13 Q3 BWP 10Q 9.30.13


 
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 September 30, 2013
OR

¨ 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 October 29, 2013, the registrant had 243,223,801 common units outstanding.
 



TABLE OF CONTENTS

FORM 10-Q

September 30, 2013

BOARDWALK PIPELINE PARTNERS, LP

PART I - FINANCIAL INFORMATION
 
 
 
 
 
 
 
 
 
 
 
 
 
PART II - OTHER INFORMATION
 
 
 
 
 
 
 
 
 
 


2


PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions)
(Unaudited)

ASSETS
September 30,
 2013
 
December 31, 2012
Current Assets:
 
 
 
Cash and cash equivalents
$
25.0

 
$
3.9

Receivables:
 

 
 

Trade, net
94.1

 
105.3

Affiliates
3.4

 
—

Other
19.6

 
6.9

Gas transportation receivables
4.2

 
9.0

Costs recoverable from customers
0.7

 
3.3

Gas and liquids stored underground
1.1

 
10.8

Prepayments
16.6

 
15.2

Other current assets
5.9

 
2.6

Total current assets
170.6

 
157.0

 
 
 
 
Property, Plant and Equipment:
 

 
 

Natural gas transmission and other plant
8,461.7

 
8,165.3

Construction work in progress
139.9

 
258.0

Property, plant and equipment, gross
8,601.6

 
8,423.3

Less—accumulated depreciation and amortization
1,410.7

 
1,234.1

Property, plant and equipment, net
7,190.9

 
7,189.2

 
 
 
 
Other Assets:
 

 
 

Goodwill
267.0

 
267.0

Gas stored underground
81.6

 
109.7

Investment in unconsolidated affiliates
28.1

 
—

Other
128.9

 
139.6

Total other assets
505.6

 
516.3

 
 
 
 
Total Assets
$
7,867.1

 
$
7,862.5


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

3


BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions)
(Unaudited)

LIABILITIES AND EQUITY
September 30,
 2013
 
December 31, 2012
Current Liabilities:
 
 
 
Payables:
 
 
 
Trade
$
34.7

 
$
69.8

Affiliates
0.7

 
2.7

Other
7.7

 
19.2

Gas Payables:
 

 
 

Transportation
8.4

 
10.4

Storage
—

 
3.5

Accrued taxes, other
66.8

 
40.5

Accrued interest
30.9

 
42.5

Accrued payroll and employee benefits
21.5

 
25.2

Deferred income
7.2

 
19.9

Other current liabilities
26.6

 
22.1

Total current liabilities
204.5

 
255.8

 
 
 
 
Long–term debt and capital lease obligations
3,333.9

 
3,539.2

 
 
 
 
Other Liabilities and Deferred Credits:
 

 
 

Pension liability
23.6

 
26.8

Asset retirement obligation
35.9

 
33.2

Provision for other asset retirement
59.4

 
57.4

Payable to affiliate
16.0

 
16.0

Other
59.4

 
57.0

Total other liabilities and deferred credits
194.3

 
190.4

 
 
 
 
Commitments and Contingencies


 


 
 
 
 
Equity:
 
 
 
Partners’ Capital:
 

 


Common units – 220.4 million units and 207.7 million units issued and
    outstanding as of September 30, 2013, and December 31, 2012
3,405.6

 
3,190.3

Class B units – 22.9 million units issued and outstanding as of
    September 30, 2013, and December 31, 2012
677.6

 
678.3

General partner
79.9

 
75.8

Accumulated other comprehensive loss
(68.3
)
 
(67.3
)
Total partners’ capital
4,094.8

 
3,877.1

Noncontrolling interest
39.6

 
—

Total Equity
4,134.4

 
3,877.1

Total Liabilities and Equity
$
7,867.1

 
$
7,862.5



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

4



BOARDWALK PIPELINE PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Millions)
(Unaudited)
 
For the
Three Months Ended
September 30,
 
 
For the
Nine Months Ended
September 30,
 
2013
 
2012
 
 
2013
 
2012
Operating Revenues:
 
 
 
 
 
 
 
 
Transportation
$
233.5

 
$
241.2

 
 
$
759.9

 
$
773.7

Parking and lending
4.9

 
8.3

 
 
19.9

 
20.1

Storage
27.4

 
18.3

 
 
82.9

 
57.0

Other
9.7

 
2.8

 
 
30.0

 
8.5

Total operating revenues
275.5

 
270.6

 
 
892.7

 
859.3

 
 
 
 
 
 
 
 
 
Operating Costs and Expenses:
 
 
 
 
 
 

 
 

Fuel and transportation
18.5

 
18.2

 
 
68.6

 
51.9

Operation and maintenance
47.0

 
40.1

 
 
131.0

 
119.6

Administrative and general
29.1

 
25.7

 
 
89.4

 
85.1

Depreciation and amortization
68.7

 
60.4

 
 
202.8

 
184.8

Asset impairment
—

 
1.1

 
 
1.2

 
8.2

Net (gain) loss on sale of operating assets
(13.0
)
 
0.5

 
 
(29.2
)
 
(3.1
)
Taxes other than income taxes
22.0

 
23.1

 
 
72.9

 
69.2

Total operating costs and expenses
172.3

 
169.1

 
 
536.7

 
515.7

 
 
 
 
 
 
 
 
 
Operating income
103.2

 
101.5

 
 
356.0

 
343.6

 
 
 
 
 
 
 
 
 
Other Deductions (Income):
 
 
 
 
 
 

 
 

Interest expense
41.0

 
41.5

 
 
122.2

 
122.0

Interest expense – affiliates
—

 
2.0

 
 
—

 
6.0

Interest income
(0.1
)
 
(0.2
)
 
 
(0.4
)
 
(0.4
)
Equity losses in unconsolidated affiliates
0.6

 
—

 
 
0.6

 
—

Miscellaneous other income, net
—

 
(0.1
)
 
 
(0.2
)
 
(0.3
)
Total other deductions
41.5

 
43.2

 
 
122.2

 
127.3

 
 
 
 
 
 
 
 
 
Income before income taxes
61.7

 
58.3

 
 
233.8

 
216.3

 
 
 
 
 
 
 
 
 
Income taxes
—

 
0.1

 
 
0.3

 
0.4

 
 
 
 
 
 
 
 
 
Net Income
61.7

 
58.2

 
 
233.5

 
215.9

Net loss attributable to noncontrolling interests
(0.6
)
 
—

 
 
(0.7
)
 
—

Net income attributable to controlling interests
$
62.3

 
$
58.2

 
 
$
234.2

 
$
215.9

 
 
 
 
 
 
 
 
 
Net Income per Unit:
 
 
 
 
 
 

 
 

Basic net income per unit:
 
 
 
 
 
 

 
 

Common units
$
0.27

 
$
0.26

 
 
$
0.96

 
$
0.99

Class B units
$
(0.32
)
 
$
(0.02
)
 
 
$
(0.11
)
 
$
0.21

Weighted-average number of units outstanding - basic:
 
 
 
 
 
 

 
 

Common units
220.4

 
192.6

 
 
213.5

 
186.8

Class B units
22.9

 
22.9

 
 
22.9

 
22.9

Diluted net income per unit:
 
 
 
 
 
 
 
 
Common units
$
0.21

 
$
0.26

 
 
$
0.90

 
$
0.99

Class B units
$
—

 
$
(0.02
)
 
 
$
0.19

 
$
0.21

Weighted-average number of units outstanding - diluted:
 
 
 
 
 
 
 
 
Common units
243.2

 
192.6

 
 
221.2

 
186.8

Class B units
—

 
22.9

 
 
15.2

 
22.9

Cash distribution declared and paid to common units
$
0.5325

 
$
0.5325

 
 
$
1.5975

 
$
1.595

Cash distribution declared and paid to class B units
$
0.30

 
$
0.30

 
 
$
0.90

 
$
0.90


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

5




BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions)
(Unaudited)

 
For the
Three Months Ended
September 30,
 
 
For the
Nine Months Ended
September 30,
 
2013
 
2012
 
 
2013
 
2012
Net income
$
61.7

 
$
58.2

 
 
$
233.5

 
$
215.9

Other comprehensive income (loss):
 
 
 
 
 
 

 
 

(Loss) gain on cash flow hedges
—

 
(0.6
)
 
 
2.5

 
(7.2
)
Reclassification adjustment transferred to Net Income from cash flow hedges
(0.6
)
 
0.6

 
 
0.5

 
1.1

Pension and other postretirement benefit costs
(0.4
)
 
(1.8
)
 
 
(4.0
)
 
(5.3
)
Total Comprehensive Income
60.7

 
56.4

 
 
232.5

 
204.5

Comprehensive loss attributable to noncontrolling interests
(0.6
)
 
—

 

(0.7
)

—

Comprehensive income attributable to controlling interests
$
61.3

 
$
56.4

 
 
$
233.2

 
$
204.5


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

6



BOARDWALK PIPELINE PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
(Unaudited)
 
For the
Nine Months Ended
September 30,
OPERATING ACTIVITIES:
2013
 
2012
Net income
$
233.5

 
$
215.9

Adjustments to reconcile net income to cash provided by operations:
 

