access to international markets.

To effectuate the Bluegrass Project: (i) we entered into separate joint venture arrangements with Boardwalk Pipelines Holding Corp. (BPHC) to form Boardwalk Bluegrass Pipeline, LLC (Boardwalk Bluegrass) and Boardwalk Moss Lake, LLC (Boardwalk Moss Lake); and (ii) Boardwalk Bluegrass and Boardwalk Moss Lake, together with affiliates of Williams, formed Bluegrass Pipeline Company LLC (Bluegrass Pipeline) and Moss Lake Fractionation LLC (Moss Lake) to continue to pursue and, if approved, develop, own and construct the pipeline and the fractionation facility. Boardwalk Bluegrass and Boardwalk Moss Lake currently own 50% of the equity interests in Bluegrass Pipeline and Moss Lake respectively, with affiliates of Williams owning the other 50%.

We have contributed a total of $10.0 million to the capital of Boardwalk Bluegrass and Boardwalk Moss Lake. BPHC has agreed to contribute up to an aggregate of $100 million to these entities to fund certain agreed upon pre-construction development costs, with BPHC contributing all additional required capital until such time as BPHC has a 90% equity ownership interest in each entity. We anticipate that total pre-construction development costs to be funded by Boardwalk Bluegrass and Boardwalk Moss Lake in 2013 will be approximately $110.0 million (inclusive of amounts funded to date). Additional capital required for Boardwalk Bluegrass and Boardwalk Moss Lake to continue to pursue the Bluegrass Project is subject to approval by us and BPHC.

Through our agreement, we and Williams are engaged in comprehensive project development activities including project design, cost estimating, economic and risk analysis, permitting, other legal and regulatory approvals and right-of-way acquisition.

We are working with Williams to develop customer support for the pipeline and expect that the Bluegrass Pipeline will conduct an open season later this year.

Sanctioning and completion of this project is subject to, among other conditions, execution of customer contracts sufficient to support the project and the parties' receipt of all necessary approvals, including board approvals and regulatory approvals, such as antitrust clearance under the Hart-Scott-Rodino Antitrust Improvements Act and approvals by the Federal Energy Regulatory Commission (FERC), among others. Before the Texas Gas Loop Line can be converted to NGL service, Texas Gas must receive abandonment authority from FERC. The abandonment application was filed with FERC in May 2013 and we estimate the abandonment process will take between nine and twelve months. In addition, each of the parties has the right, under certain circumstances, to withdraw from the project or from portions of the project, in which case the project may be terminated, only portions of the project may be completed, or the parties respective ownership interests in the project may change. We cannot give assurances that this project will be completed, in whole or in part. However, if all conditions are satisfied and the parties elect to construct the facilities described above, the project could be placed into service in late 2015.

Market Conditions and Contract Renewals

Key drivers that influence the rates and terms of our transportation contracts are the current and anticipated basis spreads - generally meaning the difference in the price of natural gas at receipt and delivery points on our natural gas pipeline systems - which influence how much customers are willing to pay to transport gas between those points. Basis differentials can be affected by, among other things, the availability and supply of natural gas, competition from other pipelines, including pipelines under development, available transportation and storage capacity, storage inventories, regulatory developments, weather and general market demand in markets served by our pipeline systems. As new sources of natural gas have been identified and developed, including the Marcellus and the Utica Shales which are closer to the traditional high value markets served by interstate pipelines like us, and pipeline infrastructure has been developed to move the new sources of gas to market areas, changes in pricing dynamics between supply basins, pooling points and market areas have occurred. As a result of the new sources of supply and related pipeline infrastructure, basis spreads on our pipeline systems have narrowed significantly over the past several years, reducing the transportation rates we can typically negotiate with our customers on contracts due for renewal for our firm transportation services.

As of June 30, 2013, a substantial portion of our transportation capacity was contracted for under firm transportation agreements having a weighted-average remaining life of approximately 5.7 years. Each year a portion of our firm transportation agreements expire and must be renewed or replaced. Due to the factors noted above, in recent years the rates we have been able to obtain under firm and interruptible transportation agreements have declined and the amount of our capacity that we have been able to contract for under long-term firm transportation agreements has also declined. The amount of our transportation capacity under agreements which expire in 2013 is greater than in recent years. In light of the market conditions discussed above, transportation contracts we have renewed or entered into in 2013 have been at lower rates, and any remaining available capacity will be marketed and sold on a short-term firm or interruptible basis, which we also expect to be at lower rates. These circumstances have negatively affected, and are expected to continue to negatively affect, our transportation revenues, EBITDA and distributable cash flows in 2013.