 
 

Depreciation and amortization
202.8

 
184.8

Amortization of deferred costs
4.0

 
4.4

Asset impairment
1.2

 
8.2

Net gain on sale of operating assets
(29.2
)
 
(3.1
)
Equity losses in unconsolidated affiliates
0.6

 
—

Changes in operating assets and liabilities:
 

 
 

Trade and other receivables
(4.6
)
 
25.5

Other receivables, affiliates
0.8

 
(0.1
)
Gas receivables and storage assets
27.3

 
(7.2
)
Costs recoverable from customers
2.6

 
5.6

Other assets
(5.6
)
 
(15.1
)
Trade and other payables
(26.3
)
 
(8.9
)
Other payables, affiliates
0.2

 
(1.1
)
Gas payables
(5.8
)
 
3.7

Accrued liabilities
11.6

 
7.7

Other liabilities
(11.1
)
 
(6.2
)
Net cash provided by operating activities
402.0

 
414.1

 
 
 
 
INVESTING ACTIVITIES:
 

 
 

Capital expenditures
(204.3
)
 
(135.5
)
Proceeds from sale of operating assets
48.6

 
5.6

Proceeds from insurance and other recoveries
1.4

 
10.4

Advances to affiliates
(2.8
)
 
—

Investment in unconsolidated affiliates
(25.6
)
 
—

Net cash used in investing activities
(182.7
)
 
(119.5
)
 
 
 
 
FINANCING ACTIVITIES:
 

 
 

Proceeds from long-term debt, net of issuance costs
—

 
296.5

Repayment of borrowings from long-term debt
—

 
(225.0
)
Proceeds from borrowings on revolving credit agreement
813.0

 
1,480.0

Repayment of borrowings on revolving credit agreement
(1,030.0
)
 
(1,588.5
)
Payments of financing fees related to revolving credit facility
—

 
(3.8
)
Repayment of borrowings from term loan
—

 
(200.0
)
Principal payment of capital lease obligation
(0.1
)
 
—

Advances from affiliate
(2.8
)
 
2.5

Repayment of contribution received related to predecessor equity
—

 
(284.8
)
Distributions paid
(392.0
)
 
(350.6
)
Capital contributions from noncontrolling interests
37.2

 
—

Proceeds from sale of common units
368.7

 
556.3

Capital contributions from general partner
7.8

 
11.8

Net cash used in financing activities
(198.2
)
 
(305.6
)
 Increase (decrease) in cash and cash equivalents
21.1

 
(11.0
)
Cash and cash equivalents at beginning of period
3.9

 
21.9

Cash and cash equivalents at end of period
$
25.0

 
$
10.9


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

7




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 (loss)
170.1

 
20.5

 
25.9

 
(0.6
)
 
—

 
—

 
215.9

Distributions paid
(301.2
)
 
(20.5
)
 
(28.9
)
 
—

 
—

 
—

 
(350.6
)
Sale of common units, net of related transactions costs
556.3

 
—

 
—

 
—

 
—

 
—

 
556.3

Capital contributions from general partner
—

 
—

 
11.8

 
—

 
—

 
—

 
11.8

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
—

 
—

 
—

 
—

 
(11.4
)
 
—

 
(11.4
)
Balance September 30, 2012
$
2,936.7

 
$
678.4

 
$
70.7

 
$
(0.8
)
 
$
(60.8
)
 
$
—

 
3,624.2

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance January 1, 2013
$
3,190.3

 
$
678.3

 
$
75.8

 
$
—

 
$
(67.3
)
 
$
—

 
$
3,877.1

Add (deduct):
 

 
 

 
 

 
 

 
 

 
 
 
 

Net income (loss)
185.1

 
19.9

 
29.2

 
—

 
—

 
(0.7
)
 
233.5

Distributions paid
(338.5
)
 
(20.6
)
 
(32.9
)
 
—

 
—

 
—

 
(392.0
)
Sale of common units, net of
    related transactions costs
368.7

 
—

 
—

 
—

 
—

 
—

 
368.7

Capital contributions from
    general partner
—

 
—

 
7.8

 
—

 
—

 
—

 
7.8

Capital contributions from
    noncontrolling interests
—

 
—

 
—

 
—

 
—

 
40.3

 
40.3

Other comprehensive loss
—

 
—

 
—

 
—

 
(1.0
)
 
—

 
(1.0
)
Balance September 30, 2013
$
3,405.6

 
$
677.6

 
$
79.9

 
$
—

 
$
(68.3
)
 
$
39.6

 
$
4,134.4


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

8


BOARDWALK PIPELINE PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1:  Basis of Presentation
    
Boardwalk Pipeline Partners, LP (the Partnership) is a Delaware limited partnership formed 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 October 29, 2013, Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned subsidiary of Loews Corporation (Loews), owned 125.6 million of the Partnership’s common units, and, through Boardwalk GP, LP (Boardwalk GP), an indirect wholly-owned subsidiary of BPHC, holds the 2% general partner interest and all of the incentive distribution rights (IDRs). As of October 29, 2013, the common units and general partner interest owned by BPHC represent approximately 53% of the Partnership’s equity interests, excluding the IDRs. At September 30, 2013, BPHC owned 22.9 million of the Partnership's Class B limited partner interests, which converted to common units on a one-for-one basis on October 9, 2013. The Partnership’s common units are traded under the symbol “BWP” on the New York Stock Exchange.

The accompanying unaudited condensed consolidated financial statements of the Partnership were prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) have been condensed or omitted pursuant to such rules and regulations. In the opinion of management, the accompanying condensed consolidated financial statements reflect all adjustments (consisting of only normal recurring accruals) necessary to present fairly the financial position as of September 30, 2013, and December 31, 2012, and the results of operations and comprehensive income for the three and nine months ended September 30, 2013 and 2012, and changes in cash flows and changes in equity for the nine months ended September 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 increased Operation and maintenance expense and decreased Net (gain) loss on sale of operating assets, by $0.7 million and $0.5 million for the three and nine months ended September 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.

 

9


Note 2: Investments  

Bluegrass Project

In 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, storage and export facilities. The proposed project would include constructing a new pipeline, a new large-scale fractionation plant and related liquids storage and transport facilities and a new export liquefied petroleum gas (LPG) terminal and related 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), Moss Lake Fractionation LLC (Moss Lake Fractionation) and Moss Lake LPG Terminal LLC (Moss Lake LPG) to pursue and, if approved, develop, own and construct the pipeline, fractionation and export LPG terminal facilities. Boardwalk Bluegrass currently owns 50% of the equity ownership interests in Bluegrass Pipeline, and Boardwalk Moss Lake currently owns 50% of the equity ownership interests in Moss Lake Fractionation and Moss Lake LPG 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 September 30, 2013, the Partnership held equity ownership interests of 18% and 23%, 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. In accordance with accounting literature applicable to consolidations, 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 the underlying investment entities.

The financial information of Boardwalk Bluegrass and Boardwalk Moss Lake was reported at historical carrying amounts in accordance with the accounting requirements applicable to transactions between entities under common control. As of September 30, 2013, the Partnership included in its Condensed Consolidated Balance Sheet the following balances that represent amounts recorded by Boardwalk Bluegrass and Boardwalk Moss Lake (in millions):

Cash
$
20.9

Other receivables
0.1

Investment in
  unconsolidated affiliates
28.1

Construction work in progress
3.7

Trade payables
3.2

Other payables
0.1

 
 


10



Bluegrass Pipeline, Moss Lake Fractionation and Moss Lake LPG

Bluegrass Pipeline, Moss Lake Fractionation and Moss Lake LPG 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, Moss Lake Fractionation or Moss Lake LPG, 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, Moss Lake Fractionation and Moss Lake LPG 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, Moss Lake Fractionation and Moss Lake LPG, which was $28.1 million as of September 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 September 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. For the period from August 16, 2012 through October 15, 2012, the acquisition and related expenses were initially financed through a joint venture with BPHC, whereby BPHC owned 65% of the equity interests of the joint venture and the Partnership owned the remaining 35%. On October 15, 2012, the Partnership acquired BPHC’s 65% equity ownership interest. The transaction was accounted for as a transaction between entities under common control, which required the Partnership to fully consolidate the joint venture from the date of its formation, or August 16, 2012. For the three and nine months ended September 30, 2012, the joint venture had incurred $1.2 million of acquisition costs. These costs have been retrospectively adjusted in the Condensed Consolidated Statements of Income, and resulted in an increase of Administrative and General expenses of $1.2 million, a decrease of Miscellaneous Other Income, net of $0.4 million and a decrease to Net Income of $0.8 million.

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 Condensed Consolidated Balance Sheet at December 31, 2012, 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.

11




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 137.7 trillion British thermal units (TBtu) of gas owned by third parties as of September 30, 2013. Assuming an average market price during September 2013 of $3.55 per million British thermal units (MMBtu), the market value of gas held on behalf of others was approximately $488.8 million. The Partnership held for storage approximately 3.6 million barrels (Mmbbls) of NGLs owed by third parties as of September 30, 2013, which had a market value of $99.9 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 September 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 6.0 TBtu. Assuming an average market price during September 2013 of $3.55 per MMBtu, the market value of that gas was approximately $21.3 million. As of September 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 $7.2 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 nine months ended September 30, 2013.

The table below identifies the Partnership's assets that were recorded at fair value at September 30, 2013. There were no liabilities recorded at fair value at September 30, 2013 (in millions):
 
 
 
Fair Value Measurements at
September 30, 2013
 
 
 
 
 
September 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
September 30, 2013
 
Total Gains (losses) for the nine months ended
September 30, 2013
Recurring fair value measurements – Assets
 
 
 
 
 
 
 
 
Derivatives
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
$
1.4

 
$
—

 
$
1.4

 
$
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


12


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
September 30, 2012
 
Total Gains (losses) for the nine months ended
September 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)
$
—

 
$
—

 
$
—

 
$
—

 
$
(1.1
)
 
$
(3.2
)
Assets held for sale (2)
—

 
—

 
—

 
—

 
—

 
(2.8
)
 
$
—

 
$
—

 
$
—

 
$
—

 
$
(1.1
)
 
$
(6.0
)
 
 
 
 
 
 
 
 
 
 
 
 

(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 $4.3 million was recorded for the nine months ended September 30, 2012, of which $2.2 million represent amounts related to the asset retirement obligations for these assets. Additionally, in the third quarter 2012, the Partnership determined that it would retire a turbine associated with one of its compressor stations, which had a carrying amount of $1.1 million. As a result, an asset impairment charge of $1.1 million was recorded for the three and nine months ended September 30, 2012.

(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 $0.6 million and $7.0 million of gas stored underground at September 30, 2013, and December 31, 2012, which the Partnership owns and carries on its balance sheet as current Gas and liquids stored underground. At September 30, 2013, approximately 3.0 billion cubic feet (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.

In the third quarter 2013, the Partnership entered into natural gas swaps to mitigate exposure associated with the purchase of 0.7 Bcf of natural gas for the future purchase of storage base gas for operational needs of Petal's cavern 12A which recently commenced operations. The derivatives were not designated as cash flow hedges and were marked to fair value through earnings, resulting in a loss of less than $0.1 million in Miscellaneous other income, net for the three and nine months ended September 30, 2013.

13



In September 2012, the Partnership settled $100.0 million notional amount of interest rate swaps outstanding associated with a $200.0 million term loan. 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 nine months ended September 30, 2012, the Partnership recognized interest expense of $0.9 million and $2.7 million related to the interest rate swaps.

In May 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. In June 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 September 30, 2013, and December 31, 2012, were included in the following captions in the Condensed Consolidated Balance Sheets (in millions):
 
Derivative Assets
 
Derivative Liabilities
 
September 30, 2013
 
December 31, 2012
 
September 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
 
$
1.1

 
Other current assets
 
$
0.1

 
Other current liabilities
 
$
—

 
Other current liabilities
 
$
0.1

 
Other non-current assets
 
$
0.3

 
Other non-current assets
 
$
—

 
Other non-current liabilities
 
$
—

 
Other non-current liabilities
 
$
—

    
The Partnership estimates that approximately $1.3 million of net losses from cash flow hedges reported in Accumulated other comprehensive income/(loss) (AOCI) as of September 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 September 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
$
—

 
Operating
revenues
 
$
—

 
N/A
 
$
—

 
 
 
Net gain on disposal of operating assets
 
1.2

 
 
 
 
Interest rate contracts (1)
—

 
Interest expense
 
(0.6
)
 
N/A
 
—

 
$
—

 
 
 
$
0.6

 
 
 
$
—


(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.


14


The amount of gains and losses from cash flow hedges recognized in the Condensed Consolidated Statements of Income for the three months ended September 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
$
(0.6
)
 
Operating
  revenues
 
$
—

 
N/A
 
$
—

Interest rate contracts (1)
—

 
Interest expense
 
(0.6
)
 
N/A
 
—

 
$
(0.6
)
 
 
 
$
(0.6
)
 
 
 
$
—


(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.


The amount of gains and losses from cash flow hedges recognized in the Condensed Consolidated Statements of Income for the nine months ended September 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)
 
$
—

 
N/A
 
$
—

 
 
 
Net gain on disposal of operating assets
 
1.2

 
 
 
 
Interest rate contracts (1)
—

 
Interest expense
 
(1.7
)
 
N/A
 
—

 
$
2.5

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


15


The amount of gains and losses from cash flow hedges recognized in the Condensed Consolidated Statements of Income for the nine months ended September 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
 
(1.4
)
 
N/A
 
—

 
$
(7.2
)
 
 
 
$
(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)
Gains of $0.2 million were recorded in Transportation revenues and gains of $0.1 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 September 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 were $1.4 million as of September 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 September 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 September 30, 2013, and December 31, 2012. The carrying amount of the Partnership's variable rate debt approximates fair value because the instruments bear a floating market-based interest rate.
    

16


The carrying amount and estimated fair values of the Partnership's financial assets and liabilities which are not recorded at fair value on the Condensed Consolidated Balance Sheets as of September 30, 2013, and December 31, 2012, were as follows (in millions):
As of September 30, 2013
 
 
 
 
Estimated Fair Value
Financial Assets
 
Carrying Amount
 
 
Level 1
 
Level 2
 
Level 3
 
Total
Cash and cash equivalents
 
$
25.0

 
 
$
25.0

 
$
—

 
$
—

 
$
25.0

 
 
 
 
 
 
 
 
 
 
 
 
Financial Liabilities
 
 

 
 
 

 
 

 
 

 
 

Long-term debt
 
$
3,323.8

(1) 
 
$
—

 
$
3,510.8

 
$
—

 
$
3,510.8



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


(1)
The carrying amount of long-term debt excludes a $10.1 million capital lease obligation.

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 September 30, 2013 (in millions):
 
 Cash Flow Hedges
 
 Pension and Other Postretirement Costs
 
Total
Beginning balance, July 1, 2013
$
(11.9
)
 
$
(55.4
)
 
$
(67.3
)
Gain (loss) recorded in accumulated other comprehensive loss
—

 
—

 
—

Reclassifications:
 
 
 
 
 
Transportation operating revenues
—

 
—

 
—

Other operating revenues
—

 
—

 
—

Disposal of assets
(1.2
)
 
—

 
(1.2
)
Interest expense
0.6

 
—

 
0.6

Administrative and general expense
—

 
(0.4
)
 
(0.4
)
 
 
 
 
 
 
Ending balance, September 30, 2013
$
(12.5
)
 
$
(55.8
)
 
$
(68.3
)


17


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 nine months ended September 30, 2013 (in millions):
 
 Cash Flow Hedges
 
 Pension and Other Postretirement Costs
 
Total
Beginning balance, January 1, 2013
$
(15.5
)
 
$
(51.8
)
 
$
(67.3
)
Gain (loss) recorded in accumulated other comprehensive loss
2.5

 
—

 
2.5

Reclassifications:
 
 
 
 
 
Transportation operating revenues
0.1

 
—

 
0.1

Other operating revenues
(0.1
)
 
—

 
(0.1
)
Disposal of Assets
(1.2
)
 
—

 
(1.2
)
Interest expense
1.7

 
—

 
1.7

Administrative and general expense
—

 
(4.0
)
 
(4.0
)
 
 
 
 
 
 
Ending balance, September 30, 2013
$
(12.5
)
 
$
(55.8
)
 
$
(68.3
)


Note 6: Property, Plant and Equipment (PPE)

Gas Sales

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

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 a compressor station 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 in the second quarter 2012.

Asset Impairments

The Partnership recognized $1.2 million of asset impairments for the nine months ended September 30, 2013 and $1.1 million and $8.2 million of asset impairments for the three and nine months ended September 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 nine lawsuits, including one purported class action suit, commenced by multiple plaintiffs in the Circuit Court of Mobile County, Alabama. The plaintiffs seek unspecified damages for personal injury and property damage

18


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

Southeast Louisiana Flood Protection Litigation

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

The outcome of 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 September 30, 2013, and December 31, 2012, the Partnership had an accrued liability of approximately $7.2 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 September 30, 2013, and December 31, 2012, approximately $2.2 million was recorded in Other current liabilities and approximately $5.0 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

19


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 installed certain emission controls on its compression engines in order to comply with EPA adopted regulations, which did not have a material effect on the Partnership's 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 September 30, 2013, were approximately $105.9 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.

Capital Lease

In 2012, the Partnership entered into an agreement to construct and lease an office building in Owensboro, Kentucky. The construction of the building was completed and the Partnership took possession of the building in the third quarter 2013, at which time the Partnership recorded a capital lease asset and obligation of $10.5 million. The office building lease has a term of fifteen years with two twenty year renewal options. Future commitments under this capital lease are as follows (in millions):
2013
$
1.0

2014
1.0

2015
1.0

2016
1.0

2017
1.1

Thereafter
10.8

Total minimum lease payments
15.9

Less amounts representing interest
(5.4
)
Present value of obligation under capital lease
10.5

Less: current portion of obligations under capital lease
    (recorded in other current liabilities)
(0.4
)
Long-term obligations under capital lease
$
10.1


Amortization of the office building under the capital lease is included in depreciation expense.