The market for storage and PAL services is also impacted by the factors discussed above, as well as by natural gas price differentials between time periods, such as winter to summer (time period price spreads). Based on current forward pricing curves, time period price spreads for 2013 are not as favorable as they were in 2012. However, forward pricing curves change frequently as a result of a variety of market factors (including weather, levels of storage gas, and available capacity, among others) and as such may not be a reliable predictor of actual future events. Accordingly, we cannot predict our future revenues from interruptible storage and PAL services due to the uncertainty and volatility in market conditions discussed above. While our PAL revenues for the six months ended June 30, 2013, were higher as compared to the same period for 2012, the majority of the revenues recognized in 2013 were a result of PAL transactions entered into in the latter half of 2012 when time period price spreads were more favorable.

Results of Operations for the Three Months Ended June 30, 2013 and 2012

Our net income attributable to controlling interests for the three months ended June 30, 2013, increased $5.4 million, or 8%, to $70.5 million compared to $65.1 million for the three months ended June 30, 2012. The increase in net income was a result of the items discussed below.

Operating revenues for the three months ended June 30, 2013, increased $12.9 million, or 5%, to $288.7 million, compared to $275.8 million for the three months ended June 30, 2012. The increase was primarily due to $24.2 million of revenues from Louisiana Midstream and increased revenues from fuel of $6.2 million mainly from higher natural gas prices. The increase in operating revenues was partially offset by lower transportation revenues, excluding fuel, of $16.1 million resulting primarily from lower firm and interruptible revenues due to the market and contract renewal conditions discussed above and mild weather.

Operating costs and expenses for the three months ended June 30, 2013, increased $10.3 million, or 6%, to $177.6 million, compared to $167.3 million for the three months ended June 30, 2012. The increase in operating expenses was driven by the acquisition of Louisiana Midstream, which incurred $16.1 million of operating expenses, and increased fuel costs of $7.9 million due to higher natural gas prices, partially offset by a $17.0 million gain from the sale of storage base gas, sold as a result of a strategy to monetize base gas and provide capacity for additional storage and parks of customer gas under PAL services.

Total other deductions for the three months ended June 30, 2013 decreased by $2.7 million, or 6%, to $40.6 million compared to $43.3 million for the 2012 period, driven by increased capitalized interest and lower interest rates on long-term debt.

Results of Operations for the Six Months Ended June 30, 2013 and 2012

Our net income attributable to controlling interests for the six months ended June 30, 2013, increased $14.2 million, or 9%, to $171.9 million compared to $157.7 million for the six months ended June 30, 2012. The increase in net income was a result of the items discussed below.

Operating revenues for the six months ended June 30, 2013, increased $28.5 million, or 5%, to $617.2 million, compared to $588.7 million for the six months ended June 30, 2012. The increase was primarily due to $43.2 million of revenues from Louisiana Midstream and increased revenues from fuel of $13.3 million resulting mainly from higher natural gas prices. The increase in revenues was partially offset by lower transportation revenues, excluding fuel, of $29.8 million resulting primarily from lower firm and interruptible revenues due to the market and contract renewal conditions discussed above.

Operating costs and expenses for the six months ended June 30, 2013, increased $17.8 million, or 5%, to $364.4 million, compared to $346.6 million for the six months ended June 30, 2012. The increase in operating expenses was driven by the acquisition of Louisiana Midstream, which incurred $28.7 million of operating expenses, and increased fuel costs of $11.3 million due to higher natural gas prices, partially offset by a $17.0 million gain from the sale of storage base gas discussed above. The 2012 period was negatively impacted by asset impairment charges of $7.1 million related to the retirement of certain small-diameter pipeline assets and the sale of our Owensboro, Kentucky, office facilities.

Total other deductions for the six months ended June 30, 2013 decreased by $3.4 million, or 4%, to $80.7 million compared to $84.1 million for the 2012 period, driven by increased capitalized interest.

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 common units representing limited partner interest in us. We have no material guarantees of debt or other similar commitments to unaffiliated parties.