20



Note 8:  Cash Distributions and Net Income per Unit

Cash Distributions

In the third 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 October 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.

Basic net income per unit is calculated based on the weighted average number of units outstanding for the period. Diluted net income per unit is calculated assuming that the class B units converted on the date that they became convertible, or July 1, 2013.

The following table provides a reconciliation of net income and the assumed allocation of net income to the common and class B units for purposes of computing basic and diluted net income per unit for the three months ended September 30, 2013, (in millions, except per unit data):
 
Total
 
Common
Units
 
Class B
 Units
 
General Partner and IDRs
Net income
$
61.7

 
 
 
 
 
 
Less: Net loss attributable to noncontrolling interests
(0.6
)
 
 
 
 
 
 
Net income attributable to controlling interests
62.3

 
 
 
 
 
 
Declared distribution
141.9

 
$
129.5

 
$
—

 
$
12.4

Assumed allocation of undistributed net loss - basic
(79.6
)
 
(70.7
)
 
(7.3
)
 
(1.6
)
Assumed allocation of net income attributable to limited
    partner unitholders and general partner - basic
$
62.3

 
$
58.8

 
$
(7.3
)
 
$
10.8

Allocation for diluted earnings per unit
—

 
(7.3
)
 
7.3

 
—

Assumed allocation of net income attributable to limited
    partner unitholders and general partner - diluted
$
62.3

 
$
51.5

 
$
—

 
$
10.8

Weighted-average units outstanding - basic
 
 
220.4

 
22.9

 
 
Weighted-average units outstanding - diluted
 
 
243.2

 
—

 
 
Net income per unit - basic
 
 
$
0.27

 
$
(0.32
)
 
 
Net income per unit - diluted
 
 
$
0.21

 
$
—

 
 
    

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 three months ended September 30, 2012, (in millions, except per unit data):
 
Total
 
Common
Units
 
Class B
 Units
 
General Partner and IDRs
Net income
$
58.2

 
 
 
 
 
 
Less: Net loss attributable to predecessor equity
(0.8
)
 
 
 
 
 
 
Net income attributable to controlling interests
59.0

 
 
 
 
 
 
Declared distribution
128.2

 
$
110.6

 
$
6.8

 
$
10.8

Assumed allocation of undistributed net loss
(69.2
)
 
(60.6
)
 
(7.2
)
 
(1.4
)
Assumed allocation of net income attributable to limited
     partner unitholders and general partner
$
59.0

 
$
50.0

 
$
(0.4
)
 
$
9.4

Weighted-average units outstanding
 

 
192.6

 
22.9

 
 

Net income per unit
 

 
$
0.26

 
$
(0.02
)
 
 


The following table provides a reconciliation of net income and the assumed allocation of net income to the common and class B units for purposes of computing basic and diluted net income per unit for the nine months ended September 30, 2013, (in millions, except per unit data):
 
Total
 
Common
Units
 
Class B
 Units
 
General Partner and IDRs
Net income
$
233.5

 
 
 
 
 
 
Less: Net loss attributable to noncontrolling interests
(0.7
)
 
 
 
 
 
 
Net income attributable to controlling interests
234.2

 
 
 
 
 
 
Declared distribution
405.7

 
$
357.5

 
$
13.7

 
$
34.5

Assumed allocation of undistributed net loss - basic
(171.5
)
 
(151.9
)
 
(16.2
)
 
(3.4
)
Assumed allocation of net income attributable to limited
    partner unitholders and general partner - basic
$
234.2

 
$
205.6

 
$
(2.5
)
 
$
31.1

Allocation for diluted earnings per unit
—

 
(5.4
)
 
5.4

 
—

Assumed allocation of net income attributable to limited
    partner unitholders and general partner - diluted
$
234.2

 
$
200.2

 
$
2.9

 
31.1

Weighted-average units outstanding - basic
 
 
213.5

 
22.9

 
 
Weighted-average units outstanding - diluted
 
 
221.2

 
15.2

 
 
Net income per unit - basic
 
 
$
0.96

 
$
(0.11
)
 
 
Net income per unit - diluted
 
 
$
0.90

 
$
0.19

 
 
    

22


The following table provides a reconciliation of net income and the assumed allocation of net income to the common and class B units for purposes of computing net income per unit for the nine months ended September 30, 2012, (in millions, except per unit data):
 
Total
 
Common
Units
 
Class B
 Units
 
General Partner and IDRs
Net income
$
215.9

 
 
 
 
 
 
Less: Net loss attributable to predecessor equity
(0.6
)
 
 
 
 
 
 
Net income attributable to controlling interests
216.5

 
 
 
 
 
 
Declared distribution
364.8

 
$
313.7

 
$
20.6

 
$
30.5

Assumed allocation of undistributed net loss
(148.3
)
 
(129.5
)
 
(15.8
)
 
(3.0
)
Assumed allocation of net income attributable to limited
     partner unitholders and general partner
$
216.5

 
$
184.2

 
$
4.8

 
$
27.5

Weighted-average units outstanding
 

 
186.8

 
22.9

 
 

Net income per unit
 

 
$
0.99

 
$
0.21

 
 



Note 9:  Financing

Notes and Debentures

As of September 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 September 30, 2013, the Partnership and its subsidiaries were in compliance with its debt covenants.

Issuance of Notes

During the nine months ended September 30, 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.

Redemption/Retirement of Notes
    
In August 2012, $225.0 million aggregate principal amount of 5.75% notes due 2012 at Gulf South matured and were retired in full. The retirement of this debt was financed through borrowings under the revolving credit facility.

Revolving Credit Facility

Outstanding borrowings under the Partnership’s revolving credit facility as of September 30, 2013, and December 31, 2012, were $85.0 million and $302.0 million, with a weighted-average borrowing rate of 1.30% 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

23


up to 5.5 to 1.0 for the three quarters following an acquisition. The Partnership and its subsidiaries were in compliance with all covenant requirements under the credit facility as of September 30, 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 September 30, 2013 and December 31, 2012, were $225.0 million, with a weighted-average borrowing interest rate of 1.94% and 1.96%.

The Partnership's HP Storage subsidiary had a $200.0 million variable rate term loan due December 1, 2016 (HP Storage Term Loan), that was repaid in full in September 2012. Interest on the HP Storage Term Loan was payable monthly at a rate that was based on the one-month LIBOR rate plus an applicable margin. There is no further borrowing capacity under this term loan.
 
Common Unit Offering

For the nine months ended September 30, 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
 
220.3
 
117.6
August 2012 (1)
 
11.6
 
$27.80
 
$11.2
 
$317.9
 
196.5
 
93.8
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
revolving credit facility.

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

Class B Units

On October 9, 2013, all of the 22.9 million class B units were converted into common units on a one-for-one basis, pursuant to the terms of the partnership agreement. After the conversion, the Partnership had 243.2 million outstanding common units.
    
    

24



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 September 30, 2013 and 2012 were as follows (in millions):
 
Retirement Plans
 
PBOP
 
For the
Three Months Ended
September 30,
 
For the
Three Months Ended
September 30,
 
2013
 
2012
 
2013
 
2012
Service cost
$
0.8

 
$
1.0

 
$
0.1

 
$
0.1

Interest cost
1.3

 
1.4

 
0.6

 
0.6

Expected return on plan assets
(2.4
)
 
(2.1
)
 
(1.1
)
 
(1.1
)
Amortization of prior service credit
—

 
—

 
(2.0
)
 
(1.9
)
Amortization of unrecognized net loss
0.6

 
0.5

 
—

 
—

Settlement charge
1.3

 
—

 
—

 
—

Net periodic benefit cost
$
1.6

 
$
0.8

 
$
(2.4
)
 
$
(2.3
)


Components of net periodic benefit cost for both the Retirement Plans and PBOP for the nine months ended September 30, 2013 and 2012 were as follows (in millions):
 
Retirement Plans
 
PBOP
 
For the
Nine Months Ended
September 30,
 
For the
Nine Months Ended
September 30,
 
2013
 
2012
 
2013
 
2012
Service cost
$
3.0

 
$
3.0

 
$
0.3

 
$
0.3

Interest cost
3.7

 
4.3

 
1.5

 
1.8

Expected return on plan assets
(6.9
)
 
(6.4
)
 
(3.3
)
 
(3.2
)
Amortization of prior service credit
—

 
—

 
(5.8
)
 
(5.8
)
Amortization of unrecognized net loss
1.8

 
1.5

 
—

 
0.1

Settlement charge
1.3

 
$
—

 
$
—

 
$
—

Net periodic benefit cost
$
2.9

 
$
2.4

 
$
(7.3
)
 
$
(6.8
)

Through the date of this filing, the Partnership contributed $3.0 million to the Pension Plan and does not expect to fund further amounts 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 $1.9 million for the three months ended September 30, 2013 and 2012, and were $6.6 million and $6.0 million for the nine months ended September 30, 2013 and 2012.


25



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 and $1.0 million for the three months ended September 30, 2013 and 2012. The Partnership incurred charges related to these services of $6.3 million and $6.9 million for the nine months ended September 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 $72.9 million and $71.7 million during the three months ended September 30, 2013 and 2012 and $217.6 million and $213.3 million for the nine months ended September 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 nine months ended September 30, 2013, the Partnership contributed $10.0 million and BPHC contributed $40.3 million of cash and assets to these entities.

    

Note 12:  Supplemental Disclosure of Cash Flow Information (in millions):
 
For the
Nine Months Ended
September 30,
 
2013
 
2012
Cash paid during the period for:
 
 
 
Interest (net of amount capitalized)
$
126.9

 
$
142.3

Non-cash adjustments:
 
 
 
Capital lease obligations incurred
10.5

 
$
—




26



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 September 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.

    













27


Condensed Consolidating Balance Sheets as of September 30, 2013
(Millions)

Assets
 
Parent
Guarantor
 
Subsidiary
Issuer
 
Non-guarantor Subsidiaries
 
Eliminations
 
Consolidated Boardwalk Pipeline Partners, LP
Cash and cash equivalents
 
$
0.2

 
$
2.1

 
$
22.7

 
$
—

 
$
25.0

Receivables
 
—

 
—

 
113.7

 
—

 
113.7

Receivables - affiliate
 
2.8

 
—

 
7.3

 
(6.7
)
 
3.4

Gas and liquids stored underground
 
—

 
—

 
1.1

 
—

 
1.1

Prepayments
 
0.3

 
0.1

 
16.2

 
—

 
16.6

Other current assets
 
0.1

 
—

 
15.0

 
(4.3
)
 
10.8

Total current assets
 
3.4

 
2.2

 
176.0

 
(11.0
)
 
170.6

Investment in consolidated subsidiaries
 
1,465.1

 
6,093.6

 
—

 
(7,558.7
)
 
—

Property, plant and equipment, gross
 
0.6

 
—

 
8,601.0

 
—

 
8,601.6

Less–accumulated depreciation and
    amortization
 
0.6

 
—

 
1,410.1

 
—

 
1,410.7

Property, plant and equipment, net
 
—

 
—

 
7,190.9

 
—

 
7,190.9

Other noncurrent assets
 
—

 
4.2

 
473.4

 
(0.1
)
 
477.5

Advances to affiliates – noncurrent
 
2,643.4

 
155.4

 
753.3

 
(3,552.1
)
 
—

Investment in unconsolidated affiliates
 
—

 
—

 
28.1

 
—

 
28.1

Total other assets
 
2,643.4

 
159.6


1,254.8


(3,552.2
)

505.6

 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
4,111.9

 
$
6,255.4

 
$
8,621.7

 
$
(11,121.9
)
 
$
7,867.1


Liabilities and Equity
 
Parent
Guarantor
 
Subsidiary
Issuer
 
Non-guarantor Subsidiaries
 
Eliminations
 
Consolidated Boardwalk Pipeline Partners, LP
Payables
 
$
0.4

 
$
—

 
$
42.0

 
$
—

 
$
42.4

Payable to affiliates
 
0.7

 
—

 
6.7

 
(6.7
)
 
0.7

Other current liabilities
 
—

 
14.0

 
151.6

 
(4.2
)
 
161.4

Total current liabilities
 
1.1

 
14.0

 
200.3

 
(10.9
)
 
204.5

Total long-term debt and capital lease
    obligation
 
—

 
1,379.6

 
1,954.3

 
—

 
3,333.9

Payable to affiliate
 
16.0

 
3,396.7

 
155.4

 
(3,552.1
)
 
16.0

Other noncurrent liabilities
 
—

 
—

 
178.5

 
(0.2
)
 
178.3

Total other liabilities and deferred
    credits
 
16.0

 
3,396.7

 
333.9

 
(3,552.3
)
 
194.3

Total partners’ capital/member’s equity
 
4,094.8

 
1,465.1

 
6,093.6

 
(7,558.7
)
 
4,094.8

Noncontrolling interest
 
—

 
—

 
39.6

 
—

 
39.6

Total Equity
 
4,094.8

 
1,465.1

 
6,133.2

 
(7,558.7
)
 
4,134.4

Total Liabilities and Equity
 
$
4,111.9

 
$
6,255.4

 
$
8,621.7

 
$
(11,121.9
)
 
$
7,867.1


28


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









29


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

 
Parent
Guarantor
 
Subsidiary
Issuer
 
Non-guarantor Subsidiaries
 
Eliminations
 
Consolidated Boardwalk Pipeline Partners, LP
Operating Revenues:
 
 
 
 
 
 
 
 
 
Transportation
$
—

 
$
—

 
$
255.8

 
$
(22.3
)
 
$
233.5

Parking and lending
—

 
—

 
4.9

 
—

 
4.9

Storage
—

 
—

 
27.4

 
—

 
27.4

Other
—

 
—

 
9.7

 
—

 
9.7

Total operating revenues
—

 
—

 
297.8

 
(22.3
)
 
275.5

 
 
 
 
 
 
 
 
 
 
Operating Cost and Expenses:
 

 
 

 
 
 
 
 
 
Fuel and transportation
—

 
—

 
40.8

 
(22.3
)
 
18.5

Operation and maintenance
—

 
—

 
47.0

 
—

 
47.0

Administrative and general
—

 
—

 
29.1

 
—

 
29.1

Other operating costs and expenses
0.2

 
—

 
77.5

 
—

 
77.7

Total operating costs and expenses
0.2

 
—

 
194.4

 
(22.3
)
 
172.3

Operating (loss) income
(0.2
)
 
—

 
103.4

 
—

 
103.2

 
 
 
 
 
 
 
 
 
 
Other Deductions (Income):
 

 
 
 
 
 
 
 
 
Interest expense
—

 
18.7

 
22.3

 
—

 
41.0

Interest (income) expense, affiliate,
   net
(8.8
)
 
10.4

 
(1.6
)
 
—

 
—

Interest income
—

 
—

 
(0.1
)
 
—

 
(0.1
)
Equity in earnings of subsidiaries
(53.7
)
 
(82.8
)
 
—

 
136.5

 
—

Equity losses in unconsolidated
    affiliates
—

 
—

 
0.6

 
—

 
0.6

Total other (income) deductions
(62.5
)
 
(53.7
)
 
21.2

 
136.5

 
41.5

 
 
 
 
 
 
 
 
 
 
Income before income taxes
62.3

 
53.7

 
82.2

 
(136.5
)
 
61.7

Income taxes
—

 
—

 
—

 
—

—

—

 
 
 
 
 
 
 
 
 
 
Net Income
62.3

 
53.7

 
82.2

 
(136.5
)
 
61.7

Net loss attributable to
    noncontrolling interests
—

 
—

 
(0.6
)
 
—

 
(0.6
)
Net income attributable to controlling
    interests
$
62.3

 
$
53.7

 
$
82.8

 
$
(136.5
)
 
$
62.3



30


Condensed Consolidating Statements of Income for the Three Months Ended September 30, 2012
(Millions)

 
Parent
Guarantor
 
Subsidiary
Issuer
 
Non-guarantor Subsidiaries
 
Eliminations
 
Consolidated Boardwalk Pipeline Partners, LP
Operating Revenues:
 
 
 
 
 
 
 
 
 
Transportation
$
—

 
$
—

 
$
264.0

 
$
(22.8
)
 
$
241.2

Parking and lending
—

 
—

 
8.3

 
—

 
8.3

Storage
—

 
—

 
18.7

 
(0.4
)
 
18.3

Other
—

 
—

 
2.8

 
—

 
2.8

Total operating revenues
—

 
—

 
293.8

 
(23.2
)
 
270.6

 
 
 
 
 
 
 
 
 
 
Operating Cost and Expenses:
 

 
 

 
 

 
 
 
 
Fuel and transportation
—

 
—

 
41.4

 
(23.2
)
 
18.2

Operation and maintenance
—

 
—

 
40.1

 
—

 
40.1

Administrative and general
0.7

 
—

 
25.0

 
—

 
25.7

Other operating costs and expenses
0.1

 
—

 
85.0

 
—

 
85.1

Total operating costs and expenses
0.8

 
—

 
191.5

 
(23.2
)
 
169.1

Operating income
(0.8
)
 
—

 
102.3

 
—

 
101.5

 
 
 
 
 
 
 
 
 
 
Other Deductions (Income):
 

 
 

 
 

 
 
 
 
Interest expense
—

 
15.3

 
26.2

 
—

 
41.5

Interest (income) expense, affiliate,
    net
(8.7
)
 
14.0

 
(3.3
)
 
—

 
2.0

Interest income
—

 
—

 
(0.2
)
 
—

 
(0.2
)
Equity in earnings of subsidiaries
(50.3
)
 
(79.6
)
 
—

 
129.9

 
—

Miscellaneous other income, net
—

 
—

 
(0.1
)
 
—

 
(0.1
)
Total other (income) deductions
(59.0
)
 
(50.3
)
 