We anticipate that our existing capital resources, including our revolving credit facility and future cash flows will be adequate to fund our operations, including our maintenance capital expenditures. We may seek to access the capital markets to fund some or all of our growth capital expenditures, acquisitions or for general corporate purposes, including to refinance all or a portion of our indebtedness, a significant amount of which matures in the next five years. Our ability to access the capital markets for equity and debt financing under reasonable terms depends on our financial condition, credit ratings and market conditions.

As discussed under Bluegrass Project, we have entered into agreements with BPHC under which we made an initial contribution of $10.0 million in total for an approximate 60% equity ownership interest in each of Boardwalk Bluegrass and Boardwalk Moss Lake. In the second quarter, BPHC made contributions of $19.7 million to Boardwalk Bluegrass and Boardwalk Moss Lake. BPHC has agreed to contribute up to an aggregate of $100 million to these entities to fund certain agreed upon pre-construction development costs, with BPHC contributing all additional required capital until such time as BPHC has a 90% equity ownership interest in each entity. We anticipate that the development costs to be funded by Boardwalk Bluegrass and Boardwalk Moss Lake in 2013 will be approximately $110.0 million (inclusive of amounts funded to date). Additional capital required for Boardwalk Bluegrass and Boardwalk Moss Lake to continue to pursue the Bluegrass Project is subject to approval by us and BPHC.

Capital Expenditures and Investments

Maintenance capital expenditures for the six months ended June 30, 2013 and 2012 were $21.8 million and $36.4 million. Growth capital expenditures were $120.4 million and $54.5 million for the six months ended June 30, 2013 and 2012, including our capital contributions made to Boardwalk Bluegrass and Boardwalk Moss Lake for the 2013 period. The 2013 growth capital expenditures primarily relate to our Eagle Ford and Choctaw Brine Supply Expansion Projects discussed in our Annual Report on Form 10-K for the year ended December 31, 2012. We expect total capital expenditures to be approximately $360.0 million in 2013, including approximately $100.0 million for maintenance capital and $10.0 million of capital contributions made to Boardwalk Bluegrass and Boardwalk Moss Lake. Based on projected spending, we expect that BPHC will fund any remaining capital contributions required for Boardwalk Bluegrass and Boardwalk Moss Lake in 2013. We expect that Boardwalk Bluegrass and Boardwalk Moss Lake will contribute approximately $110.0 million to the Bluegrass Project in 2013 (inclusive of amounts funded to date).

Equity Financing

In May 2013, we completed a public offering of 12.7 million of our common units at a price of $30.12 per unit. We 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 our general partner to maintain its 2% general partner interest. The net proceeds were used to repay borrowings outstanding under our credit facility and to create funding for future capital growth projects.

Revolving Credit Facility

As of June 30, 2013, we had $20.0 million of loans outstanding under our revolving credit facility with a weighted-average interest rate of 1.32% and no letters of credit issued thereunder. At June 30, 2013, we had an available borrowing capacity of $980.0 million and were in compliance with all covenant requirements under our credit facility. For further information on our revolving credit facility, refer to Note 9 in Part I, Item 1 of this report.

Distributions

For the six months ended June 30, 2013 and 2012, we paid distributions of $256.4 million and $228.9 million to our partners. Note 8 in Part I, Item I of this report contains further discussion regarding our distributions.

As of June 30, 2013 and December 31, 2012, we had 22.9 million class B units outstanding. Holders of class B units participate in distribution on a pari passu basis with our common units, but only up to a maximum distribution of $0.30 per quarter. The class B units are convertible into common units on a one-for-one basis upon demand by the holder at any time after June 30, 2013. We expect the class B units to be converted in the third quarter 2013.

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 Annual Report on Form 10-K for the year ended December 31, 2012, for our full distribution policy and risks associated with it.

Changes in cash flow from operating activities

Net cash provided by operating activities increased slightly to $285.2 million for the six months ended June 30, 2013, compared to $284.3 million for the comparable 2012 period.

Changes in cash flow from investing activities

Net cash used in investing activities increased $47.9 million to $131.0 million for the six months ended June 30, 2013, compared to $83.1 million for the comparable 2012 period. The increase was primarily driven by an increase in capital expenditures of $41.3 million and the investment in the Bluegrass Project of $21.4 million.