22.6

 
129.9

 
43.2

 
 
 
 
 
 
 
 
 
 
Income before income taxes
58.2

 
50.3

 
79.7


(129.9
)
 
58.3

Income taxes
—

 
—

 
0.1

 
—

 
0.1

 
 
 
 
 
 
 
 
 
 
Net Income
$
58.2

 
$
50.3

 
$
79.6

 
$
(129.9
)
 
$
58.2




31


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

 
Parent
Guarantor
 
Subsidiary
Issuer
 
Non-guarantor Subsidiaries
 
Eliminations
 
Consolidated Boardwalk Pipeline Partners, LP
Operating Revenues:
 
 
 
 
 
 
 
 
 
Transportation
$
—

 
$
—

 
$
826.2

 
$
(66.3
)
 
$
759.9

Parking and lending
—

 
—

 
19.9

 
—

 
19.9

Storage
—

 
—

 
83.0

 
(0.1
)
 
82.9

Other
—

 
—

 
30.0

 
—

 
30.0

Total operating revenues
—

 
—

 
959.1

 
(66.4
)
 
892.7

 
 
 
 
 
 
 
 
 
 
Operating Cost and Expenses:
 

 
 

 
 
 
 
 
 
Fuel and transportation
—

 
—

 
135.0

 
(66.4
)
 
68.6

Operation and maintenance
—

 
0.3

 
130.7

 
—

 
131.0

Administrative and general
—

 
0.8

 
88.6

 
—

 
89.4

Other operating costs and expenses
0.3

 
0.1

 
247.3

 
—

 
247.7

Total operating costs and expenses
0.3

 
1.2

 
601.6

 
(66.4
)
 
536.7

Operating (loss) income
(0.3
)
 
(1.2
)
 
357.5

 
—

 
356.0

 
 
 
 
 
 
 
 
 
 
Other Deductions (Income):
 

 
 
 
 
 
 
 
 
Interest expense
—

 
53.9

 
68.3

 
—

 
122.2

Interest (income) expense, affiliate,
    net
(25.4
)
 
30.9

 
(5.5
)
 
—

 
—

Interest income
—

 
—

 
(0.4
)
 
—

 
(0.4
)
Equity in earnings of subsidiaries
(209.1
)
 
(295.1
)
 
—

 
504.2

 
—

Equity losses in unconsolidated
    affiliates
—

 
—

 
0.6

 
—

 
0.6

Miscellaneous other income, net
—

 
—

 
(0.2
)
 
—

 
(0.2
)
Total other (income) deductions
(234.5
)
 
(210.3
)
 
62.8

 
504.2

 
122.2

 
 
 
 
 
 
 
 
 
 
Income before income taxes
234.2

 
209.1

 
294.7

 
(504.2
)
 
233.8

Income taxes
—

 
—

 
0.3

 
—

 
0.3

 
 
 
 
 
 
 
 
 
 
Net Income
234.2

 
209.1

 
294.4

 
(504.2
)
 
233.5

Net loss attributable to
noncontrolling interests
—

 
—

 
(0.7
)
 
—

 
(0.7
)
Net income attributable to controlling
    interests
$
234.2

 
$
209.1

 
$
295.1

 
$
(504.2
)
 
$
234.2



32


Condensed Consolidating Statements of Income for the Nine Months Ended September 30, 2012
(Millions)

 
Parent
Guarantor
 
Subsidiary
Issuer
 
Non-guarantor Subsidiaries
 
Eliminations
 
Consolidated Boardwalk Pipeline Partners, LP
Operating Revenues:
 
 
 
 
 
 
 
 
 
Transportation
$
—

 
$
—

 
$
839.9

 
$
(66.2
)
 
$
773.7

Parking and lending
—

 
—

 
20.1

 
—

 
20.1

Storage
—

 
—

 
57.5

 
(0.5
)
 
57.0

Other
—

 
—

 
8.5

 
—

 
8.5

Total operating revenues
—

 
—

 
926.0

 
(66.7
)
 
859.3

 
 
 
 
 
 
 
 
 
 
Operating Cost and Expenses:
 

 
 

 
 

 
 
 
 
Fuel and transportation
—

 
—

 
118.6

 
(66.7
)
 
51.9

Operation and maintenance
—

 
—

 
119.6

 
—

 
119.6

Administrative and general
0.6

 
—

 
84.5

 
—

 
85.1

Other operating costs and expenses
0.2

 
—

 
258.9

 
—

 
259.1

Total operating costs and expenses
0.8

 
—

 
581.6

 
(66.7
)
 
515.7

Operating income
(0.8
)
 
—

 
344.4

 
—

 
343.6

 
 
 
 
 
 
 
 
 
 
Other Deductions (Income):
 

 
 

 
 

 
 
 
 
Interest expense
—

 
47.0

 
75.0

 
—

 
122.0

Interest (income) expense, affiliate,
    net
(26.5
)
 
41.4

 
(8.9
)
 
—

 
6.0

Interest income
—

 
—

 
(0.4
)
 
—

 
(0.4
)
Equity in earnings of subsidiaries
(190.2
)
 
(278.6
)
 
—

 
468.8

 
—

Miscellaneous other income, net
—

 
—

 
(0.3
)
 
—

 
(0.3
)
Total other (income) deductions
(216.7
)
 
(190.2
)
 
65.4

 
468.8

 
127.3

 
 
 
 
 
 
 
 
 
 
Income before income taxes
215.9

 
190.2

 
279.0

 
(468.8
)
 
216.3

Income taxes
—

 
—

 
0.4

 
—

 
0.4

 
 
 
 
 
 
 
 
 
 
Net Income
$
215.9

 
$
190.2

 
$
278.6

 
$
(468.8
)
 
$
215.9






33


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

 
Parent
Guarantor
 
Subsidiary
Issuer
 
Non-guarantor Subsidiaries
 
Eliminations
 
Consolidated Boardwalk Pipeline Partners, LP
Net Income
$
62.3

 
$
53.7

 
$
82.2

 
$
(136.5
)
 
$
61.7

Other comprehensive income (loss):
 

 
 

 
 

 
 
 
 
Reclassification adjustment transferred
    to Net Income from cash flow hedges
(0.6
)
 
(0.6
)
 
(1.0
)
 
1.6

 
(0.6
)
Pension and other postretirement
    benefit costs
(0.4
)
 
(0.4
)
 
(0.4
)
 
0.8

 
(0.4
)
Total Comprehensive Income
61.3

 
52.7

 
80.8

 
(134.1
)
 
60.7

Comprehensive loss attributable to
    noncontrolling interests
—

 
—

 
(0.6
)
 
—

 
(0.6
)
Comprehensive income attributable to
    controlling interests
$
61.3

 
$
52.7

 
$
81.4

 
$
(134.1
)
 
$
61.3



34


Condensed Consolidating Statements of Comprehensive Income for the Three Months Ended September 30, 2012
(Millions)

 
Parent
Guarantor
 
Subsidiary
Issuer
 
Non-guarantor Subsidiaries
 
Eliminations
 
Consolidated Boardwalk Pipeline Partners, LP
Net Income
$
58.2

 
$
50.3

 
$
79.6

 
$
(129.9
)
 
$
58.2

Other comprehensive income (loss):
 

 
 

 
 

 
 
 
 
(Loss) gain on cash flow hedges
(0.6
)
 
(0.6
)
 
(0.6
)
 
1.2

 
(0.6
)
Reclassification adjustment transferred
    to Net Income from cash flow hedges
0.6

 
0.6

 
0.2

 
(0.8
)
 
0.6

Pension and other postretirement
    benefit costs
(1.8
)
 
(1.8
)
 
(1.8
)
 
3.6

 
(1.8
)
Total Comprehensive Income
$
56.4

 
$
48.5

 
$
77.4

 
$
(125.9
)
 
$
56.4



35


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

 
Parent
Guarantor
 
Subsidiary
Issuer
 
Non-guarantor Subsidiaries
 
Eliminations
 
Consolidated Boardwalk Pipeline Partners, LP
Net Income
$
234.2

 
$
209.1

 
$
294.4

 
$
(504.2
)
 
$
233.5

Other comprehensive income (loss):
 

 
 

 
 

 
 
 

Gain (loss) on cash flow hedges
2.5

 
2.5

 
2.5

 
(5.0
)
 
2.5

Reclassification adjustment transferred
    to Net Income from cash flow hedges
0.5

 
0.5

 
(0.8
)
 
0.3

 
0.5

Pension and other postretirement
    benefit costs
(4.0
)
 
(4.0
)
 
(4.0
)
 
8.0

 
(4.0
)
Total Comprehensive Income
233.2

 
208.1

 
292.1

 
(500.9
)
 
232.5

Comprehensive loss attributable to
    noncontrolling interests
—

 
—

 
(0.7
)
 
—

 
(0.7
)
Comprehensive income attributable to
    controlling interests
$
233.2

 
$
208.1

 
$
292.8

 
$
(500.9
)
 
$
233.2



36


Condensed Consolidating Statements of Comprehensive Income for the Nine Months Ended September 30, 2012
(Millions)

 
Parent
Guarantor
 
Subsidiary
Issuer
 
Non-guarantor Subsidiaries
 
Eliminations
 
Consolidated Boardwalk Pipeline Partners, LP
Net Income
$
215.9

 
$
190.2

 
$
278.6

 
$
(468.8
)
 
$
215.9

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
1.1

 
1.1

 
(0.1
)
 
(1.0
)
 
1.1

Pension and other postretirement
    benefit costs
(5.3
)
 
(5.3
)
 
(5.3
)
 
10.6

 
(5.3
)
Total Comprehensive Income
$
204.5

 
$
178.8

 
$
266.0

 
$
(444.8
)
 
$
204.5



37




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

 
Parent
Guarantor
 
Subsidiary
 Issuer
 
Non-guarantor Subsidiaries
 
Eliminations
 
Consolidated Boardwalk Pipeline Partners, LP
Net Cash Provided by (Used In)
    Operating Activities
$
26.0

 
$
(86.3
)
 
$
462.3

 
$
—

 
$
402.0

 
 
 
 
 
 
 
 
 
 
Investing Activities:
 

 
 

 
 

 
 

 
 

Capital expenditures
—

 
—

 
(204.3
)
 
—

 
(204.3
)
Proceeds from sale of operating assets
—

 
—

 
48.6

 
—

 
48.6

Proceeds from insurance and other
    recoveries
—

 
—

 
1.4

 
—

 
1.4

Advances to affiliates, net
(7.6
)
 
(71.0
)
 
(168.7
)
 
244.5

 
(2.8
)
Investment in consolidated subsidiary
—

 
(15.1
)
 
—

 
15.1

 
—

Investment in unconsolidated affiliates
—

 
—

 
(25.6
)
 
—

 
(25.6
)
Net Cash (Used in) Provided
    by Investing Activities
(7.6
)
 
(86.1
)
 
(348.6
)
 
259.6

 
(182.7
)
 
 
 
 
 
 
 
 
 
 
Financing Activities:
 

 
 

 
 

 
 

 
 

Proceeds from borrowings on revolving
    credit agreement
—

 
—

 
813.0

 
—

 
813.0

Repayment of borrowings on revolving
    credit agreement
—

 
—

 
(1,030.0
)
 
—

 
(1,030.0
)
Contribution from parent
—

 
—

 
15.1

 
(15.1
)
 
—

Principal payment of capital lease
    obligation
—

 
—

 
(0.1
)
 
—

 
(0.1
)
Advances from affiliates, net
(2.8
)
 
173.5

 
71.0

 
(244.5
)
 
(2.8
)
Distributions paid
(392.0
)
 
—

 
—

 
—

 
(392.0
)
Capital contribution from noncontrolling
    interests
—

 
—

 
37.2

 
—

—

37.2

Proceeds from sale of common units
368.7

 
—

 
—

 
—

 
368.7

Capital contributions from general
    partner
7.8

 
—

 
—

 
—

 
7.8

Net Cash (Used in) Provided by
    Financing Activities
(18.3
)
 
173.5

 
(93.8
)
 
(259.6
)
 
(198.2
)
 
 
 
 
 
 
 
 
 
 
Increase in Cash and Cash
  Equivalents
0.1

 
1.1

 
19.9

 
—

 
21.1

Cash and Cash Equivalents at
  Beginning of Period
0.1

 
1.0

 
2.8

 
—

 
3.9

Cash and Cash Equivalents at End of
    Period
$
0.2

 
$
2.1

 
$
22.7

 
$
—

 
$
25.0


38


Condensed Consolidating Statements of Cash Flow for the Nine Months Ended September 30, 2012
(Millions)

 
Parent
Guarantor
 
Subsidiary
Issuer
 
Non-guarantor Subsidiaries
 
Eliminations
 
Consolidated Boardwalk Pipeline Partners, LP
Net Cash Provided by (Used In)
    Operating Activities
$
20.7

 
$
552.4

 
$
480.7

 
$
(639.7
)
 
$
414.1

 
 
 
 
 
 
 
 
 
 
Investing Activities:
 

 
 

 
 

 
 

 
 

Capital expenditures
—

 
—

 
(135.5
)
 
—

 
(135.5
)
Proceeds from sale of operating assets
—

 
—

 
5.6

 
—

 
5.6

Proceeds from insurance and other
    recoveries
—

 
—

 
10.4

 
—

 
10.4

Advances to affiliates, net
(223.9
)
 
(62.0
)
 
119.0

 
166.9

 
—

Investment in consolidated subsidiary
(17.0
)
 
(231.5
)
 
—

 
248.5

 
—

Net Cash (Used in) Provided by
    Investing Activities
(240.9
)
 
(293.5
)
 
(0.5
)
 
415.4

 
(119.5
)
 
 
 
 
 
 
 
 
 
 
Financing Activities:
 

 
 

 
 

 
 

 
 

Proceeds from long-term debt, net of
    issuance costs
—

 
—

 
296.5

 
—

 
296.5

Repayment of borrowings from long-
    term debt
—

 
—

 
(225.0
)
 
—

 
(225.0
)
Proceeds from borrowings on revolving
    credit agreement
—

 
300.0

 
1,180.0

 
—

 
1,480.0

Repayment of borrowings on revolving
    credit agreement
—

 
(400.0
)
 
(1,188.5
)
 
—

 
(1,588.5
)
Payments of financing fees related to
    revolving credit facility
—

 
(3.8
)
 
—

 
—

 
(3.8
)
Repayment of borrowings from term
     loan
—

 
—

 
(200.0
)
 
—

 
(200.0
)
Contribution from parent
—

 
17.0

 
231.5

 
(248.5
)
 
—

Advances from affiliates, net
2.5

 
104.9

 
62.0

 
(166.9
)
 
2.5

Repayment of contribution received
related to predecessor equity
—

 
(284.8
)
 
—

 
—

 
(284.8
)
Distributions paid
(350.6
)
 
—

 
(639.7
)
 
639.7

 
(350.6
)
Proceeds from sale of common units
556.3

 
—

 
—

 
—

 
556.3

Capital contributions from general
    partner
11.8

 
—

 
—

 
—

 
11.8

Net Cash Provided by (Used in)
    Financing Activities
220.0

 
(266.7
)
 
(483.2
)
 
224.3

 
(305.6
)
 
 
 
 
 
 
 
 
 
 
Decrease in Cash and Cash
    Equivalents
(0.2
)
 
(7.8
)
 
(3.0
)
 
—

 
(11.0
)
Cash and Cash Equivalents at
    Beginning of Period
0.5

 
10.7

 
10.7

 
—

 
21.9

Cash and Cash Equivalents at End of
    Period
$
0.3

 
$
2.9

 
$
7.7

 
$
—

 
$
10.9


39


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 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 proposed project would also include constructing a new large-scale fractionation plant, expanding natural gas liquids storage facilities in Louisiana, constructing a new pipeline connecting these facilities to the converted Texas Gas Loop Line and constructing a new export liquefied petroleum gas (LPG) 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), Moss Lake Fractionation LLC (Moss Lake Fractionation) and Moss Lake LPG Terminal LLC (Moss Lake LPG) to continue to pursue and, if approved, develop, own and construct the pipeline, fractionation and export LPG terminal facilities. Boardwalk Bluegrass currently owns 50% of the equity interests in Bluegrass Pipeline, and Boardwalk Moss Lake currently owns 50% of the equity interests in Moss Lake Fractionation and Moss Lake LPG, 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 $100.0 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 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.

40


We are working with Williams to develop customer support for the pipeline, including the recent announcement of an open season for capacity on the Bluegrass Pipeline.

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

We provide natural gas transportation services to customers that are directly connected to our pipeline system and, through interconnects with third-party pipelines to customers that are not directly connected to our system. Transportation rates that we can charge customers we serve through interconnects with third-party pipelines are heavily influenced by current and anticipated basis differentials. Basis differentials, generally the difference in the price of natural gas at receipt and delivery points across our natural gas pipeline system, 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 shale plays 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 differentials on our pipeline systems have narrowed significantly in recent years, reducing the transportation rates we can typically negotiate with our customers on contracts due for renewal for our firm transportation services.
 
     A substantial portion of our transportation capacity was contracted for under firm transportation agreements having a weighted-average remaining life of approximately 5.6 years as of September 30, 2013. 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 expired in 2013 was greater than in recent years. In light of the market conditions discussed above, natural gas transportation contracts we have renewed or entered into in 2013 and in recent years have been at lower rates, and any remaining available capacity generally has been marketed and sold at lower rates under  short-term firm or interruptible contracts, or in some cases not sold at all. As a result, capacity reservation charges under firm transportation agreements for the nine months ended September 30, 2013, were lower by $33.7 million than they were for the comparable 2012 period. We expect this trend to continue in 2014 while we attempt to renew or replace expiring transportation agreements. The cumulative effect of these circumstances have negatively affected, and are expected to continue to negatively affect, our transportation revenues, EBITDA and distributable cash flows in 2013 and 2014. 

     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 were not as favorable as they were in 2012 and that trend is expected to continue in 2014. 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. 
    