Changes in cash flow from financing activities

Net cash used in financing activities decreased $63.5 million to $148.2 million for the six months ended June 30, 2013, compared to $211.7 million for the comparable 2012 period. The decrease in cash used in financing activities resulted primarily from an increase in the issuance and sale of common units which was invested in our growth projects, and the capital contribution received from BPHC for the investment in Boardwalk Bluegrass and Boardwalk Moss Lake.

Contractual Obligations

The following table summarizes significant contractual cash payment obligations under firm commitments as of June 30, 2013, 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⁾	$	3,270.0	$	—	$	525.0	$	1,255.0	$	1,490.0
Interest on long-term debt ⁽²⁾	900.7		150.1		280.3		208.1		262.2
Capital commitments ⁽³⁾	112.8		112.8		—		—		—
Total	$	4,283.5	$	262.9	$	805.3	$	1,463.1	$	1,752.2


(1)	Includes our senior unsecured notes, having maturity dates from 2015 to 2027, $20.0 million of loans outstanding under our revolving credit facility, having a maturity date of April 27, 2017, and $225.0 million loans outstanding under our Term Loan, having a maturity date of October 1, 2017.

(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 1.32% weighted-average interest rate and an unused commitment fee of 0.16% as of June 30, 2013, $1.8 million, $3.6 million and $1.5 million would be due in less than one year, 1-3 years and 3-5 years. Based on a 1.95% weighted average interest rate on amounts outstanding under the Term Loan as of June 30, 2013, $4.4 million, $8.8 million and $5.5 million would be due in less than one year, 1-3 years and 3-5 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 June 30, 2013.

Pursuant to the settlement of the Texas Gas Transmission, LLC (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 not contributed to the Texas Gas pension plan but expect to fund $3.0 million during 2013.

Off-Balance Sheet Arrangements

At June 30, 2013, 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 2013, there have been no significant changes to our critical accounting policies, judgments or estimates disclosed in our Annual Report on Form 10-K for the year ended December 31, 2012.

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;


•	the impact of FERC rate-making policies and actions on the services we offer, the rates we charge, our ability to recover the full cost of operating our pipelines, including earning a reasonable return, and overall business strategies such as converting a portion of the Texas Gas Loop Line to NGL service;


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


•	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;


•	the impact of changes to laws and regulations, such as the proposed greenhouse gas 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 expansion into new product lines and geographic areas;


•	volatility or disruptions in the capital or financial markets;


•	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


•	the additional risks and uncertainties as described in Part I, Item 1A, Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2012.

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 Annual Report on Form 10-K for the year ended December 31, 2012, for discussion of our market risk. There have not been any material updates to our market risk except for the following related to our commodity risk:

Our pipelines do not take title to the natural gas which they transport and store in rendering firm and interruptible transportation and storage services, therefore they do not assume the related natural gas commodity price risk associated with that gas. However, certain volumes of our gas stored underground are available for sale and subject to commodity price risk. At June 30, 2013 and December 31, 2012, approximately $1.4 million and $7.0 million of gas stored underground, which we own and carry as current Gas and liquids stored underground, was available for sale and exposed to commodity price risk. Additionally, at June 30, 2013, we had 9.7 Bcf of gas with a carrying amount of $22.0 million that had become available for sale as a result of a change in storage gas needed to support operations and no-notice services. We utilize derivatives to hedge certain exposures to market price fluctuations on the anticipated operational sales of gas. For further information on our derivatives, refer to Note 5 in Part I, Item 1 of this report.

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 June 30, 2013.

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 June 30, 2013, 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 7 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 Annual Report on Form 10-K for the year ended December 31, 2012.

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).
4.1		First Supplemental Indenture to the indenture dated November 21, 2006, among Boardwalk Pipelines, LP, as issuer, Boardwalk Pipeline Partners, LP, as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee (Incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on April 23, 2013).
4.2		Third Supplemental Indenture to the indenture dated August 21, 2009, among Boardwalk Pipelines, LP, as issuer, Boardwalk Pipeline Partners, LP, as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee (Incorporated by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K filed on April 23, 2013).
10.1		Boardwalk Operating GP, LLC Exempt Employee Annual Short-Term Incentive Plan (As Amended and Restated Effective January 1, 2013).
*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
July 30, 2013	By:	/s/ Jamie L. Buskill
		Jamie L. Buskill Senior Vice President, Chief Financial and Administrative Officer and Treasurer