Results of Operations for the Three Months Ended September 30, 2013 and 2012

Our net income attributable to controlling interests for the three months ended September 30, 2013, increased $4.1 million, or 7%, to $62.3 million compared to $58.2 million for the three months ended September 30, 2012. The increase in net income was a result of the items discussed below.


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Operating revenues for the three months ended September 30, 2013, increased $4.9 million, or 2%, to $275.5 million, compared to $270.6 million for the three months ended September 30, 2012. The increase was primarily due to $19.4 million of revenues from the acquisition of Boardwalk Louisiana Midstream, LLC (Louisiana Midstream) on October 1, 2012. The increase in operating revenues was partially offset by lower transportation revenues, excluding fuel, of $13.0 million resulting primarily from lower firm and interruptible revenues due to the market and contract renewal conditions discussed above and reduced utilization. PAL and storage revenues decreased by $2.9 million due to decreased parking opportunities from unfavorable natural gas price spreads between time periods.

Operating costs and expenses for the three months ended September 30, 2013, increased $3.2 million, or 2%, to $172.3 million, compared to $169.1 million for the three months ended September 30, 2012. The increase in operating expenses was driven by the acquisition of Louisiana Midstream, which incurred $12.0 million of operating expenses, and an increase of depreciation expense of $3.6 million due to an increase in our asset base. The increases were partially offset by a $12.5 million gain from the sale of storage gas as a result of a change in the storage gas needed for no-notice services.

Total other deductions for the three months ended September 30, 2013 decreased by $1.7 million, or 4%, to $41.5 million compared to $43.2 million for the 2012 period, driven by lower interest expense due to lower average outstanding long-term debt levels.

Results of Operations for the Nine Months Ended September 30, 2013 and 2012

Our net income attributable to controlling interests for the nine months ended September 30, 2013, increased $18.3 million, or 8%, to $234.2 million compared to $215.9 million for the nine months ended September 30, 2012. The increase in net income was a result of the items discussed below.

Operating revenues for the nine months ended September 30, 2013, increased $33.4 million, or 4%, to $892.7 million, compared to $859.3 million for the nine months ended September 30, 2012. The increase was primarily due to $62.6 million of revenues from Louisiana Midstream and increased revenues from fuel of $12.8 million resulting mainly from higher natural gas prices. The increase in revenues was partially offset by lower transportation revenues, excluding fuel, of $42.7 million resulting primarily from lower firm and interruptible revenues due to the market and contract renewal conditions discussed above and lower utilization.

Operating costs and expenses for the nine months ended September 30, 2013, increased $21.0 million, or 4%, to $536.7 million, compared to $515.7 million for the nine months ended September 30, 2012. The increase in operating expenses was driven by the acquisition of Louisiana Midstream, which incurred $40.8 million of operating expenses, and increased fuel costs of $12.3 million due to higher natural gas prices, partially offset by a $29.5 million gain from the sale of storage gas. The 2012 period was negatively impacted by asset impairment charges of $7.0 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 nine months ended September 30, 2013 decreased by $5.1 million, or 4%, to $122.2 million compared to $127.3 million for the 2012 period, driven by lower interest expense due to increased capitalized interest and lower average outstanding debt levels in 2013.

    
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 cash contribution of $10.0 million in total for an approximate 60% equity ownership interest in each of Boardwalk Bluegrass and Boardwalk Moss Lake. Through September 30, 2013, BPHC has made cash contributions of $37.2 million to Boardwalk Bluegrass

42


and Boardwalk Moss Lake. BPHC has agreed to contribute up to an aggregate $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 us and BPHC.

Capital Expenditures and Investments

Maintenance capital expenditures for the nine months ended September 30, 2013 and 2012 were $36.9 million and $51.3 million. Growth capital expenditures were $177.4 million and $84.2 million for the nine months ended September 30, 2013 and 2012, including our cash 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 $330.0 million in 2013, including approximately $100.0 million for maintenance capital and excluding expenditures made to Boardwalk Bluegrass and Boardwalk Moss Lake.

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.

On October 9, 2013, all of the 22.9 million class B units were converted into common units on a one-for-one basis, pursuant to the terms of the partnership agreement. After the conversion, we had 243.2 million outstanding common units. The class B unit conversion will result in an increase to the November distribution of approximately $6.3 million paid to BPHC.

Revolving Credit Facility

As of September 30, 2013, we had $85.0 million of loans outstanding under our revolving credit facility with a weighted-average interest rate of 1.30% and no letters of credit issued thereunder. At September 30, 2013, we had an available borrowing capacity of $915.0 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 nine months ended September 30, 2013 and 2012, we paid distributions of $392.0 million and $350.6 million to our partners. Note 8 in Part I, Item I of this report contains further discussion regarding our distributions.
    
Our cash distribution policy is consistent with the terms of our partnership agreement which requires us to distribute our "available cash," as defined in our partnership agreement, on a quarterly basis. Our distributions are determined by the board of directors of our general partner based on our financial position, earnings, cash flow and other relevant factors. There is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy may be changed at any time and is subject to certain restrictions or limitations. Refer to Part II, Item 5 of our Annual Report on Form 10-K for the year ended December 31, 2012, for our full distribution policy and risks associated with it.

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Changes in cash flow from operating activities

Net cash provided by operating activities decreased $12.1 million to $402.0 million for the nine months ended September 30, 2013, compared to $414.1 million for the comparable 2012 period primarily due to timing of payables and receivables.

Changes in cash flow from investing activities

Net cash used in investing activities increased $63.2 million to $182.7 million for the nine months ended September 30, 2013, compared to $119.5 million for the comparable 2012 period. The increase was primarily driven by an increase in capital expenditures of $68.8 million and the investment in the Bluegrass Project of $25.6 million. The increase in cash used in investing activities was partially offset by an increase in proceeds received from the sale of assets of $43.0 million primarily from the sale of storage gas in 2013.

Changes in cash flow from financing activities
 
Net cash used in financing activities decreased $107.4 million to $198.2 million for the nine months ended September 30, 2013, compared to $305.6 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 made by BPHC for its interest in Boardwalk Bluegrass and Boardwalk Moss Lake.

Contractual Obligations
 
The following table summarizes significant contractual cash payment obligations under firm commitments as of September 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)
$
3,335.0

 
$
—

 
$
525.0

 
$
1,320.0

 
$
1,490.0

Interest on long-term debt (2)
845.9

 
152.8

 
273.4

 
191.2

 
228.5

Capital commitments (3)
105.9

 
105.9

 
—

 
—

 
—

Capital lease commitments(4)
15.9

 
1.0

 
2.0

 
2.1

 
10.8

Total
$
4,302.7

 
$
259.7

 
$
800.4

 
$
1,513.3

 
$
1,729.3

 
(1)
Includes our senior unsecured notes, having maturity dates from 2015 to 2027, $85.0 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 1.30% weighted-average interest rate and an unused commitment fee of 0.16% as of September 30, 2013, $2.5 million, $5.1 million and $1.5 million would be due in less than one year, 1-3 years and 3-5 years. Based on a 1.93% weighted average interest rate on amounts outstanding under the Term Loan as of September 30, 2013, $4.3 million, $8.7 million and $4.3 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 September 30, 2013.
(4)
Capital lease commitments represent future non-cancelable minimum lease payments under capital lease agreements.

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 contributed $3.0 million to the Texas Gas pension plan and do not expect to fund further amounts during 2013.


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Off-Balance Sheet Arrangements
 
At September 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 costs of maintaining and ensuring the integrity and reliability of our pipeline systems;

•
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 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;

45



•
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.

    
Item 4.  Controls and Procedures
 
Disclosure Controls and Procedures
 
As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Commission. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of September 30, 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 September 30, 2013, that have materially affected or that are reasonably likely to materially affect our internal control over financial reporting. 

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PART II – OTHER INFORMATION

Item 1.  Legal Proceedings

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).
3.9
 
Amendment No. 3 to the Third Amended and Restated Agreement of Limited Partnership of Boardwalk Pipeline Partners, LP, dated as of October 7, 2013 (Incorporated by reference to Exhibit 3.1 to the Registrant's Current report on Form 8-K filed on October 8, 2013).
4.1
 
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).

47


10.2
 
Equity Distribution Agreement, dated August 29, 2013 by and among the Partnership, Boardwalk GP, LP and Boardwalk GP, LLC and Citigroup Global Markets Inc., Barclays Capital Inc., BB&T Capital Markets, a division of BB&T Securities, LLC, Deutsche Bank Securities Inc., Goldman, Sachs & Co., J.P. Morgan Securities LLC, Mitsubishi UFJ Securities (USA), Inc., Mizuho Securities USA Inc., Morgan Stanley & Co. LLC, RBC Capital Markets, LLC, UBS Securities LLC and Wells Fargo Securities, LLC (Incorporated by reference to Exhibit 1.1 to the Registrant’s Current report on Form 8-K filed on August 29, 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


48



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
October 29, 2013
By:
/s/  Jamie L. Buskill
 
 
Jamie L. Buskill
Senior Vice President, Chief Financial and Administrative Officer and Treasurer

49